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F O R M 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003
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
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X]
No [ ]
The Registrant had 130,033,218 common units outstanding at April 30, 2003.
1
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
PART I. FINANCIAL INFORMATION
Item 1: Financial Statements (Unaudited)......................... 3
Consolidated Statements of Income - Three Months Ended 3
March 31, 2003 and 2002................................
Consolidated Balance Sheets - March 31, 2003 and 4
December 31, 2002......................................
Consolidated Statements of Cash Flows - Three Months 5
Ended March 31, 2003 and 2002..........................
Notes to Consolidated Financial Statements............. 6
Item 2: Management's Discussion and Analysis of Financial
Condition and Results of Operations...................... 44
Results of Operations.................................. 44
Financial Condition.................................... 48
Information Regarding Forward-Looking Statements....... 52
Item 3: Quantitative and Qualitative Disclosures About Market
Risk..................................................... 53
Item 4: Controls and Procedures.................................. 53
PART II. OTHER INFORMATION
Item 1: Legal Proceedings........................................ 54
Item 2: Changes in Securities and Use of Proceeds................ 54
Item 3: Defaults Upon Senior Securities.......................... 54
Item 4: Submission of Matters to a Vote of Security Holders...... 54
Item 5: Other Information........................................ 54
Item 6: Exhibits and Reports on Form 8-K......................... 54
Signatures............................................... 56
Certifications........................................... 57
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Unit Amounts)
(Unaudited)
Three Months Ended March 31,
2003 2002
------------- ----------
Revenues
Natural gas sales.................................. $ 1,378,288 $ 469,868
Services........................................... 334,941 295,243
Product sales and other............................ 75,609 37,954
--------- ---------
1,788,838 803,065
--------- ---------
Costs and Expenses
Gas purchases and other costs of sales............. 1,375,414 448,093
Operations and maintenance......................... 93,899 87,291
Fuel and power..................................... 25,138 18,384
Depreciation and amortization...................... 49,805 41,326
General and administrative......................... 34,679 29,532
Taxes, other than income taxes..................... 14,751 12,583
--------- ---------
1,593,686 637,209
--------- ---------
Operating Income..................................... 195,152 165,856
Other Income (Expense)
Earnings from equity investments................... 24,305 23,271
Amortization of excess cost of equity investments.. (1,394) (1,394)
Interest, net...................................... (44,925) (39,022)
Other, net......................................... 277 (50)
Minority Interest.................................... (2,214) (2,827)
--------- ---------
Income Before Income Taxes and Cumulative Effect of .
a Change in Accounting Principle.................. 171,201 145,834
Income Taxes......................................... (4,188) (4,401)
---------- ----------
Income Before Cumulative Effect of a Change in
Accounting Principle.............................. 167,013 141,433
Cumulative effect adjustment from change in accounting
for asset retirement obligations.................. 3,465 -
--------- ---------
Net Income........................................... $ 170,478 $ 141,433
========= =========
Calculation of Limited Partners' interest in Net
Income:
Income Before Cumulative Effect of a Change in
Accounting Principle............................. $ 167,013 $ 141,433
Less: General Partner's interest.................... (76,425) (61,794)
---------- ----------
Limited Partners' interest.......................... 90,588 79,639
Add: Limited Partners' interest in Change in
Accounting Principle............................. 3,430 -
--------- ---------
Limited Partners' interest in Net Income............ $ 94,018 $ 79,639
========= =========
Basic and Diluted Limited Partners' Net Income per
Unit:
Income Before Cumulative Effect of a Change in
Accounting Principle............................. $ 0.50 $ 0.48
Cumulative effect adjustment from change in
accounting for asset retirement obligations...... 0.02 -
---------- ---------
Net Income.......................................... $ 0.52 $ 0.48
========== =========
Weighted average number of units used in computation
of Limited Partners' Net Income per unit:
Basic............................................... 181,377 166,049
========== =========
Diluted............................................. 181,510 166,246
========== =========
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)
March 31, December 31,
2003 2002
----------- --------
ASSETS
Current Assets
Cash and cash equivalents.......................... $ 36,881 $ 41,088
Accounts and notes receivable
Trade............................................ 763,094 457,583
Related parties.................................. 21,664 17,907
Inventories
Products......................................... 3,392 4,722
Materials and supplies........................... 8,965 7,094
Gas imbalances..................................... 51,280 25,488
Gas in underground storage......................... 3,707 11,029
Other current assets............................... 78,820 104,479
---------- ----------
967,803 669,390
---------- ----------
Property, Plant and Equipment, net.................... 6,381,802 6,244,242
Investments........................................... 320,835 311,044
Notes receivable...................................... 2,673 3,823
Goodwill.............................................. 869,840 856,940
Other intangibles, net................................ 17,356 17,324
Deferred charges and other assets..................... 241,925 250,813
---------- ----------
TOTAL ASSETS.......................................... $8,802,234 $8,353,576
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Trade............................................ $ 657,489 $ 373,368
Related parties.................................. 7,946 43,742
Current portion of long-term debt.................. 14,520 -
Accrued interest................................... 20,152 52,500
Deferred revenues.................................. 5,620 4,914
Gas imbalances..................................... 51,870 40,092
Accrued other current liabilities.................. 358,511 298,711
---------- ----------
1,116,108 813,327
---------- ----------
Long-Term Liabilities and Deferred Credits
Long-term debt, outstanding........................ 3,787,234 3,659,533
Market value of interest rate swaps................ 157,665 166,956
---------- ----------
3,944,899 3,826,489
Deferred revenues.................................. 23,143 25,740
Deferred income taxes.............................. 30,262 30,262
Other long-term liabilities and deferred credits... 220,292 199,796
---------- ----------
4,218,596 4,082,287
---------- ----------
Commitments and Contingencies (Note 3)
Minority Interest..................................... 41,976 42,033
---------- ----------
Partners' Capital
Common Units....................................... 1,831,477 1,844,553
Class B Units...................................... 123,068 123,635
i-Units............................................ 1,444,786 1,420,898
General Partner.................................... 74,919 72,100
Accumulated other comprehensive income (loss)...... (48,696) (45,257)
----------- -----------
3,425,554 3,415,929
----------- -----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL............... $8,802,234 $8,353,576
=========== ===========
The accompanying notes are an integral part of
these consolidated financial statements.
4
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Three Months Ended March 31,
-----------------------------
2003 2002
------------ --------
Cash Flows From Operating Activities
Net income..................................... $ 170,478 $141,433
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect adjustment from change in
accounting for asset retirement
obligations.............................. (3,465) --
Depreciation and amortization.............. 49,805 41,326
Amortization of excess cost of equity
investments.............................. 1,394 1,394
Earnings from equity investments........... (24,305) (23,271)
Distributions from equity investments...... 17,872 6,177
Changes in components of working capital... (37,079) 58,998
Other, net................................. (3,456) (3,486)
---------- ---------
Net Cash Provided by Operating Activities...... 171,244 222,571
--------- --------
Cash Flows From Investing Activities
Acquisitions of assets..................... (2,098) (758,340)
Acquisitions of investments................ (3,500) --
Additions to property, plant and equipment
for expansion and maintenance projects.. (145,831) (91,038)
Sale of investments, property, plant and
equipment, net of removal costs......... (823) (274)
Contributions to equity investments........ (9,415) (291)
Other...................................... 3,168 669
--------- --------
Net Cash Used in Investing Activities.......... (158,499) (849,274)
--------- --------
Cash Flows From Financing Activities
Issuance of debt........................... 955,365 1,800,337
Payment of debt............................ (813,365) (1,075,591)
Debt issue costs........................... (287) (60)
Proceeds from issuance of common units..... 780 680
Distributions to partners:
Common units........................... (81,232) (71,424)
Class B units.......................... (3,321) (2,922)
General Partner........................ (73,641) (55,300)
Minority interest...................... (2,236) (2,651)
Other, net................................. 985 98
--------- --------
Net Cash (Used in)/Provided by Financing
Activities..................................... (16,952) 593,167
--------- --------
Decrease in Cash and Cash Equivalents.......... (4,207) (33,536)
Cash and Cash Equivalents, beginning of period. 41,088 62,802
--------- --------
Cash and Cash Equivalents, end of period....... $ 36,881 $ 29,266
========= ========
Noncash Investing and Financing Activities:
Assets acquired by the assumption of
liabilities $ -- $105,597
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, 2002.
Kinder Morgan, Inc. and Kinder Morgan Management, LLC
Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of
Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware
corporation, is the sole stockholder of our general partner, Kinder Morgan
G.P., Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report.
Kinder Morgan Management, LLC, a Delaware limited liability company, was
formed on February 14, 2001. Our general partner owns all of Kinder Morgan
Management, LLC's voting securities and, pursuant to a delegation of control
agreement, our general partner delegated to Kinder Morgan Management, LLC, to
the fullest extent permitted under Delaware law and our partnership agreement,
all of its power and authority to manage and control the business and affairs of
us, our operating limited partnerships and their subsidiaries. Kinder Morgan
Management, LLC cannot take certain specified actions without the approval of
our general partner and its activities are limited to being a limited partner
in, and managing and controlling the business and affairs of, us, our operating
limited partnerships and their subsidiaries. Kinder Morgan Management, LLC is
referred to as "KMR" in this report.
Basis of Presentation
Our consolidated financial statements include our accounts and those of our
majority-owned and controlled subsidiaries and our operating partnerships. All
significant intercompany items have been eliminated in consolidation. Certain
amounts from prior periods have been reclassified to conform to the current
presentation.
Net Income Per Unit
We compute Basic Limited Partners' Net Income per Unit by dividing our limited
partners' interest in net income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the potential dilution, by application of the treasury stock method,
that could occur if options to issue units were exercised, which would result in
the issuance of additional units that would then share in our net income.
Asset Retirement Obligations
As of January 1, 2003, we account for asset retirement obligations pursuant to
Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations." For more information on our asset retirement
obligations, see Note 4.
6
2. Acquisitions and Joint Ventures
During the first three months of 2003, we completed or made adjustments for
the following significant acquisitions. Each of the acquisitions was accounted
for under the purchase method and the assets acquired and liabilities assumed
were recorded at their estimated fair market values as of the acquisition date.
The preliminary amounts assigned to assets and liabilities may be adjusted
during a short period of time following the acquisition. The results of
operations from these acquisitions are included in the consolidated financial
statements from the effective date of acquisition.
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 an
aggregate consideration of approximately $881.5 million, consisting of $727.1
million in cash and the assumption of $154.4 million of liabilities. Tejas Gas,
LLC consists primarily of a 3,400-mile natural gas intrastate pipeline system
that extends from south Texas along the Mexico border and the Texas Gulf Coast
to near the Louisiana border and north from near Houston to east Texas. The
acquisition expanded 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 combination of these
systems is part of our Texas intrastate natural gas pipeline group.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs.............. $ 727,094
Liabilities assumed................................. 154,455
---------
Total purchase price................................ $ 881,549
=========
Allocation of purchase price:
Current assets...................................... $ 56,496
Property, plant and equipment, including cushion gas 674,147
Goodwill ........................................... 150,906
---------
$ 881,549
=========
Our allocation to assets acquired and liabilities assumed was based on an
appraisal of fair market values. The $150.9 million of goodwill was assigned to
our Natural Gas Pipelines business segment and the entire amount is expected to
be deductible for tax purposes.
Bulk Terminals from M.J. Rudolph
Effective January 1, 2003, we acquired long-term lease contracts from New
York-based M.J. Rudolph Corporation to operate four bulk facilities at major
ports along the East Coast and in the southeastern United States. The
acquisition also includes the purchase of certain assets that provide
stevedoring services at these locations. The aggregate cost of the acquisition
was approximately $31.3 million. On December 31, 2002, we paid $29.9 million for
the Rudolph acquisition and this amount was included with Other current assets
on our accompanying balance sheet. In the first quarter of 2003, we paid the
remaining $1.4 million and we allocated our aggregate purchase price to the
appropriate asset and liability accounts. The acquired operations serve various
terminals located at the ports of New York and Baltimore, along the Delaware
River in Camden, New Jersey, and in Tampa Bay, Florida. Combined, these
facilities transload nearly four million tons annually of products such as
fertilizer, iron ore and salt. The acquisition expands our growing Terminals
business segment and complements certain of our existing terminal facilities and
will be included in our Terminals business segment.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
7
Purchase price:
Cash paid, including transaction costs.... $ 31,337
Liabilities assumed....................... 6
--------
Total purchase price...................... $ 31,343
========
Allocation of purchase price:
Current assets............................ $ 84
Property, plant and equipment............. 18,250
Intangibles-agreements ................... 100
Deferred charges and other assets ........ 9
Goodwill ................................. 12,900
--------
$ 31,343
========
The $12.9 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 three months ended March 31, 2003 and 2002, assumes all of
the acquisitions we have made since January 1, 2002, including the ones listed
above, had occurred as of January 1, 2002. 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, 2002 or the results that
will be attained in the future. Amounts presented below are in thousands, except
for the per unit amounts:
Pro Forma
Three Months Ended
March 31,
2003 2002
---- ----
(Unaudited)
Revenues....................................... $1,788,838 $1,051,357
Operating Income............................... 195,152 174,155
Income Before Cumulative Effect of a Change in
Accounting Principle......................... 167,013 149,845
Net Income..................................... 170,478 149,845
Basic and diluted Limited Partners' Net Income
per unit:
Income Before Cumulative Effect of a Change in
Accounting Principle......................... $ 0.50 $ 0.50
Net Income..................................... $ 0.52 $ 0.50
3. Litigation and Other Contingencies
Federal Energy Regulatory Commission Proceedings
SFPP, L.P.
SFPP, L.P., referred to herein as SFPP, is the subsidiary limited partnership
that owns our Pacific operations, excluding CALNEV Pipe Line LLC and related
terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to
certain proceedings at the FERC involving shippers' complaints regarding the
interstate rates, as well as practices and the jurisdictional nature of certain
facilities and services, on our Pacific operations' pipeline systems. Generally,
the interstate rates on our Pacific operations' pipeline systems are
"grandfathered" under the Energy Policy Act of 1992 unless "substantially
changed circumstances" are found to exist. To the extent "substantially changed
circumstances" are found to exist, our Pacific operations may be subject to
substantial exposure under these FERC complaints.
The complainants in the proceedings before the FERC 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." Given the relative newness of the
grandfathering standard under the Energy Policy Act and limited precedent, we
cannot predict how
8
these allegations will be viewed by the FERC.
If "substantially changed circumstances" are found, SFPP rates previously
"grandfathered" under the Energy Policy Act will lose their "grandfathered"
status. If these rates are found to be unjust and unreasonable, shippers may be
entitled to prospective rate reductions and complainants may be entitled to
reparations for periods from the date of their respective complaint to the date
of the implementation of the new rates.
We currently believe that these FERC complaints seek approximately $154
million in tariff reparations and prospective annual tariff reductions, the
aggregate average annual impact of which would be approximately $45 million. We
are not able to predict with certainty the final outcome of the pending FERC
proceedings involving SFPP, should they be carried through to their conclusion,
or whether we can reach a settlement with some or all of the complainants.
However, even if "substantially changed circumstances" are found to exist, we
believe that the resolution of these FERC complaints will be for amounts
substantially less than the amounts sought and that the resolution of such
matters will not have a material adverse effect on our business, financial
position or results of operations.
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.;
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.
9
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 FERC 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.
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.
10
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 Navajo
and El Paso civil litigation, and the provision for regulatory costs in
prospective rates. However, it modified the FERC'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
Diamond Shamrock ("UDS") is not eligible for reparations in the Docket No.
OR92-8 et al. proceedings.
11
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
FERC-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 FERC'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, UDS 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 UDS 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 FERC held that Chevron's eligibility for
reparations should be measured from August 3, 1993, rather than the September
23, 1992 date sought by Chevron. The FERC also clarified its prior ruling with
respect to the "substantial divergence" test, holding that in order to be
considered on the merits, complaints challenging the SFPP rates set by applying
the FERC's indexing regulations to the 1994 cost of service derived under the
Opinion No. 435
12
orders must demonstrate a substantial divergence between the indexed rates and
the pipeline's actual cost of service. Finally, the FERC held that SFPP's 1993
regulatory costs should not be included in the surcharge for the recovery of
supplemental costs.
On November 20, 2001, SFPP submitted its compliance filing and tariffs
implementing Opinion No. 435-B and the FERC's November 7, 2001 Order. Motions to
intervene and protest were subsequently filed by ARCO, Mobil (which now submits
filings under the name ExxonMobil), RHC, Navajo and Chevron, alleging that SFPP:
o should have calculated the supplemental cost surcharge differently;
o did not provide adequate information on the taxpaying status of its
unitholders; and
o failed to estimate potential reparations for ARCO.
On December 7, 2001, Chevron filed a petition for rehearing of the FERC's
November 7, 2001 Order. The petition requested the FERC to specify whether
Chevron would be entitled to reparations for the two year period prior to the
August 3, 1993 filing of its complaint.
On December 10, 2001, SFPP filed a response to those claims. On December 14,
2001, SFPP filed a revised compliance filing and new tariff correcting an error
that had resulted in understating the proper surcharge and tariff rates.
On December 20, 2001, the FERC's Director of the Division of Tariffs and Rates
Central issued two letter orders rejecting SFPP's November 20, 2001 and December
14, 2001 tariff filings because they were not made effective retroactive to
August 1, 2000. On January 11, 2002, SFPP filed a request for rehearing of those
orders by the FERC, on the ground that the FERC has no authority to require
retroactive reductions of rates filed pursuant to its orders in complaint
proceedings.
On January 7, 2002, SFPP and RHC filed petitions for review of the FERC's
November 7, 2001 Order in the U.S. Court of Appeals for the District of Columbia
Circuit. On January 8, 2002, the court consolidated those petitions with the
petitions for review of Opinion Nos. 435, 435-A and 435-B. On January 24, 2002,
the court ordered the consolidated proceedings to be held in abeyance until the
FERC acts on Chevron's request for rehearing of the November 7, 2001 Order.
Motions to intervene and protest the December 14, 2001 corrected submissions
were filed by Navajo, ARCO and ExxonMobil. UDS 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 FERC denied rehearing of the Director of the
Division of Tariffs and Rates Central's letter orders. On February 21, 2002,
SFPP filed a motion requesting that the FERC clarify whether it intended SFPP to
file a retroactive tariff or simply make a compliance filing calculating the
effects of Opinion No. 435-B back to August 1, 2000; in the event the order was
clarified to require a retroactive tariff filing, SFPP asked the FERC to stay
that requirement pending judicial review.
On April 8, 2002, SFPP filed a petition for review of the FERC's February 15,
2002 Order in the U.S. Court of Appeals for the District of Columbia Circuit. BP
West Coast Products, LLC (formerly ARCO), ExxonMobil, and Tosco filed motions to
intervene in that proceeding. A motion to intervene was also filed by Valero
Energy Corporation ("Valero Energy") (which had merged with UDS on December 31,
2001) and Valero Energy's newly acquired shipper subsidiary Ultramar Inc. On
April 9, 2002, the Court of Appeals consolidated SFPP's petition with the
petitions for review of the FERC's prior orders and directed the parties "to
file motions to govern future proceedings" by May 9, 2002. Motions were filed by
SFPP, RHC, Navajo, Chevron and the "Indicated Parties" (BP West Coast Products,
ExxonMobil, Ultramar Inc., UDS and Tosco). The FERC requested that the Court of
Appeals continue to hold the consolidated cases in abeyance pending the
completion of proceedings before the agency on rehearing.
13
On June 25, 2002, the Court of Appeals 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 of Appeals 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.
On September 26, 2002, the FERC issued an order ruling on the protests against
SFPP's November 20, 2001 and December 14, 2001 compliance filings implementing
Opinion No. 435-B and the November 7, 2001 Order. The FERC held that:
o SFPP must measure supplemental costs against the total amount of reparations
for the entire reparations period (as opposed to year-by-year);
o SFPP will not be permitted to include in its supplemental costs (a)
litigation expenses incurred during 1999 and 2000 or (b) payments made to
Navajo and RHC to settle certain FERC litigation;
o the tariff surcharge collected by SFPP for all shipments between August 1,
2000 and December 1, 2001 is subject to refund; and
o in calculating its tax allowance, SFPP must exclude the ownership interest
attributable to an entity that the FERC found to be a mutual fund.
The FERC rejected the requests by Navajo, BP West Coast Products and
ExxonMobil to extend the period for which they are entitled to reparations
beyond the periods specified in prior orders.
The September 26, 2002 Order also ruled on SFPP's request for clarification of
the February 15, 2002 Order as to whether it was required to make a retroactive
tariff filing or rather a compliance filing calculating the effects of Opinion
No. 435-B beginning August 1, 2000. The FERC held that SFPP was required to file
a tariff retroactive to August 1, 2000. The FERC did not rule on SFPP's
alternative request for a stay. The FERC also ruled on Chevron's request for
rehearing of the November 7, 2001 Order, clarifying that Chevron was eligible
for reparations for shipments on the East Line for the two years prior to the
filing of its complaint.
On October 22, 2002, ExxonMobil filed a Request for Clarification or, in the
Alternative, Rehearing of the September 26, 2002 Order. ExxonMobil requested
that the FERC clarify that ExxonMobil was eligible for reparations for East Line
rates.
Following the September 26, 2002 Order, several parties filed motions to
govern future proceedings with the U.S. Court of Appeals for the District of
Columbia Circuit. BP West Coast Products and ExxonMobil (the "Indicated
Parties") and Valero Energy, Ultramar Inc. and Tosco (the "Joint Parties")
requested that the court return the petitions for review to its active docket
but sever the docket involving compliance filing issues. The FERC filed a motion
that did not take a definitive position on whether the petitions for review
should continue to be held in abeyance, but noted that compliance filing issues
were still pending before the FERC. SFPP, Chevron, Navajo and RHC filed
responses to the motions to govern future proceedings. On December 6, 2002, the
Court of Appeals granted the motion of the "Indicated Parties" and "Joint
Parties" to return the petitions for review to the Court's active docket. The
Court also severed the docket relating to compliance filing issues and directed
the parties to submit a proposed briefing schedule and format. On January 6,
2003, SFPP and FERC filed a joint briefing proposal, and the shipper parties
jointly filed a separate briefing proposal.
14
On October 18, 2002, Chevron filed a petition for review of Opinion Nos. 435,
435-A and 435-B in the U.S. Court of Appeals for the District of Columbia
Circuit. The Court of Appeals consolidated that petition with the main docket on
November 20, 2002. Tosco and BP West Coast Products moved to intervene in that
docket, and those motions were granted on December 10, 2002.
Petitions for review of the September 26, 2002 Order were filed in the U.S.
Court of Appeals for the District of Columbia Circuit by Navajo, on October 24,
2002, and by SFPP, on November 8, 2002. The Court consolidated those petitions
with the main docket on November 5, 2002 and November 12, 2002, respectively.
Valero Marketing and Supply Company ("Valero Marketing and Supply") moved to
intervene in both dockets and Tosco moved to intervene in the docket for the
SFPP petition. On January 6, 2003, Valero Marketing and Supply filed a motion to
substitute itself for UDS in the UDS petition for review of Opinion No. 435-B.
On January 21, 2003, SFPP filed a response, stating that it did not object to
the proposed substitution provided Valero Marketing and Supply was not permitted
to create or enlarge any claim for damages. On January 24, 2003, ConocoPhillips
filed a motion to substitute itself for Tosco in the consolidated dockets, and
on January 27, 2003, filed a similar motion in the severed docket relating to
compliance filing issues. On February 4, 2003, the Court of Appeals granted the
ConocoPhillips motion for substitution.
On October 25, 2002, SFPP filed Tariff No. 75 implementing changes required by
the September 26, 2002 Order, and on October 28, 2002, SFPP submitted a
compliance filing pursuant to that order. Valero Marketing and Supply filed a
motion to intervene and protest regarding the compliance filing and tariff, and
Tosco protested the compliance filing. Navajo Refining Company, L.P. moved to
intervene in proceedings relating to the tariff, and Chevron and Equilon
Enterprises LLC filed comments and related pleadings challenging the compliance
filing and seeking additional relief.
On January 29, 2003, the FERC issued an order accepting the October 28,
2002 compliance filing subject to the condition that SFPP recalculate gross
reparations in determining its per barrel surcharge and submit a revised tariff
reflecting that change within fifteen days of the order. The FERC rejected all
other challenges to that compliance filing. On February 13, 2003, SFPP filed its
revised compliance filing along with Tariff No. 81, implementing the provisions
of the January 29, 2003 Order. No party protested that filing. Valero Marketing
and Supply moved to intervene in the sub-docket related to Tariff No. 81 and
Valero Marketing and Supply and Ultramar Inc. moved to intervene in the
sub-docket related to the compliance filing.
On February 24, 2003, the FERC modified the basis on which maximum
allowable oil pipeline rates are adjusted for inflation, from the producer price
index for finished goods minus one percent to the unadjusted producer price
index for finished goods. On February 25, 2003, SFPP filed Tariff No. 82, which
implemented that indexing change with respect to its prospective rates. Tariff
No. 82 was protested by BP West Coast Products, Chevron, ExxonMobil, Valero
Marketing and Supply, and ConocoPhillips Company, in Docket No. IS03-131. On
March 28, 2003, the Commission denied the protests and accepted Tariff No. 82.
On March 7, 2003, SFPP filed a revised compliance filing in Docket No. OR92-8,
which adjusted the refund calculations in SFPP's October 28, 2002 compliance
filing to account for the change in the oil pipeline pricing index as of July 1,
2001. On March 24, 2003, BP West Coast Products protested this revised
compliance filing. On March 27, 2003, Navajo Refining Company, LP filed an
answer to the BP West Coast Products protest in which it also challenged the
adjustment to the refund calculation made in the revised compliance filing. On
April 14, 2003, SFPP made reparation payments of $42.7 million and refund
payments of $1.7 million as ordered by the Commission pursuant to SFPP's March
7, 2003 revised compliance filing.
Petitions for review of the January 29, 2003 Order were filed by
ConocoPhillips on February 6, 2003, SFPP on March 10, 2003 and Chevron on March
27, 2003. SFPP moved to intervene in the ConocoPhillips docket. ExxonMobil and
BP West Coast Products moved to intervene in the SFPP docket.
On March 7, 2003, the United States Court of Appeals for the District of
Columbia Circuit severed from the main docket all dockets relating to petitions
for review of the February 15, 2002, September 26, 2002, and January 29, 2003
Orders. The Court of Appeals ordered those dockets to be held in abeyance
pending resolution of the main docket. The Court of Appeals also issued a
briefing schedule for the main docket, with opening briefs due May 9, 2003 and
final briefs due September 17, 2003. No date for oral argument was set, and the
panel that will hear the
15
case has not yet been announced. The Court also granted the motion of Valero
Marketing and Supply to substitute itself for UDS.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC
---------------------
Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines
(Line Sections 109 and 110) to Watson Station, in the Los Angeles basin,
were subject to FERC's jurisdiction under the Interstate Commerce Act, and,
if so, claimed that the rate for that service was unlawful. Texaco sought to
have its claims addressed in the OR92-8 proceeding discussed above. Several
other West Line shippers filed similar complaints and/or motions to intervene.
The FERC consolidated all of these filings into Docket No. 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. On February 28, 2003, the FERC issued an order upholding that decision.
Because the FERC found that SFPP did not have market power over two of the three
major customers at the Sepulveda origin market and because the third customer is
now an affiliate of SFPP, SFPP filed a request for rehearing of that order on
March 31, 2003, which 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. As part
of its February 28, 2003 order denying SFPP's application for market-based
ratemaking authority, the FERC remanded the proceeding to the ongoing litigation
in Docket No. OR96-2, et al. for a determination of whether SFPP's current rate
for service on the Sepulveda line is just and reasonable.
OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar filed a
----------------------------------
complaint at FERC (Docket No. OR97-2) challenging SFPP's West Line rates,
claiming they were unjust and unreasonable and no longer subject to
grandfathering. In October 1997, ARCO, Mobil and Texaco filed a complaint at the
FERC (Docket No. OR98-1) challenging the justness and reasonableness of all of
SFPP's interstate rates, raising claims against SFPP's East and West Line rates
similar to those that have been at issue in Docket Nos. OR92-8, et al. discussed
above, 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.
16
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, the 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
second quarter of 2003.
OR02-4 proceedings.
------------------
On February 11, 2002, Chevron, an intervenor in the OR96-2 proceeding, filed
a complaint against SFPP in Docket No. OR02-4 along with a motion to consolidate
the complaint with the OR96-2 proceeding. On May 21, 2002, the FERC dismissed
Chevron's complaint and motion to consolidate. Chevron filed a request for
rehearing and on September 25, 2002, the FERC dismissed Chevron's rehearing
request. In October 2002, Chevron filed a request for rehearing of the FERC's
September 25, 2002 Order. On April 4, 2003, Chevron filed a motion for expedited
consideration of its rehearing request. Its rehearing request remains pending.
Chevron continues to participate in the OR96-2 proceeding as an intervenor.
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 sought prospective rate reductions aggregating
approximately $10 million per year.
On March 16, 2000, SFPP filed an application with the CPUC seeking authority
to justify its rates for intrastate transportation of refined petroleum products
on competitive, market-based conditions rather than on traditional,
cost-of-service analysis.
On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC
asserting that SFPP's California intrastate rates are not just and reasonable
based on a 1998 test year and requesting the CPUC to reduce SFPP's rates
prospectively. The amount of the reduction in SFPP rates sought by the
complainants is not discernible from the complaint.
The rehearing complaint was heard by the CPUC in October 2000 and the April
2000 complaint and SFPP's market-based application were heard by the CPUC in
February 2001. All three matters stand submitted as of April 13, 2001, and a
decision addressing the submitted matters is expected within three to four
months.
The CPUC has recently issued a resolution approving a 2001 request by SFPP to
raise its California rates to reflect increased power costs. The resolution
approving the requested rate increase also requires SFPP to submit cost data for
2001, 2002, and 2003 to assist the CPUC in determining whether SFPP's overall
rates for California intrastate transportation services are reasonable. The
resolution reserves the right to require refunds, from the date of issuance of
the resolution, to the extent the CPUC's analysis of cost data to be submitted
by SFPP demonstrates that SFPP's California jurisdictional rates are
unreasonable in any fashion. On February 21, 2003, SFPP submitted the cost data
required by the CPUC, which submittal was protested by Valero Marketing and
Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil
Corporation, and Chevron Products Company. Issues raised by the protest,
including the reasonableness of SFPP's existing intrastate transportation rates,
will be the subject of evidentiary hearings and are expected to be resolved by
the CPUC by the first quarter of 2004.
17
We currently believe the CPUC complaints seek approximately $15 million in
tariff reparations and prospective annual tariff reductions, the aggregate
average annual impact of which would be approximately $31 million. There is no
way to quantify the potential extent to which the CPUC could determine that
SFPP's existing California rates are unreasonable or estimate the amount of
dollars potentially subject to refund as a consequence of the CPUC resolution
requiring the provision by SFPP of cost-of-service data. SFPP believes that
submission of the required, representative cost data required by the CPUC will
indicate that SFPP's existing rates for California intrastate services remain
reasonable and that no refunds are justified.
We believe that the resolution of such matters will not have a material
adverse effect on our business, financial position or results of operations.
Trailblazer Pipeline Company
As required by its last rate case settlement, Trailblazer Pipeline Company
made a general rate case filing at the FERC on November 29, 2002. The filing
provides for a small rate decrease and also includes a number of non-rate tariff
changes. By an order issued December 31, 2002, FERC effectively bifurcated the
proceeding. The rate change was accepted to be effective on January 1, 2003,
subject to refund and a hearing. Most of the non-rate tariff changes were
suspended until June 1, 2003, subject to refund and a technical conference
procedure.
Trailblazer sought rehearing of the FERC order with respect to the refund
condition on the rate decrease. On April 15, 2003, the FERC granted
Trailblazer's rehearing request to remove the refund condition that had been
imposed in the December 31, 2002 Order. The Intervenors have sought rehearing as
to the FERC's acceptance of certain non-rate tariff provisions. A prehearing
conference on the rate issues was held on January 16, 2003. A procedural
schedule was established under which the hearing will commence on October 8,
2003, if the case is not settled. Discovery has commenced as to rate issues.
The technical conference on non-rate issues was held on February 6, 2003.
Those issues include:
o capacity award procedures;
o credit procedures;
o imbalance penalties; and
o the maximum length of bid terms considered for evaluation in the right of
first refusal process.
Comments on these issues as discussed at the technical conference were filed
by parties in March 2003. An order on the technical conference issues is
expected sometime during the second quarter of 2003.
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 the 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 the FERC. From October 2000 through June 2001,
KMIGT held a series of technical and phone conferences to identify issues,
obtain input, and modify its Order 637 compliance plan, based on comments
received from FERC staff and other interested parties and shippers. On June 19,
2001, KMIGT received a letter from the FERC encouraging it to file revised
pro-forma tariff sheets, which reflected the latest discussions and input from
parties into its Order 637 compliance plan. KMIGT made such a revised Order 637
compliance filing on July 13, 2001. The July 13, 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 the 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
18
into effect until further order of the FERC. KMIGT filed its compliance filing
with the October 19, 2001 Order on November 19, 2001 and also filed a request
for rehearing/clarification of the FERC's October 19, 2001 Order on November 19,
2001. Several parties protested the November 19, 2001 compliance filing. KMIGT
filed responses to those protests on December 14, 2001. At this time, it is
unknown when this proceeding will be finally resolved. The full impact of
implementation of Order 637 on the KMIGT system is under evaluation. We believe
that these matters will not have a material adverse effect on our business,
financial position or results of operations.
Separately, numerous petitioners, including KMIGT, have filed appeals of Order
637 in the D.C. Circuit, potentially raising a wide array of issues related to
Order 637 compliance. Initial briefs were filed on April 6, 2001, addressing
issues contested by industry participants. Oral arguments on the appeals were
held before the court in December 2001. On April 5, 2002, the D.C. Circuit
issued an order largely affirming Order Nos. 637, et seq. The D.C. Circuit
remanded the FERC's decision to impose a 5-year cap on bids that an existing
shipper would have to match in the right of first refusal process. The D.C.
Circuit also remanded the FERC's decision to allow forward-hauls and backhauls
to the same point. Finally, the D.C. Circuit held that several aspects of the
FERC's segmentation policy and its policy on discounting at alternate points
were not ripe for review. The FERC requested comments from the industry with
respect to the issues remanded by the D.C. Circuit. They were due July 30, 2002.
On October 31, 2002, the FERC issued an order in response to the D.C.
Circuit's remand of certain Order 637 issues. The order:
o eliminated the requirement of a 5-year cap on bid terms that an existing
shipper would have to match in the right of first refusal process, and found
that no term matching cap is necessary given existing regulatory controls;
o affirmed FERC's policy that a segmented transaction consisting of both a
forwardhaul up to contract demand and a backhaul up to contract demand to
the same point is permissible; and
o accordingly required, under Section 5 of the Natural Gas Act, pipelines that
the FERC had previously found must permit segmentation on their systems to
file tariff revisions within 30 days to permit such segmented forwardhaul
and backhaul transactions to the same point.
On December 23, 2002, KMIGT filed revised tariff provisions (in a separate
docket) in compliance with the October 31, 2002 Order concerning the elimination
of the right of first refusal five-year term matching cap. In an order issued
January 22, 2003, the FERC approved such revised tariff provisions to be
effective January 23, 2003.
Trailblazer Pipeline Company
On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with
the 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, the FERC issued its order on Trailblazer's Order No. 637
compliance filing. The FERC approved Trailblazer's proposed language regarding
operational flow orders and the right of first refusal, but
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required Trailblazer to make changes to its tariff related to the other issues
listed above.
On November 14, 2001, Trailblazer made its compliance filing pursuant to the
FERC order of October 15, 2001 and also filed for rehearing of the October 15,
2001 order. On April 16, 2003, the FERC issued its order on Trailblazer's
compliance filing and rehearing order. The FERC denied Trailblazer's requests
for rehearing and approved the compliance filing subject to modifications that
must be made within 30 days of the order.
Trailblazer anticipates no adverse impact on its business as a result of
the implementation of Order No. 637.
Standards of Conduct Rulemaking
On September 27, 2001, the 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, the FERC held a technical conference dealing with the FERC's
proposed changes in the Standard of Conduct Rulemaking. On June 28, 2002, KMIGT
and numerous other parties filed additional written comments under a procedure
adopted at the technical conference. The Proposed Rulemaking is awaiting further
FERC action. We believe that these matters, as finally adopted, will not have a
material adverse effect on our business, financial position or results of
operations.
The FERC also issued a Notice of Proposed Rulemaking in Docket No. RM02-14-000
in which it proposed new regulations for cash management practices, including
establishing limits on the amount of funds that can be swept from a regulated
subsidiary to a non-regulated parent company. Kinder Morgan Interstate Gas
Transmission LLC filed comments on August 28, 2002. We believe that these
matters, as finally adopted, will not have a material adverse effect on our
business, financial position or results of operations.
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. The trial
of this matter ended in early March 2003 and we expect the judge's ruling
sometime in the second quarter of 2003.
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, has been
named as a defendant with several others in a series of lawsuits in the United
States District Court in Denver, Colorado and certain state courts in Colorado
and Texas. The plaintiffs include several private royalty, overriding royalty
and working interest owners at the McElmo Dome (Leadville) Unit in southwestern
Colorado. Plaintiffs in the Colorado state court action also are overriding
royalty interest owners in the Doe Canyon Unit. Plaintiffs seek to also
represent classes of claimants composed of all private and governmental royalty,
overriding royalty and working interest owners, and governmental taxing
authorities who have an interest in the carbon dioxide produced at the McElmo
Dome Unit. Plaintiffs claim they and the members of any classes that might be
certified have been damaged because the defendants have maintained a low price
for carbon dioxide in the enhanced oil recovery market in the Permian Basin and
maintained a high cost of pipeline
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transportation from the McElmo Dome Unit to the Permian Basin. Plaintiffs claim
breaches of contractual and potential fiduciary duties owed by defendants and
also allege other theories of liability including:
o common law fraud;
o fraudulent concealment; and
o negligent misrepresentation.
In addition to actual or compensatory damages, certain plaintiffs are
seeking punitive or trebled damages as well as declaratory judgment for
various forms of relief, including the imposition of a constructive trust
over the defendants' interests in the Cortez Pipeline and the Partnership.
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); Shell Western E&P Inc. v. Bailey, et al., No 98-28630 (215th
Dist. Ct. Harris County, Tex. filed 6/17/98); Shores, et al. v. Mobil Oil
Corporation, et al., No. GC-99-01184 (Texas Probate Court, Denton County
filed 12/22/99); First State Bank of Denton v. Mobil Oil Corporation, et al.,
No. PR-8552-01 (Texas Probate Court, Denton County filed 3/29/01); and
Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist.
Ct. Montezuma County filed 3/21/98).
At a hearing conducted in the United States District Court for the District of
Colorado on April 8, 2002, the Court orally announced that it had approved the
certification of proposed plaintiff classes and approved a proposed settlement
in the CO2 Claims Coalition, LLC, Rutter & Wilbanks, Watson, and Ainsworth
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. On December 26, 2002, the 10th
Circuit Court of Appeals affirmed in all respects the District Court's Order
approving settlement. Following the decision of the 10th Circuit, the plaintiffs
and defendants jointly filed motions to abate the Shell Western E&P Inc., Shores
and First State Bank of Denton cases in order to afford the parties time to
discuss potential settlement of those matters. These Motions were granted on
February 6, 2003. In the Celeste C. Grynberg case, the parties are currently
engaged in discovery. On March 24, 2003, the plaintiffs' counsel in the Shores
matter filed a Petition for Writ of Certiorari in the United States Supreme
Court seeking to have the Court review and overturn the decision of the 10th
Circuit Court of Appeals.
RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et
al.
Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District. On October 15, 2001, Kinder Morgan Energy Partners, L.P. was
served with the First Supplemental Petition filed by RSM Production
Corporation on behalf of the County of Zapata, State of Texas and Zapata
County Independent School District as plaintiffs. Kinder Morgan Energy
Partners, L.P. was sued in addition to 15 other defendants, including two other
Kinder Morgan affiliates. Certain entities we acquired in the Kinder Morgan
Tejas acquisition are also defendants in this matter. The Petition alleges that
these taxing units relied on the reported volume and analyzed heating content of
natural gas produced from the wells located within the appropriate taxing
jurisdiction in order to properly assess the value of mineral interests in
place. The suit further alleges that the defendants undermeasured the volume and
heating content of that natural gas produced from privately owned wells in
Zapata County, Texas. The Petition further alleges that the County and School
District were deprived of ad valorem tax revenues as a result of the alleged
undermeasurement of the natural gas by the defendants. On December 15, 2001, the
defendants filed motions to transfer venue on jurisdictional grounds. There are
no further pretrial proceedings at this time.
Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating
Company et al. v. Gas Pipelines, et al.)
Stevens County, Kansas District Court, Case No. 99 C 30. In May, 1999, three
plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto, filed a
purported nationwide class action in the Stevens County, Kansas District Court
against some 250 natural gas pipelines and many of their affiliates. The
District Court is located in Hugoton, Kansas. Certain entities we acquired in
the Kinder Morgan Tejas acquisition are also defendants in this matter. The
Petition (recently amended) alleges a conspiracy to underpay royalties, taxes
and producer payments by the defendants' undermeasurement of the volume and
heating content of natural gas produced from nonfederal lands
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for more than twenty-five years. The named plaintiffs purport to adequately
represent the interests of unnamed plaintiffs in this action who are comprised
of the nation's gas producers, State taxing agencies and royalty, working and
overriding owners. The plaintiffs seek compensatory damages, along with
statutory penalties, treble damages, interest, costs and fees from the
defendants, jointly and severally. This action was originally filed on May 28,
1999 in Kansas State Court in Stevens County, Kansas as a class action against
approximately 245 pipeline companies and their affiliates, including certain
Kinder Morgan entities. Subsequently, one of the defendants removed the action
to Kansas Federal District Court and the case was styled as Quinque Operating
Company, et al. v. Gas Pipelines, et al., Case No. 99-1390-CM, United States
District Court for the District of Kansas. Thereafter, we filed a motion with
the Judicial Panel for Multidistrict Litigation to consolidate this action for
pretrial purposes with the Grynberg False Claim Act cases referred to below,
because of common factual questions. On April 10, 2000, the MDL Panel ordered
that this case be consolidated with the Grynberg federal False Claims Act cases
discussed below. On January 12, 2001, the Federal District Court of Wyoming
issued an oral ruling remanding the case back to the State Court in Stevens
County, Kansas. The Court in Kansas has issued a case management order
addressing the initial phasing of the case. In this initial phase, the court
will rule on motions to dismiss (jurisdiction and sufficiency of pleadings), and
if the action is not dismissed, on class certification. Merits discovery has
been stayed. Recently, the defendants filed a motion to dismiss on grounds other
than personal jurisdiction, which was denied by the Court in August, 2002. The
Motion to Dismiss for lack of Personal Jurisdiction of the nonresident
defendants has been briefed and is pending. 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.
On April 10, 2003, the court issued its decision denying plaintiffs' motion for
class certification. Plaintiffs have indicated they will move the Court for
permission to amend the Complaint.
United States of America, ex rel., Jack J. Grynberg v. K N Energy
Civil Action No. 97-D-1233, filed in the U.S. District Court, District of
Colorado. This action was filed on June 9, 1997 pursuant to the federal False
Claim Act and involves allegations of mismeasurement of natural gas produced
from federal and Indian lands. The Department of Justice has decided not to
intervene in support of the action. The complaint is part of a larger series of
similar complaints filed by Mr. Grynberg against 77 natural gas pipelines
(approximately 330 other defendants). Certain entities we acquired in the Kinder
Morgan Tejas acquisition are also defendants in this matter. An earlier single
action making substantially similar allegations against the pipeline industry
was dismissed by Judge Hogan of the U.S. District Court for the District of
Columbia on grounds of improper joinder and lack of jurisdiction. As a result,
Mr. Grynberg filed individual complaints in various courts throughout the
country. In 1999, these cases were consolidated by the Judicial Panel for
Multidistrict Litigation, and transferred to the District of Wyoming. The
multidistrict litigation matter is called In Re Natural Gas Royalties Qui Tam
Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument
on the motion to dismiss occurred on March 17, 2000. On July 20, 2000, the
United States of America filed a motion to dismiss those claims by Grynberg that
deal with the manner in which defendants valued gas produced from federal
leases, referred to as valuation claims. Judge Downes denied the defendant's
motion to dismiss on May 18, 2001. The United States' motion to dismiss most of
plaintiff's valuation claims has been granted by the court. Grynberg has
appealed that dismissal to the 10th Circuit, which has requested briefing
regarding its jurisdiction over that appeal. Discovery is now underway to
determine issues related to the Court's subject matter jurisdiction arising out
of the False Claim Act.
Mel R. Sweatman and Paz Gas Corporation v. 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 to receive under an agreement with a
subsidiary of ours acquired in the Tejas Gas acquisition. We have filed a motion
to remove the case from venue in Dewitt County, Texas to Harris County, Texas,
and our motion was denied in a venue hearing in November 2002.
22
In a Second Amended Original Petition, Sweatman and Paz assert new and
distinct allegations against us, principally that we were a party to an alleged
commercial bribery committed by us, Gulf Energy Marketing, and Intergen inasmuch
as we, in our role as acquirer of Kinder Morgan Tejas, allegedly paid Intergen
to not renew the underlying Entex contracts belonging to the Tejas/Paz joint
venture. Moreover, new and distinct allegations of breach of fiduciary and
bribery of a fiduciary are also raised in this amended petition for the first
time.
Based on the information available to date and our preliminary investigation,
we believe this suit is without merit and we intend to defend it vigorously.
Maher et ux. v. Centerpoint Energy, Inc. d/b/a Reliant Energy,
Incorporated, Reliant Energy Resources Corp., Entex Gas Marketing Company,
Kinder Morgan Texas Pipeline, L.P., Kinder Morgan Energy Partners, L.P.,
Houston Pipeline Company, L.P. and AEP Gas Marketing, L.L.C., No. 30875
(District Court, Wharton County Texas).
On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan
Energy Partners, L.P. were served with the above-entitled Complaint. A First
Amended Complaint was served on October 23, 2002, adding additional
defendants Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc.,
Kinder Morgan Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. The
First Amended Complaint purports to bring a class action on behalf of those
Texas residents who purchased natural gas for residential purposes from the
so-called "Reliant Defendants" in Texas at any time during the period
encompassing "at least the last ten years."
The Complaint alleges that Reliant Energy Resources Corp., by and through its
affiliates, has artificially inflated the price charged to residential consumers
for natural gas that it allegedly purchased from the non-Reliant defendants,
including the above-listed Kinder Morgan entities. The Complaint further alleges
that in exchange for Reliant Energy Resources Corp.'s purchase of natural gas at
above market prices, the non-Reliant defendants, including the above-listed
Kinder Morgan entities, sell natural gas to Entex Gas Marketing Company at
prices substantially below market, which in turn sells such natural gas to
commercial and industrial consumers and gas marketers at market price. The
Complaint purports to assert claims for fraud, violations of the Texas Deceptive
Trade Practices Act, and violations of the Texas Utility Code against some or
all of the Defendants, and civil conspiracy against all of the defendants, and
seeks relief in the form of, inter alia, actual, exemplary and statutory
damages, civil penalties, interest, attorneys' fees and a constructive trust ab
initio on any and all sums which allegedly represent overcharges by Reliant and
Reliant Energy Resources Corp.
On November 18, 2002, the Kinder Morgan defendants filed a Motion to Transfer
Venue and, Subject Thereto, Original Answer to the First Amended Complaint. The
parties are currently engaged in preliminary discovery. Based on the information
available to date and our preliminary investigation, the Kinder Morgan
defendants believe that the claims against them are without merit and intend to
defend against them vigorously.
Marie Snyder, et al v. City of Fallon, United States Department of the
Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas
Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District
Court, District of Nevada)("Snyder"); and Frankie Sue Galaz, et al v. United
States of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy
Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No.
cv-N-02-0630-DWH-RAM (United States District Court, District of
Nevada)("Galaz").
On July 9, 2002, we were served with a purported Complaint for Class Action in
the Snyder case, in which the plaintiffs, on behalf of themselves and others
similarly situated, assert that a leukemia cluster has developed in the City of
Fallon, Nevada. The Complaint alleges that the plaintiffs have been exposed to
unspecified "environmental carcinogens" at unspecified times in an unspecified
manner and are therefore "suffering a significantly increased fear of serious
disease." The plaintiffs seek a certification of a class of all persons in
Nevada who have lived for at least three months of their first ten years of life
in the City of Fallon between the years 1992 and the present who have not been
diagnosed with leukemia.
The Complaint purports to assert causes of action for nuisance and "knowing
concealment, suppression, or omission of material facts" against all defendants,
and seeks relief in the form of "a court-supervised trust fund, paid for by
defendants, jointly and severally, to finance a medical monitoring program to
deliver services to members of the purported class that include, but are not
limited to, testing, preventative screening and surveillance for conditions
23
resulting from, or which can potentially result from exposure to environmental
carcinogens," incidental damages, and attorneys' fees and costs.
The defendants responded to the Complaint by filing Motions to Dismiss on the
grounds that it fails to state a claim upon which relief can be granted. On
November 7, 2002, the United States District Court granted the Motion to Dismiss
filed by the United States, and further dismissed all claims against the
remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs
filed a Motion for Reconsideration and Leave to Amend, which was denied by the
Court on December 30, 2002. Plaintiffs have filed a Notice of Appeal to the
United States Court of Appeals for the 9th Circuit, which appeal is currently
pending.
On December 3, 2002, plaintiffs filed an additional Complaint for Class Action
in the Galaz matter asserting the same claims in the same Court on behalf of the
same purported class against virtually the same defendants, including us. On
February 10, 2003, the defendants filed Motions to Dismiss the Galaz Complaint
on the grounds that it also fails to state a claim upon which relief can be
granted. This motion to dismiss was granted as to all defendants on April 3,
2003.
Based on the information available to date and our preliminary investigation,
we believe that the claims against us in the Snyder and Galaz matters are
without merit and intend to defend against them vigorously.
Walter Chandler v. Plantation Pipe Line Company
On October 2, 2001, the jury rendered a verdict against Plantation Pipe Line
Company 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.
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 below, a current remediation effort is
taking place among Chevron, Plantation and Alabama Department of Environmental
Management.
In addition to the Chandler case, in 1998 and 1999, other entities and
individuals living in close proximity to the Chandlers filed lawsuits against
Plantation, Chevron and an environmental consulting firm, CH2MHill, alleging
property damage and personal injuries from groundwater contaminated with
petroleum hydrocarbons. In February 2003, Plantation settled, through a
confidential settlement, all of these lawsuits as well as the Chandler
litigation. Plantation believes that the settlement of these lawsuits and the
Chandler litigation will not have a material adverse effect on its business,
financial position or results of operations.
Marion County, Mississippi Litigation
In 1968, Plantation discovered a release from its 12-inch pipeline in Marion
County, Mississippi. The pipeline was immediately repaired. In 1998 and 1999, 62
lawsuits were filed on behalf of 263 plaintiffs in the Circuit Court of Marion
County, Mississippi. The majority of the claims are based on alleged exposure
from the 1968 release, including claims for property damage and personal injury.
Plantation has resolved some of the lawsuits but lawsuits by 236 of the
plaintiffs are still pending. Although a trial date has not been set for any of
the remaining cases, it is anticipated that a trial on a portion of the lawsuits
will be scheduled in 2003. Plantation believes that the ultimate resolution of
these Marion County, Mississippi cases will not have a material effect on its
business, financial position or results of operations.
24
Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids
Terminals, Inc. and ST Services, Inc.
On April 23, 2003, Exxon Mobil Corporation filed the Complaint in the Superior
Court of New Jersey, Gloucester County. Our answer to the Complaint is due June
27, 2003. The lawsuit relates to environmental remediation obligations at a
Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s
through November 1989, by GATX Terminals Corp. from 1989 through September 2000,
and owned currently by ST Services, Inc. Prior to selling the terminal to GATX
Terminals, ExxonMobil performed an environmental site assessment of the terminal
required prior to sale pursuant to state law. During the site assessment,
ExxonMobil discovered items that required remediation and the New Jersey
Department of Environmental Protection issued an order that required ExxonMobil
to perform various remediation activities to remove hydrocarbon contamination at
the terminal. ExxonMobil, we understand, is still remediating the site and has
not been removed from the state's cleanup order; however, ExxonMobil claims that
the remediation continues because of GATX Terminals' storage of a fuel additive,
MTBE, at the terminal during GATX Terminals' ownership of the terminal. When
GATX Terminals sold the terminal to ST Services, the parties indemnified one
another for certain environmental matters. When GATX Terminals was sold to us,
GATX Terminals' indemnification obligations to ST Services may have passed to
us, consequently, at issue is any indemnification obligations we may owe to ST
Services in respect to environmental remediation of MTBE at the terminal. The
Complaint seeks any and all damages related to remediating MTBE at the terminal,
and, according to the New Jersey Spill Compensation and Control Act, treble
damages may be available for actual dollars incorrectly spent by the successful
party in the lawsuit for remediating MTBE at the terminal.
Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party
in interest for Enron Helium Company, a division of Enron Corp., Enron
Liquids Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership,
Kinder Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252
(189th Judicial District Court, Harris County, Texas)
On September 1, 2000, Plaintiff Exxon Mobil Corporation filed its Original
Petition and Application for Declaratory Relief against Kinder Morgan
Operating L.P. "A," Enron Liquids Pipeline Operating Limited Partnership
n/k/a Kinder Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a
Kinder Morgan G.P., Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton
Processing, Inc., and Enron Helium Company. Plaintiff added Enron Corp. as
party in interest for Enron Helium Company in its First Amended Petition and
added Kinder Morgan, Inc. as a Defendant. The claims against Enron Corp.
were severed into a separate cause of action. Plaintiff's claims are based
on a Gas Processing Agreement entered into on September 23, 1987 between
Mobil Oil Corp. and Enron Gas Processing Company relating to gas produced in
the Hugoton Field in Kansas and processed at the Bushton Plant, a natural gas
processing facility located in Kansas. Plaintiff also asserts claims
relating to the Helium Extraction Agreement entered between Enron Helium
Company (a division of Enron Corp.) and Mobil Oil Corporation dated March 14,
1988. Plaintiff alleges that Defendants failed to deliver propane and to
allocate plant products to Plaintiff as required by the Gas Processing
Agreement and originally sought damages of approximately $5.9 million.
Plaintiff filed its Third Amended Petition on February 25, 2003. In its Third
Amended Petition, Plaintiff alleges claims for breach of the Gas Processing
Agreement and the Helium Extraction Agreement, requests a declaratory judgment
and asserts claims for fraud by silence/bad faith, fraudulent inducement of the
1997 Amendment to the Gas Processing Agreement, civil conspiracy, fraud, breach
of a duty of good faith and fair dealing, negligent misrepresentation and
conversion. As of April 7, 2003, Plaintiff alleged damages for the period
November 1987 through March 1997 in the amount of $30.7 million. On May 2, 2003,
Plaintiff added claims for the period April 1997 through February 2003 in the
amount of $12.9 million. The parties are currently engaged in discovery. Based
on the information available to date in our investigation, the Kinder Morgan
Defendants believe that the claims against them are without merit and intend to
defend against them vigorously.
Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions, that, to the extent an assessment of the
matter is possible, we have established an adequate reserve to cover potential
liability, and that these matters will not have a material adverse effect on our
business, financial position or results of operations.
25
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,
terminal and carbon dioxide field and oil field 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 and have
established a reserve to address the costs associated with the cleanup:
o one cleanup ordered by the United States Environmental Protection Agency
related to ground water contamination in the vicinity of SFPP's storage
facilities and truck loading terminal at Sparks, Nevada;
o several ground water hydrocarbon remediation efforts under administrative
orders issued by the California Regional Water Quality Control Board and two
other state agencies;
o groundwater and soil remediation efforts under administrative orders issued
by various regulatory agencies on those assets purchased from GATX
Corporation, comprising Kinder Morgan Liquids Terminals LLC, CALNEV Pipe
Line LLC and Central Florida Pipeline LLC; and
o a ground water remediation effort taking place between Chevron, Plantation
Pipe Line Company and the Alabama Department of Environmental Management.
In addition, we are from time to time involved in civil proceedings relating
to damages alleged to have occurred as a result of accidental leaks or spills of
refined petroleum products, natural gas liquids, natural gas and carbon dioxide.
Furthermore, our review of assets related to Kinder Morgan Interstate Gas
Transmission LLC indicates possible environmental impacts from petroleum and
used oil releases into the soil and groundwater at nine sites. Additionally, our
review of assets related to Kinder Morgan Texas Pipeline indicates possible
environmental impacts from petroleum releases into the soil and groundwater at
six sites. Further delineation and remediation of any environmental impacts from
these matters will be conducted. Reserves have been established to address the
closure of these issues.
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. As
of March 31, 2003, we have recorded a total reserve for environmental claims
in the amount of $46.6 million. However, 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 to the matters described above, we may face additional challenges
to our rates in the future. Shippers on our pipelines do have rights to
challenge the rates we charge under certain circumstances prescribed by
applicable regulations. There can be no assurance that we will not face
challenges to the rates we receive for services on our pipeline systems in the
future. In addition, since many of our assets are subject to regulation, we are
26
subject to potential future changes in applicable rules and regulations that may
have an adverse effect on our business, financial position or results of
operations.
4. Change in Accounting for Asset Retirement Obligations
In August 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 provides accounting and reporting guidance for legal
obligations associated with the retirement of long-lived assets that result from
the acquisition, construction or normal operation of a long-lived asset. The
provisions of this Statement are effective for fiscal years beginning after June
15, 2002. We adopted SFAS No. 143 on January 1, 2003.
SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. Its primary impact on
us will be to change the method of accruing for oil production site restoration
costs related to our CO2 Pipelines business segment. Prior to January 1, 2003,
we accounted for asset retirement obligations in accordance with SFAS No. 19,
"Financial Accounting and Reporting by Oil and Gas Producing Companies." Under
SFAS No. 143, the fair value of asset retirement obligations are recorded as
liabilities on a discounted basis when they are incurred, which is typically at
the time the assets are installed or acquired. Amounts recorded for the related
assets are increased by the amount of these obligations. Over time, the
liabilities will be accreted for the change in their present value and the
initial capitalized costs will be depreciated over the useful lives of the
related assets. The liabilities are eventually extinguished when the asset is
taken out of service. Specifically, upon adoption of this Statement, an entity
must recognize the following items in its balance sheet:
o a liability for any existing asset retirement obligations adjusted for
cumulative accretion to the date of adoption;
o an asset retirement cost capitalized as an increase to the carrying
amount of the associated long-lived asset; and
o accumulated depreciation on that capitalized cost.
Amounts resulting from initial application of this Statement shall be measured
using current information, current assumptions and current interest rates. The
amount recognized as an asset retirement cost shall be measured as of the date
the asset retirement obligation was incurred. Cumulative accretion and
accumulated depreciation shall be measured for the time period from the date the
liability would have been recognized had the provisions of this Statement been
in effect to the date of adoption of this Statement.
The cumulative-effect adjustment for this change in accounting principle
resulted in income of $3.5 million in the first quarter of 2003. Furthermore, as
required by SFAS No. 143, we recognized the cumulative-effect of initially
applying SFAS No. 143 as a change in accounting principle as described in
Accounting Principles Board Opinion 20, "Accounting Changes." The
cumulative-effect adjustment results from the difference between the amounts
recognized in our consolidated balance sheet prior to the application of SFAS
No. 143 and the net amount recognized in our consolidated balance sheet pursuant
to SFAS No. 143.
In our CO2 Pipelines business segment, we are required to plug and abandon oil
wells that have been removed from service and to remove our surface wellhead
equipment and compressors. As of March 31, 2003, we have recognized asset
retirement obligations in the aggregate amount of $11.3 million relating to
these requirements at two existing sites within our CO2 Pipelines segment.
In our Natural Gas Pipelines business segment, if we would cease providing
utility services, we would be required to remove surface facilities from land
belonging to our customers and others. Our Texas intrastate natural gas pipeline
group has various condensate drip tanks and separators located throughout its
natural gas pipeline systems, as well as inactive gas processing plants,
laterals and gathering systems which are no longer integral to the overall
mainline transmission systems, and asbestos-coated underground pipe, which is
being abandoned and retired. Our Kinder Morgan Interstate Gas Transmission
system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of March 31, 2003, we have recognized
27
asset retirement obligations in the aggregate amount of $2.8 million relating to
the businesses within our Natural Gas Pipelines segment.
We have included $0.8 million of our total $14.1 million asset retirement
obligations as of March 31, 2003 with Accrued other current liabilities in the
accompanying consolidated balance sheet and the remaining $13.3 million with
Other long-term liabilities and deferred credits. No assets are legally
restricted for purposes of settling our asset retirement obligations. A
reconciliation of the beginning and ending aggregate carrying amount of our
asset retirement obligations for the quarter ended March 31, 2003 is as follows
(in thousands):
Balance at Dec. 31, 2002................... $ -
Cumulative effect transition adjustment.... 14,125
Liabilities incurred....................... -
Liabilities settled........................ (202)
Accretion expense.......................... 171
Revisions in estimated cash flows.......... -
-----------
Balance at Mar. 31, 2003................... $ 14,094
===========
Pro Forma Information
If SFAS No. 143 had been applied as of January 1, 2002, our liability for
asset retirement obligations would have been approximately $14.1 million at
March 31, 2002 and December 31, 2002. The following table illustrates the Pro
Forma impact on the carrying amounts of the obligations for each of the three
months ended March 31, 2002 and March 31, 2003 as if SFAS No. 143 had been
adopted on January 1, 2002 (in thousands):
Three Months Three Months
Ended Ended
Mar. 31, 2003 Mar. 31, 2002
------------- -------------
Balance at beginning of period....... $ 14,125 $14,344
Liabilities incurred................. -- --
Liabilities settled.................. (202) (437)
Accretion expense.................... 171 233
Revisions in estimated cash flows.... -- --
--------- ---------
Balance at end of period............. $ 14,094 $ 14,140
========= =========
For each of the three months ended March 31, 2003 and 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
March 31,
--------------------
2003 2002
--------- --------
Reported limited partners' interest in net income $ 94,018 $ 79,639
Add: limited partners' interest in adjustments
from change in accounting for asset retirement
obligations -- (253)
-------- --------
Adjusted limited partners' interest in net income $ 94,018 $ 79,386
======== ========
Basic and diluted limited partners' net income per unit:
Reported net income $ 0.52 $ 0.48
Adjs. from change in accounting for asset
retirement obligations -- --
-------- --------
Adjusted net income $ 0.52 $ 0.48
======== ========
5. Distributions
On February 14, 2003, we paid a cash distribution for the quarterly period
ended December 31, 2002, of $0.625 per unit to our common unitholders and to our
class B unitholders. KMR, our sole i-unitholder, received 858,981 additional
i-units based on the $0.625 cash distribution per common unit. The distributions
were declared on
28
January 15, 2003, payable to unitholders of record as of January 31, 2003.
On April 16, 2003, we declared a cash distribution for the quarterly period
ended March 31, 2003, of $0.64 per unit. The distribution will be paid on or
before May 15, 2003, to unitholders of record as of April 30, 2003. Our common
unitholders and class B unitholders will receive cash. KMR will receive a
distribution in the form of additional i-units based on the $0.64 distribution
per common unit. The number of i-units distributed will be 859,933. For each
outstanding i-unit that KMR holds, a fraction of an i-unit (0.018488) will be
issued. The fraction was determined by dividing:
o $0.64, the cash amount distributed per common unit
by
o $34.617, the average of KMR's limited liability shares' closing market
prices from April 11-25, 2003, the ten consecutive trading days preceding
the date on which the shares began to trade ex-dividend under the rules of
the New York Stock Exchange.
6. Intangibles
Effective January 1, 2002, we adopted Statement of Financial Accounting
Standards No. 141 "Business Combinations" and Statement of Financial
Accounting Standards No. 142 "Goodwill and Other Intangible Assets." These
accounting pronouncements require that we prospectively cease amortization of
all intangible assets having indefinite useful economic lives. Such assets,
including goodwill, are not to be amortized until their lives are determined to
be finite. A recognized intangible asset with an indefinite useful life should
be tested for impairment annually or on an interim basis if events or
circumstances indicate that the fair value of the asset has decreased below its
carrying value. We completed this initial transition impairment test in June
2002 and determined that our goodwill was not impaired as of January 1, 2002. We
completed our second impairment test in early May 2003 and determined that our
goodwill was not impaired as of January 1, 2003.
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):
Mar. 31, Dec. 31,
2003 2002
--------- ---------
Goodwill $869,840 $856,940
Lease value 6,124 6,124
Contracts and other 11,662 11,580
Accumulated amortization (430) (380)
--------- ---------
Other intangibles, net 17,356 17,324
--------- ---------
Total intangibles, net $887,196 $874,264
========= =========
Changes in the carrying amount of goodwill for the three months ended March
31, 2003 are summarized as follows (in thousands):
Products Natural Gas CO2
Pipelines Pipelines Pipelines Terminals Total
--------- ----------- --------- --------- -----
Balance at Dec. 31, 2002 $ 349,458 $ 307,412 $ 46,101 $ 153,969 $ 856,940
Goodwill acquired -- -- -- 12,900 12,900
Goodwill dispositions, net -- -- -- -- --
Impairment losses -- -- -- -- --
------- ---------- ---------- ---------- ----------
Balance at Mar. 31, 2003 $ 349,458 $ 307,412 $ 46,101 $ 166,869 $ 869,840
========= ========= ========= ========= =========
29
Amortization expense on intangibles consists of the following (in thousands):
Three Months Ended Mar. 31,
2003 2002
------------ -----------
Goodwill $ -- $ --
Lease value 35 35
Contracts and other 15 10
------------ -----------
$ 50 $ 45
============ ===========
Our weighted average amortization period for our intangible assets is
approximately 41 years. The following table shows the estimated amortization
expense for these assets for each of the five succeeding fiscal years (in
thousands):
2004 $206
2005 $206
2006 $206
2007 $206
2008 $206
7. Debt
Our debt and credit facilities as of March 31, 2003, consisted primarily of:
o a $530 million unsecured 364-day credit facility due October 14, 2003;
o a $445 million unsecured three-year credit facility due October 15, 2005;
o $37.1 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 66 2/3% owned subsidiary,
International Marine Terminals, is the obligor on the bonds);
o $250 million of 5.35% Senior Notes due August 15, 2007;
o $30 million of 7.84% Senior Notes, with a final maturity of July 2008 (our
subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes);
o $250 million of 6.30% Senior Notes due February 1, 2009;
o $250 million of 7.50% Senior Notes due November 1, 2010;
o $700 million of 6.75% Senior Notes due March 15, 2011;
o $450 million of 7.125% Senior Notes due March 15, 2012;
o $25 million of New Jersey Economic Development Revenue Refunding Bonds due
January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals LLC, is
the obligor on the bonds);
o $87.9 million of Industrial Revenue Bonds with final maturities ranging
from September 2019 to December 2024 (our subsidiary, Kinder Morgan Liquids
Terminals LLC, is the obligor on the bonds);
o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan
Operating L.P. "B," is the obligor on the bonds);
30
o $300 million of 7.40% Senior Notes due March 15, 2031;
o $300 million of 7.75% Senior Notes due March 15, 2032;
o $500 million of 7.30% Senior Notes due August 15, 2033; and
o a $975 million short-term commercial paper program (supported by our credit
facilities, the amount available for borrowing under our credit facilities
is reduced by our outstanding commercial paper borrowings).
None of our debt or credit facilities are subject to payment acceleration as a
result of any change to our credit ratings. However, the margin that we pay with
respect to LIBOR based borrowings under our credit facilities is tied to our
credit ratings.
Our outstanding short-term debt as of March 31, 2003 was $407.8 million. The
balance consisted of:
o $362 million of commercial paper borrowings;
o $37.1 million under the SFPP, L.P. 10.7% First Mortgage Notes;
o $5 million under the Central Florida Pipeline LLC Notes; and
o $3.7 million in other borrowings.
We intend and have the ability to refinance $393.3 million of our short-term
debt on a long-term basis under our unsecured long-term credit facility.
Accordingly, such amounts have been classified as long-term debt in our
accompanying consolidated balance sheet. Currently, we do not anticipate any
liquidity problems. The weighted average interest rate on all of our borrowings
was approximately 4.730% per annum during the first quarter of 2003 and 5.172%
per annum during the first quarter of 2002.
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, 2002.
Credit Facilities
As of March 31, 2003, we had two credit facilities:
o a $530 million unsecured 364-day credit facility due October 14, 2003; and
o a $445 million unsecured three-year credit facility due October 15, 2005.
Our credit facilities are with a syndicate of financial institutions. Wachovia
Bank, National Association is the administrative agent under both credit
facilities. The terms of our two credit facilities are substantially similar to
the terms of our previous credit facilities. Interest on the two credit
facilities accrues at our option at a floating rate equal to either:
o the administrative agent's base rate (but not less than the Federal Funds
Rate, plus 0.5%); or
o LIBOR, plus a margin, which varies depending upon the credit rating of our
long-term senior unsecured debt.
There were no borrowings under either credit facility at December 31, 2002 or
at March 31, 2003. The amount available for borrowing under our credit
facilities is reduced by:
o a $23.7 million letter of credit that supports Kinder Morgan Operating
L.P. "B"'s tax-exempt bonds;
o a $28 million letter of credit entered into on December 23, 2002 that
supports Nassau County, Florida Ocean Highway and Port Authority tax exempt
bonds (associated with the operations of our bulk terminal facility
31
located at Fernandina Beach, Florida);
o a $0.2 million letter of credit entered into on June 4, 2002 that supports a
workers' compensation insurance policy;
o a $0.5 million letter of credit entered into on March 31, 2003 that
supports an engineering contract; and
o our outstanding commercial paper borrowings.
Our three-year credit facility also permits us to obtain bids for fixed rate
loans from members of the lending syndicate.
On May 5, 2003, we increased the borrowings available under our two credit
facilities by $75 million as follows:
o our $530 million unsecured 364-day credit facility was increased to $570
million; and
o our $445 million unsecured three-year credit facility was increased to
$480 million.
Senior Notes
As of March 31, 2003, our unamortized liability balance due on the various
series of our senior notes was as follows (in millions):
8.0% senior notes due March 15, 2005 $ 199.8
5.35% senior notes due August 15, 2007 249.9
6.3% senior notes due February 1, 2009 249.5
7.5% senior notes due November 1, 2010 248.8
6.75% senior notes due March 15, 2011 698.4
7.125% senior notes due March 15, 2012 448.1
7.4% senior notes due March 15, 2031 299.3
7.75% senior notes due March 15, 2032 298.5
7.3% senior notes due August 15, 2033 499.0
-------
Total $3,191.3
========
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 March
31, 2003, we have entered into interest rate swap agreements with a notional
principal amount of $1.95 billion for the purpose of hedging the interest rate
risk associated with our fixed and variable rate debt obligations. The $1.95
billion notional principal amount of our interest rate swap agreements has not
changed since December 31, 2002.
These swaps meet the conditions required to assume no ineffectiveness under
SFAS No. 133 and, therefore, we have accounted for them using the "shortcut"
method prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust
the carrying value of each swap to its fair value each quarter, with an
offsetting entry to adjust the carrying value of the debt securities whose fair
value is being hedged. For more information on our risk management activities,
see Note 10.
Commercial Paper Program
As of December 31, 2002 and March 31, 2003, our commercial paper program
provided for the issuance of up to $975 million of commercial paper. As of March
31, 2003, we had $362 million of commercial paper outstanding with an average
interest rate of 1.429%. Borrowings under our commercial paper program reduce
the borrowings allowed under our credit facilities.
32
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 first quarter of 2003, the
weighted-average interest rate on these bonds was 1.10% per annum, and as of
March 31, 2003, the interest rate was 1.17%. 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
We own a 66 2/3% interest in International Marine Terminals partnership. The
principal assets owned by IMT are dock and wharf facilities financed by the
Plaquemines Port, Harbor and Terminal District (Louisiana) $40,000,000
Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds
(International Marine Terminals Project) Series 1984A and 1984B. The bonds
mature on March 15, 2006. The bonds are backed by two letters of credit issued
by KBC Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit
Reimbursement Agreement relating to the letters of credit in the amount of $45.5
million was entered into by IMT and KBC Bank. In connection with that agreement,
we agreed to guarantee the obligations of IMT in proportion to our ownership
interest. Our obligation is approximately $30.3 million for principal, plus
interest and other fees.
Contingent Debt
Cortez Pipeline Company Debt
Pursuant to a certain Throughput and Deficiency Agreement, the owners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a
subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers Pipeline
Company - 13% owner) are required, on a percentage ownership basis, to
contribute capital to Cortez Pipeline Company in the event of a cash deficiency.
The Throughput and Deficiency Agreement contractually supports the borrowings of
Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline
Company, by obligating the owners of Cortez Pipeline Company to fund cash
deficiencies at Cortez Pipeline Company, including cash deficiencies relating to
the repayment of principal and interest on borrowings by Cortez Capital
Corporation. Parent companies of the respective Cortez Pipeline Company owners
further severally guarantee, on a percentage basis, the obligations of the
Cortez Pipeline Company owners under the Throughput and Deficiency Agreement.
Due to our indirect ownership of Cortez Pipeline Company through Kinder Morgan
CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez Capital
Corporation. Shell Oil Company shares our guaranty obligations jointly and
severally through December 31, 2006 for Cortez Capital Corporation's debt
programs in place as of April 1, 2000.
As of March 31, 2003, the debt facilities of Cortez Capital Corporation
consisted of:
o $115.7 million of Series D notes due May 15, 2013;
o a $175 million short-term commercial paper program; and
o a $175 million committed revolving credit facility due December 26, 2003 (to
support the above-mentioned $175 million commercial paper program).
As of March 31, 2003, Cortez Capital Corporation had $135.1 million of
commercial paper outstanding with an interest rate of 1.30%, the average
interest rate on the Series D notes was 6.9322% and there were no borrowings
under the credit facility.
Plantation Pipeline Company Debt
On April 30, 1997, Plantation Pipeline Company entered into a $10 million,
ten-year floating-rate term credit agreement. We, as an owner of Plantation
Pipeline Company, severally guarantee this debt on a pro rata basis
33
equivalent to our respective 51% ownership interest. During 1999, this agreement
was amended to reduce the maturity date by three years. The $10 million is
outstanding as of March 31, 2003.
Red Cedar Gas Gathering Company Debt
In October 1998, Red Cedar Gas Gathering Company sold $55 million in aggregate
principal amount of Senior Notes due October 31, 2010. The $55 million was sold
in 10 different notes in varying amounts with identical terms.
The Senior Notes are collateralized by a first priority lien on the ownership
interests, including our 49% ownership interest, in Red Cedar Gas Gathering
Company. The Senior Notes are also guaranteed by us and the other owner of Red
Cedar Gas Gathering Company. The principal is to be repaid in seven equal
installments beginning on October 31, 2004 and ending on October 31, 2009, with
any remainder due October 31, 2010. The $55 million is outstanding as of March
31, 2003.
Nassau County, Florida Ocean Highway and Port Authority Debt
Nassau County, Florida Ocean Highway and Port Authority is a political
subdivision of the State of Florida. During 1990, Ocean Highway and Port
Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal
amount of $38.5 million for the purpose of constructing certain port
improvements located in Fernandino Beach, Nassau County, Florida. A letter of
credit was issued as security for the Adjustable Demand Revenue Bonds and was
guaranteed by the parent company of Nassau Terminals, Inc., the operator of the
port facilities. In July 2002, we acquired Nassau Terminals, Inc. and became
guarantor under the letter of credit agreement. In December 2002, we issued a
$28 million letter of credit under our credit facilities and the former letter
of credit guarantee was terminated.
Certain Relationships and Related Transactions
Retention Agreement
Effective January 17, 2002, KMI entered into a retention agreement with C.
Park Shaper, an officer of KMI, Kinder Morgan G.P., Inc. (our general partner)
and its delegate, KMR. Pursuant to the terms of the agreement, Mr. Shaper
obtained a $5 million personal loan guaranteed by KMI and us. Mr. Shaper was
required to purchase and did purchase KMI common stock and our common units in
the open market with the loan proceeds. If he voluntarily leaves KMI prior to
the end of five years, then he must repay the entire loan. On the fifth
anniversary date of the agreement, provided Mr. Shaper has continued to be
employed by KMI and/or our general partner, then KMI and we will assume Mr.
Shaper's obligations under the loan. The agreement contains provisions that
address termination for cause, death, disability and change of control. It is
expected that KMI's and our involvement in this loan will end in October 2003.
Lines of Credit
We have agreed to guarantee potential borrowings under lines of credit
available from Wachovia Bank, National Association, formerly known as First
Union National Bank, to Messrs. Joseph Listengart, Thomas Bannigan, Shaper and
James Street and Ms. Deborah Macdonald. Each of these KMI officers is primarily
liable for any borrowing on his or her line of credit, and if we make any
payment with respect to an outstanding loan, the officer on behalf of whom
payment is made must surrender a percentage of his or her options to purchase
KMI common stock. Our current obligations under the guaranties, on an individual
basis, generally do not exceed $1.0 million and such obligations, in the
aggregate, do not exceed $1.9 million. Our obligations under these guaranties do
not include our obligations in respect of the $5 million loan obtained by Mr.
Shaper in connection with his retention agreement, referred to above. To date,
we have made no payment with respect to these lines of credit. Further, our
involvement in these lines of credit will expire in October 2003.
34
KMI Asset Contributions
In conjunction with our acquisition of Natural Gas Pipelines assets from KMI
on December 31, 1999 and 2000, KMI became a guarantor of approximately $522.7
million of our debt. This amount has not changed as of December 31, 2002 and
March 31, 2003. KMI would be obligated to perform under this guarantee only if
we and/or our assets were unable to satisfy our obligations.
8. Partners' Capital
As of March 31, 2003, our partners' capital consisted of:
o 129,989,818 common units;
o 5,313,400 Class B units; and
o 46,513,029 i-units.
Together, these 181,816,247 units represent the limited partners' interest and
an effective 98% economic interest in the Partnership, exclusive of our general
partner's incentive distribution rights. Our general partner has an effective 2%
interest in the Partnership, excluding its incentive distribution rights. As of
March 31, 2003, our common unit total consisted of 117,034,083 units held by
third parties, 11,231,735 units held by KMI and its consolidated affiliates
(excluding our general partner); and 1,724,000 units held by our general
partner. Our Class B units were held entirely by KMI and our i-units were held
entirely by KMR.
As of December 31, 2002, our Partners' capital consisted of:
o 129,943,218 common units;
o 5,313,400 Class B units; and
o 45,654,048 i-units.
Our total common units outstanding at December 31, 2002, consisted of
116,987,483 units held by third parties, 11,231,735 units held by KMI and its
consolidated affiliates (excluding our general partner) and 1,724,000 units held
by our general partner. Our Class B units were held entirely by KMI and our
i-units were held entirely by KMR.
All of our Class B units were issued in December 2000. The Class B units are
similar to our common units except that they are not eligible for trading on the
New York Stock Exchange. We initially issued i-units in May 2001. The i-units
are a separate class of limited partner interests in us. All of our i-units are
owned by KMR and are not publicly traded. In accordance with its limited
liability company agreement, KMR'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 KMR's limited liability company agreement, the number of
outstanding KMR 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 KMR
is based upon the amount of cash we distribute to the owners of our common
units. When cash is paid to the holders of our common units, we will issue
additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by
KMR will have the same value as the cash payment on the common unit.
The cash equivalent of distributions of i-units will be treated as if it had
actually been distributed for purposes of determining the distributions to our
general partner. We will not distribute the related cash but will retain the
cash
35
and use the cash in our business. If additional units are distributed to
the holders of our common units, we will issue an equivalent amount of i-units
to KMR based on the number of i-units it owns. Based on the preceding, KMR
received a distribution of 858,981 i-units on February 14, 2003. These
additional i-units distributed were based on the $0.625 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, other than owners of i-units, in accordance with their percentage
interests. Normal allocations according to percentage interests are made,
however, only after giving effect to any priority income allocations in an
amount equal to the incentive distributions that are allocated 100% to our
general partner. Incentive distributions are generally defined as all cash
distributions paid to our general partner that are in excess of 2% of the
aggregate value of cash and i-units being distributed.
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 $0.625 per unit paid on February 14, 2003 for
the fourth quarter of 2002 required an incentive distribution to our general
partner of $72.5 million. Our distribution of $0.55 per unit paid on February
14, 2002 for the fourth quarter of 2001 required an incentive distribution to
our general partner of $54.4 million. The increased incentive distribution to
our general partner paid for the fourth quarter of 2002 over the distribution
paid for the fourth 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 first quarter of 2003 of $0.64 per unit will
result in an incentive distribution to our general partner of approximately
$75.5 million. This compares to our distribution of $0.59 per unit and incentive
distribution to our general partner of approximately $61.0 million for 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 quarters ended March 31, 2003 and 2002,
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 9. Our total comprehensive
income is as follows (in thousands):
Three Months Ended
March 31,
2003 2002
-------- --------
Net income $170,478 $141,433
Change in fair value of derivatives used for hedging
purposes (53,870) (66,936)
Reclassification of change in fair value of derivatives
to net income 50,431 (24,359)
------ --------
Comprehensive income $167,039 $50,138
======== =======
10.Risk Management
Hedging Activities
Certain of our business activities expose us to risks associated with changes
in the market price of natural gas, natural gas liquids, crude oil and carbon
dioxide. Through KMI, we use energy financial instruments to reduce our risk of
changes in the prices of natural gas, natural gas liquids and crude oil markets
(and carbon dioxide to the extent contracts are tied to crude oil prices) as
discussed below. 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.
36
The energy risk management products that we use include:
o commodity futures and options contracts;
o fixed-price swaps; and
o basis swaps.
Pursuant to our management's approved policy, we are to engage in these
activities only as a hedging mechanism against price volatility associated with:
o pre-existing or anticipated physical natural gas, natural gas liquids and
crude oil sales;
o pre-existing or anticipated physical carbon dioxide sales that have
pricing tied to crude oil prices;
o natural gas purchases; and
o system use and storage.
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.
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS 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. However, if the derivative transaction qualifies for and is
designated as a normal purchase and sale, it is exempted from the fair value
accounting requirements of SFAS No. 133 and is accounted for using traditional
accrual accounting.
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 derivatives that hedge our commodity price risks involve our normal
business activities, which include the sale of natural gas, natural gas liquids,
oil and carbon dioxide, and these derivatives have been designated as cash flow
hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that
hedge exposure to variable cash flows of forecasted transactions as cash flow
hedges and the effective portion of the derivative's gain or loss is initially
reported as a component of other comprehensive income (outside earnings) and
subsequently reclassified into earnings when the forecasted transaction affects
earnings. To be effective, changes in the value of the derivative or its
resulting cash flows must substantially offset changes in the value or cash
flows of the item being hedged. The ineffective portion of the gain or loss is
reported in earnings immediately.
The gains and losses included in Accumulated other comprehensive income are
reclassified into earnings as the hedged sales and purchases take place.
Approximately $34.1 million of the Accumulated other comprehensive loss balance
of $48.7 million representing unrecognized net losses on derivative activities
as of March 31, 2003 is expected to be reclassified into earnings during the
next twelve months. During the quarter ended March 31, 2003, we reclassified
$50.4 million of accumulated other comprehensive income into earnings. This
amount includes the balance of $45.3 million representing unrecognized net
losses on derivative activities at December 31, 2002. In addition, we did not
reclassify any gains or losses 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
37
time period.
We recognized a gain of $0.2 million during the first quarter of 2003 and a
gain of $0.8 million during the first quarter of 2002 as a result of ineffective
hedges. These amounts are reported within the captions Gas purchases and other
costs of sales and Operations and maintenance in the accompanying Consolidated
Statements of Income. For each of the quarters ended March 31, 2003 and 2002, we
did not exclude any component of the derivative instruments' gain or loss from
the assessment of hedge effectiveness.
The differences between the current market value and the original physical
contracts value associated with our hedging activities are primarily reflected
as Other current assets and Accrued other current liabilities in the
accompanying consolidated balance sheets. As of March 31, 2003, our balance of
$78.8 million of Other current assets included approximately $66.1 million
related to risk management hedging activities, and our balance of $358.5 million
of Accrued other current liabilities included approximately $100.9 million
related to risk management hedging activities. As of December 31, 2002, our
balance of $104.5 million of Other current assets included approximately $57.9
million related to risk management hedging activities, and our balance of $298.7
million of Accrued other current liabilities included approximately $101.3
million related to risk management hedging activities.
The remaining differences between the current market value and the original
physical contracts value associated with our hedging activities are reflected as
deferred charges or deferred credits in the accompanying consolidated balance
sheets. As of March 31, 2003, our balance of $241.9 million of Deferred charges
and other assets included approximately $4.5 million related to risk management
hedging activities, and our balance of $220.3 million of Other long-term
liabilities and deferred credits included approximately $19.3 million related to
risk management hedging activities. As of December 31, 2002, our balance of
$250.8 million of Deferred charges and other assets included approximately $5.7
million related to risk management hedging activities, and our balance of $199.8
million of Other long-term liabilities and deferred credits included
approximately $8.5 million related to risk management hedging activities.
Our over-the-counter swaps and options are with a number of parties, who
principally have investment grade credit ratings. We both owe money and are owed
money under these financial instruments. Defaults by counterparties under
over-the-counter swaps and options could expose us to additional commodity price
risks in the event that we are unable to enter into replacement contracts for
such swaps and options on substantially the same terms. Alternatively, we may
need to pay significant amounts to the new counterparties to induce them to
enter into replacement swaps and options on substantially the same terms. While
we enter into derivative transactions principally 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
in the future.
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 March
31, 2003 and as of December 31, 2002, we were a party to interest rate swap
agreements with a notional principal amount of $1.95 billion for the purpose of
hedging the interest rate risk associated with our fixed and variable rate debt
obligations.
As of March 31, 2003, a notional principal amount of $1.75 billion of these
agreements effectively converts the interest expense associated with the
following series of our senior notes from fixed rates to variable rates based on
an interest rate of LIBOR plus a spread:
o $200 million principal amount of our 8.0% senior notes due March 15, 2005;
o $200 million principal amount of our 5.35% senior notes due August 15,
2007;
o $250 million principal amount of our 6.30% senior notes due February 1,
2009;
o $200 million principal amount of our 7.125% senior notes due March 15,
2012;
38
o $300 million principal amount of our 7.40% senior notes due March 15,
2031;
o $200 million principal amount of our 7.75% senior notes due March 15,
2032; and
o $400 million principal amount of our 7.30% senior notes due August 15, 2033.
These swap agreements have termination dates that correspond to the maturity
dates of the related series of senior notes, therefore, as of March 31, 2003,
the maximum length of time over which we have hedged our exposure to the
variability in future cash flows associated with interest rate risk is through
August 2033.
The swap agreements related to our 7.40% senior notes contain mutual cash-out
provisions at the then-current economic value every seven years. The swap
agreements related to our 7.125% senior notes contain cash-out provisions at the
then-current economic value at March 15, 2009. The swap agreements related to
our 7.75% senior notes and our 7.30% senior notes contain mutual cash-out
provisions at the then-current economic value every five years.
These interest rate swaps have been designated as fair value hedges as
defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge a
recognized asset or liability's exposure to changes in their fair value as fair
value hedges and the gain or loss on fair value hedges are to be recognized in
earnings in the period of change together with the offsetting loss or gain on
the hedged item attributable to the risk being hedged. The effect of that
accounting is to reflect in earnings the extent to which the hedge is not
effective in achieving offsetting changes in fair value.
As of March 31, 2003, we also had swap agreements that effectively convert
the interest expense associated with $200 million of our variable rate debt to
fixed rate. The maturity dates of these swap agreements range from September 2,
2003 to September 1, 2005. In the prior year, this hedge was designated a fair
value hedge on our $200 million Floating Rate Senior Notes, which were retired
in March 2002. Subsequent to the repayment of our Floating Rate Senior Notes,
the swaps were designated as a cash flow hedge of the risk associated with
changes in the designated benchmark interest rate (in this case, one-month
LIBOR) related to forecasted payments associated with interest on an aggregate
of $200 million of our portfolio of commercial paper.
Our interest rate swaps meet the conditions required to assume no
ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed for fair value hedges by SFAS No. 133.
Accordingly, we adjust the carrying value of each swap to its fair value each
quarter, with an offsetting entry to adjust the carrying value of the debt
securities whose fair value is being hedged. We record interest expense equal to
the variable rate payments or fixed rate payments under the swaps. Interest
expense is accrued monthly and paid semi-annually. As of March 31, 2003, we
recognized an asset of $168.9 million and a liability of $11.2 million for the
$157.7 million net fair value of our swap agreements, and we included these
amounts with Deferred charges and other assets and Other long-term liabilities
and deferred credits on the accompanying balance sheet. The offsetting entry to
adjust the carrying value of the debt securities whose fair value was being
hedged was recognized as Market value of interest rate swaps on the accompanying
balance sheet. As of December 31, 2002, we recognized an asset of $179.1 million
and a liability of $12.1 million for the $167.0 million net fair value of our
swap agreements, and we included these amounts with Deferred charges and other
assets and Other long-term liabilities and deferred credits on the accompanying
balance sheet and again, the offsetting entry to adjust the carrying value of
the debt securities whose fair value was being hedged was recognized as Market
value of interest rate swaps on the accompanying balance sheet.
We are exposed to credit related losses in the event of nonperformance by
counterparties to these interest rate swap agreements. While we enter into
derivative transactions primarily with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that from
time to time losses will result from counterparty credit risk.
11.Reportable Segments
We divide our operations into four reportable business segments:
39
o Products Pipelines;
o Natural Gas Pipelines;
o CO2 Pipelines; and
o Terminals.
We evaluate performance based on each segments' earnings, which exclude
general and administrative expenses, third-party debt costs, interest income and
expense and minority interest. Our reportable segments are strategic business
units that offer different products and services. Each segment is managed
separately because each segment involves different products and marketing
strategies.
Our Products Pipelines segment derives its revenues primarily from the
transportation and terminaling 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 transmission, storage,
gathering and sale of natural gas. Our CO2 Pipelines segment derives its
revenues primarily from the transportation and marketing of carbon dioxide used
as a flooding medium for recovering crude oil from mature oil fields and from
the production and sale 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 March 31,
2003 2002
----------- -----------
Revenues
Products Pipelines............................ $ 144,417 $ 134,818
Natural Gas Pipelines......................... 1,480,954 537,557
CO2 Pipelines................................. 48,456 32,124
Terminals..................................... 115,011 98,566
----------- -----------
Total consolidated revenues................... $ 1,788,838 $ 803,065
=========== ===========
Depreciation and amortization (a)
Products Pipelines............................ $ 16,560 $ 15,996
Natural Gas Pipelines......................... 12,626 11,425
CO2 Pipelines................................. 11,762 6,989
Terminals..................................... 9,028 6,916
----------- -----------
Total consolidated depreciation and
amortization................................ $ 49,976 $ 41,326
=========== ===========
(a) 2003 amounts include $171 of non-cash asset retirement obligation accretion
expense, included within operations and maintenance expense in the
accompanying consolidated statement of income. $169 of such expense is
included in CO2 Pipelines' depreciation and amortization total and $2 is
included in Natural Gas Pipelines' depreciation and amortization total.
Operating income
Products Pipelines............................ $ 86,671 $ 78,573
Natural Gas Pipelines......................... 72,796 61,507
CO2 Pipelines................................. 20,181 12,634
Terminals..................................... 50,183 42,674
----------- -----------
Total segment operating income................ 229,831 195,388
Corporate administrative expenses............. (34,679) (29,532)
------------ ------------
Total consolidated operating income........... $ 195,152 $ 165,856
=========== ===========
40
Earnings from equity investments
Products Pipelines............................ $ 8,043 $ 8,001
Natural Gas Pipelines......................... 6,224 6,125
CO2 Pipelines................................. 10,006 9,145
Terminals..................................... 32 -
----------- -----------
Total consolidated equity earnings............ $ 24,305 $ 23,271
=========== ===========
Amortization of excess cost of equity investments
Products Pipelines............................ $ 821 $ 821
Natural Gas Pipelines......................... 69 69
CO2 Pipelines................................. 504 504
Terminals..................................... - -
----------- -----------
Total consolidated amortization of excess cost
of invests................................. $ 1,394 $ 1,394
=========== ===========
Income taxes and Other, net - income (expense)
Products Pipelines............................ $ (2,600) $ (2,775)
Natural Gas Pipelines......................... (85) 5
CO2 Pipelines................................. 17 94
Terminals..................................... (1,243) (1,775)
------------ ------------
Total consolidated income taxes and Other, net $ (3,911) $ (4,451)
============ ============
Segment earnings
Products Pipelines............................ $ 91,293 $ 82,978
Natural Gas Pipelines......................... 78,866 67,568
CO2 Pipelines................................. 29,700 21,369
Terminals..................................... 48,972 40,899
----------- -----------
Total segment earnings........................ 248,831 212,814
Interest and corporate administrative
expenses (a) ............................... (78,353) (71,381)
------------ ------------
Total consolidated net income................. $ 170,478 $ 141,433
=========== ===========
(a) Includes interest and debt expense, general and administrative expenses,
minority interest expense, cumulative effect adjustment from a change in
accounting principle (2003 only) and other insignificant items.
March 31, Dec. 31,
2003 2002
----------- --------
Assets
Products Pipelines............................ $ 3,056,164 $ 3,088,799
Natural Gas Pipelines......................... 3,476,175 3,121,674
CO2 Pipelines................................. 722,512 613,980
Terminals..................................... 1,302,494 1,165,096
----------- -----------
Total segment assets.......................... 8,557,345 7,989,549
Corporate assets (a).......................... 244,889 364,027
----------- -----------
Total consolidated assets..................... $ 8,802,234 $ 8,353,576
=========== ===========
(a) Includes cash, cash equivalents and certain unallocable deferred charges.
12. New Accounting Pronouncements
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 requirement
that gains and losses on debt extinguishment must be classified as extraordinary
items in the income statement. Instead, such gains and losses are now 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
are effective for fiscal years beginning after May 15, 2002, and the changes
related to lease accounting are effective for transactions occurring after May
15, 2002. Adoption of this Statement has not had any immediate effect on our
consolidated financial statements. We will apply this guidance
41
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 adopted 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.
In November 2002, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements
for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This
interpretation of Financial Accounting Standards Board Statements No. 5, 57 and
107, and rescission of FIN No. 34 elaborates on the disclosures to be made by a
guarantor in its interim and annual financial statements about its obligations
under certain guarantees that it has issued. It also clarifies that a guarantor
is required to recognize, at the inception of a guarantee, a liability for the
fair value of the obligation undertaken in issuing the guarantee. This
interpretation incorporates, without change, the guidance in FIN No. 34,
"Disclosure of Indirect Guarantees of Indebtedness of Others," which is being
superceded. The initial recognition and initial measurement provisions of FIN
No. 45 are applicable on a prospective basis to guarantees issued or modified
after December 31, 2002. The disclosure requirements in this interpretation are
effective for financial statements of interim or annual periods after December
15, 2002, and have been adopted.
In December 2002, the Financial Accounting Standards Board issued SFAS No.
148, "Accounting for Stock-Based Compensation - Transition and Disclosure." This
amendment to SFAS No. 123, "Accounting for Stock-Based Compensation," provides
alternative methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. In addition, this
statement amends the disclosure requirements of SFAS No. 123 to require
disclosures in both annual and interim financial statements about the method of
accounting for stock-based employee compensation and the effect of the method
used on reported results. The provisions of this statement are effective for
financial statements of interim or annual periods after December 15, 2002.
Adoption of this Statement has not had any immediate effect on our consolidated
financial statements.
On April 30 2003, the Financial Accounting Standards Board issued SFAS No.
149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities." This Statement amends and clarifies accounting for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities under SFAS No. 133.
The new guidance amends SFAS No. 133 for decisions made:
o as part of the Derivatives Implementation Group process that effectively
required amendments to SFAS No. 133;
o in connection with other Board projects dealing with financial
instruments; and
o regarding implementation issues raised in relation to the application of the
definition of a derivative, particularly regarding the meaning of an
"underlying" and the characteristics of a derivative that contains financing
components.
The amendments set forth in SFAS No. 149 are intended to improve financial
reporting by requiring that contracts with comparable characteristics be
accounted for similarly. In particular, this Statement clarifies under what
circumstances a contract with an initial net investment meets the
characteristics of a derivative as discussed in SFAS No. 133. In addition, it
clarifies when a derivative contains a financing component that warrants special
reporting in the statement of cash flows. SFAS No. 149 amends certain other
existing pronouncements. These changes are intended to result in more consistent
reporting of contracts that are derivatives in their entirety or that contain
embedded derivatives that warrant separate accounting.
42
The Statement is effective for contracts entered into or modified after June
30, 2003, except as stated below and for hedging relationships designated after
June 30, 2003. We will apply this guidance prospectively. We have not yet
quantified the impacts of adopting this Statement on our financial position or
results of operations.
We will continue to apply the provisions of this Statement that relate to SFAS
No. 133 Implementation Issues that have been effective for fiscal quarters that
began prior to June 15, 2003, in accordance with their respective effective
dates. In addition, certain provisions relating to forward purchases or sales of
"when-issued" securities or other securities that do not yet exist, will be
applied to existing contracts as well as new contracts entered into after June
30, 2003.
43
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Results of Operations
First Quarter 2003 Compared With First Quarter 2002
For the quarter ended March 31, 2003, our operating results represented our
most profitable quarter ever. Total consolidated net income before a change in
accounting principle was a record $167.0 million ($0.50 per diluted unit), an
18% increase from the $141.4 million ($0.48 per diluted unit) in consolidated
net income reported for the first quarter of 2002. Additionally, our 2003 first
quarter results benefited from a cumulative-effect adjustment of $3.5 million
related to a change in accounting for asset retirement obligations pursuant to
our adoption of Statement of Financial Accounting Standards No. 143, "Accounting
for Asset Retirement Obligations" on January 1, 2003. After the
cumulative-effect adjustment, net income for the quarter totaled $170.5 million
($0.52 per diluted unit). For more information on this cumulative-effect
adjustment from a change in accounting principle, see Note 4 to our Consolidated
Financial Statements, included elsewhere in this report.
Revenues for the first quarter of 2003 were a record $1,788.8 million,
compared with revenues of $803.1 million in the same year-earlier period. The
increase, primarily due to higher natural gas prices, was largely offset by
similar increases in natural gas purchase costs. Our first quarter 2003
operating income was $195.2 million, the second-highest level ever attained and
18% over the $165.9 million in operating income earned during the first quarter
of 2002. Operating expenses, excluding depreciation, depletion and amortization,
general and administrative expenses and taxes, other than income taxes, were
$1,494.5 million in the first quarter of 2003, compared with $553.8 million in
the same period a year ago.
Our first quarter results demonstrated balanced growth across our business
portfolio as all four of our business segments reported quarter-to-quarter
increases in earnings, operating income and revenues. The increases were driven
primarily by internal growth, mainly resulting from our ongoing expansion and
capital improvement projects within our CO2 Pipelines and Natural Gas Pipelines
business segments, but also by the acquisitions of pipeline and terminal
businesses that we have made since the beginning of the first quarter of 2002.
The largest of these was the January 31, 2002 purchase of Kinder Morgan Tejas.
Kinder Morgan Tejas' operations include a 3,400-mile Texas 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.
First quarter earnings from our investments accounted for under the equity
method of accounting, which include investments in Plantation Pipe Line Company,
Cortez Pipeline Company and the Red Cedar Gathering Company, were up
approximately 5% in the first quarter of 2003, compared to the same year ago
period. Equity earnings, net of amortization of excess costs, were $22.9 million
and $21.9 million for each of the first three months of 2003 and 2002,
respectively. In addition, on April 16, 2003, we declared a record quarterly
cash distribution of $0.64 per unit (an annualized rate of $2.56). This first
quarter 2003 distribution will be paid on May 15, 2003, and is up 8% from the
$0.59 per unit distribution we made for the first quarter of 2002. Furthermore,
we expect to declare cash distributions of at least $2.63 per unit for 2003, and
we expect to increase our quarterly cash distribution to at least $0.68 per unit
(an annualized rate of $2.72) by the fourth quarter of 2003. However, no
assurance can be given that we will be able to achieve this level of
distributions.
Products Pipelines
Our Products Pipelines segment reported earnings of $91.3 million on revenues
of $144.4 million in the first quarter of 2003. In the first quarter of 2002,
the segment reported earnings of $83.0 million on revenues of $134.8 million.
Operating income for each of the quarters ended March 31, 2003 and 2002 was
$86.7 million and $78.6 million, respectively.
The $8.3 million (10%) increase in quarter-to-quarter earnings resulted from
internal growth, primarily driven by record earnings from our North System
liquids pipeline and higher returns from terminal assets associated with our
Pacific operations. The $9.6 million (7%) increase in overall segment revenues
includes a $3.5 million increase in revenues from our North System, primarily
due to a 17% increase in throughput volume and higher average tariff rates in
the first quarter of 2003 compared to the same period last year. The throughput
volume increase was due to
44
cold weather in the Midwest and strong propane demand. Revenues from our Pacific
operations accounted for $2.0 million of the quarter-to-quarter increase in
overall segment revenues. Although total delivery volumes on our Pacific
operations were down slightly in the first quarter of 2003 compared to last
year, average tariff rates remained relatively flat, and we benefited from
higher terminal revenue as a result of increased ethanol blending operations.
Revenues from our CALNEV pipeline increased $1.6 million in the first quarter of
2003 compared to the first quarter of 2002. CALNEV benefited from a slight (1%)
increase in transport volumes and an almost 3% increase in average tariff rates.
The segment's expenses, excluding depreciation charges and taxes, other than
income taxes, increased a slight 1% in the first quarter of 2003, compared to
the first quarter a year ago. Expenses totaled $36.0 million in the first
quarter of 2003 and $35.5 million in the first quarter of 2002. The $0.5 million
change was the result of higher operations and maintenance expenses, partially
offset by lower fuel and power expenses.
Earnings from our Products Pipelines' equity investments, net of amortization
of excess costs, were $7.2 million in each of the first quarters of 2003 and
2002. The segment's equity earnings primarily relate to our 51% ownership
interest in Plantation Pipe Line Company. Plantation's earnings in the first
quarter of 2003 were essentially unchanged from its earnings in the first
quarter of 2002. Lower pipeline revenues resulting from a decrease in delivery
volumes were offset by higher non-transportation income items.
Natural Gas Pipelines
Our Natural Gas Pipelines segment reported earnings of $78.9 million on
revenues of $1,481.0 million in the first quarter of 2003. In the first quarter
of 2002, the segment reported earnings of $67.6 million on revenues of $537.6
million. The segment's expenses, excluding depreciation charges and taxes, other
than income taxes, were $1,391.3 million in the first quarter of 2003 and $461.3
million in the first quarter of 2002. Operating income for each of the two
quarters ended March 31, 2003 and 2002 was $72.8 million and $61.5 million,
respectively.
The segment's $11.3 million (17%) increase in earnings in the first quarter
of 2003 compared to the first quarter of 2002 was primarily attributable to
internal growth on our Kinder Morgan Interstate Gas Transmission and Trailblazer
Pipeline Company natural gas pipeline systems. Together, these two Rocky
Mountain natural gas pipeline systems accounted for $10.6 million of the
quarter-to-quarter increase in segment earnings. The increase was primarily the
result of higher operational sales of natural gas at higher margins as well as
an increase in natural gas transport volumes. In May 2002, we completed a
fully-subscribed, $59 million expansion project on our Trailblazer system that
increased transportation capacity on the pipeline by approximately 60%.
Earnings from our Texas intrastate natural gas pipeline group were up $0.9
million in the first quarter of 2003, compared to the same period last year,
principally due to the contributions from our North Texas and Mier-Monterrey
natural gas pipelines. In addition to the Kinder Morgan Tejas and Kinder Morgan
Texas Pipeline systems, our Texas intrastate natural gas group now includes the
Kinder Morgan North Texas pipeline, completed in August 2002, and the
Mier-Monterrey pipeline, completed in March 2003.
The North Texas pipeline is an 86-mile system that transports natural gas
from an interconnect with KMI's Natural Gas Pipeline Company of America system
in Lamar County, Texas to electric generating facilities within the State of
Texas. FPL Energy has entered into a 30-year long-term, binding firm
transportation contract with us for the full 325,000 dekatherms per day of
natural gas capacity on the North Texas pipeline.
The Mier-Monterrey pipeline stretches from south Texas to Monterrey, Mexico
and can transport up to 375,000 dekatherms per day of natural gas. We have
entered into a 15-year contract with Pemex Gas Y Petroquimica Basica, which has
subscribed for all of the capacity on the pipeline. The pipeline connects to a
1,000-megawatt power plant complex and to the Pemex natural gas transportation
system.
The segment's significant increases in period-to-period revenues and expenses
relate primarily to higher natural gas prices in the first quarter of 2003, and
to our January 31, 2002 acquisition of Kinder Morgan Tejas. The acquisition and
subsequent integration of its assets with our pre-existing natural gas pipeline
assets in the State of Texas, particularly our KMTP system, has produced a
strategic and complementary intrastate pipeline business combination. Both
Kinder Morgan Tejas and KMTP purchase and sell significant volumes of natural
gas, which is
45
transported through their pipeline systems. Our objective is to
match purchases and sales in the aggregate, thus locking-in the equivalent of a
transportation fee. The purchase and sale activity results in considerably
higher revenues and operating expenses compared to the interstate natural gas
pipeline systems of KMIGT and Trailblazer Pipeline Company. Both KMIGT and
Trailblazer charge a transportation fee for gas transmission service but neither
system has significant gas purchases and resales.
The overall increase in segment earnings was partially offset by higher
depreciation and amortization charges. Depreciation expenses totaled $12.6
million, up 11% from the $11.4 million reported in the first quarter of 2002.
The increase was due to the additional capital investments we have made since
the end of the first quarter of 2002 and to our acquisition of Kinder Morgan
Tejas.
Earnings from our Natural Gas Pipelines' equity investments, net of
amortization of excess costs, were essentially flat for the first quarter of
2003 compared to the first quarter of 2002. The segment's equity investments,
which include investments in Red Cedar, Thunder Creek Gas Services, LLC and
Coyote Gas Treating, LLC, reported $6.2 million in net equity earnings for the
first quarter of 2003 versus $6.1 million for the same prior year period. The
slight $0.1 million increase in equity earnings was mainly due to higher
earnings from the segment's 25% ownership interest in Thunder Creek.
CO2 Pipelines
Our CO2 Pipelines segment reported earnings of $29.7 million on revenues of
$48.5 million in the first three months of 2003. The segment reported earnings
of $21.4 million on revenues of $32.1 million in the same period of 2002.
Expenses, excluding depreciation, depletion, amortization, and taxes, other than
income taxes, totaled $14.5 million in the first quarter of 2003 versus $10.8
million in the first quarter of 2002. Operating income for each of the quarters
ended March 31, 2003 and 2002 was $20.2 million and $12.6 million, respectively.
The $8.3 million (39%) increase in period-to-period segment earnings was
primarily attributable to the $16.4 million (51%) increase in revenues,
partially offset by higher depreciation, depletion and operating expenses. The
increase in revenues was mainly due to higher oil production volumes and higher
average oil prices. The segment reported a 50% increase in oil production
volumes from its SACROC Unit and benefited from an 8% increase in our realized
weighted average hedged price of oil per barrel. The general increase in segment
revenues was partially offset by lower carbon dioxide delivery volumes,
primarily due to reduced deliveries from the McElmo Dome carbon dioxide Unit.
The overall increase in segment earnings was partially offset by higher
depreciation, depletion and amortization charges and by higher operations and
maintenance expenses. Non-cash depletion and depreciation-related charges were
up $4.6 million, mainly as a result of the higher production volumes and
additional capital investments that we have made since the end of the first
quarter of 2002. The $3.7 million period-to-period increase in expenses,
excluding depreciation, depletion, amortization, and taxes, other than income
taxes, was primarily due to the increase in oil production and to higher fuel
and power expenses as a result of higher production volumes.
In the first quarter of 2003, our CO2 Pipelines segment reported $9.5 million
in equity earnings, net of amortization of excess costs. The amount represents a
10% increase from the $8.6 million in equity earnings in the first quarter of
2002. The increase resulted from higher earnings from the segment's 15%
ownership interest in MKM Partners, L.P. MKM Partners, L.P., an oil and gas
joint venture with Marathon Oil Company, had higher earnings due to higher
average oil prices and higher production. Higher overall segment earnings were
also offset slightly by a $0.4 million increase in taxes, other than income
taxes, primarily the result of higher production taxes.
Terminals
Our Terminals segment, including both our bulk and liquids terminal
businesses, reported earnings of $49.0 million on revenues of $115.0 million in
the first quarter of 2003. In the first quarter of 2002, the segment earned
$40.9 million on revenues of $98.6 million. Expenses, excluding depreciation and
taxes, other than income taxes, for each of the quarters ended March 31, 2003
and 2002 were $52.7 million and $46.2 million, respectively. Operating income
for each of the quarters ended March 31, 2003 and 2002 was $50.2 million and
$42.7 million, respectively.
46
Excluding acquisitions, earnings increased $4.6 million and revenues increased
$7.1 million for the first quarter of 2003 compared to the same prior year
period. The favorable change was driven primarily by expansion projects that
have increased utilization and leaseable capacity at certain terminals, most
notably our Carteret, New Jersey and Harvey, Louisiana liquids terminals. Our
total leaseable capacity for liquids products increased 3% in the first quarter
of 2003 compared to the first quarter of 2002, and the increase resulted in a
$4.3 million increase in segment earnings and a $4.9 million increase in
revenues from liquids terminals that were owned in both periods.
First quarter earnings from all bulk terminal operations owned during each
year were essentially the same in 2003 versus 2002. Increases from an almost 4%
increase in coal transload volumes at our Grand Rivers, Kentucky and Cora,
Illinois coal terminals, as well as from strong fertilizer and soda ash exports
from bulk terminal facilities located on the West Coast were offset by a
quarter-to-quarter drop in engineering services.
Key acquisitions of terminal businesses since the end of the first quarter of
2002 accounted for $3.5 million of the $8.1 million (20%) increase in segment
earnings, and $9.3 million of the $16.4 million (17%) increase in segment
revenues. These acquisitions included:
o the Milwaukee Bagging Operations, acquired effective May 1, 2002;
o the Owensboro Gateway Terminal, acquired effective September 1, 2002;
o the St. Gabriel Terminal, acquired effective September 1, 2002;
o the purchase of four floating cranes at our bulk terminal facility in
Port Sulphur, Louisiana in December 2002; and
o the bulk terminal businesses acquired from M.J. Rudolph Corporation,
effective January 1, 2003.
The above acquisitions accounted for $5.3 million in expenses, excluding
depreciation and taxes, other than income taxes, in the first quarter of 2003.
Segment Operating Statistics
Operating statistics for the first three months of 2003 and 2002 are as
follows:
Three Months Ended
March 31, 2003 March 31, 2002
-------------- --------------
Products Pipelines
Gasoline (MMBbl)............................... 104.0 108.2
Diesel (MMBbl)................................. 36.0 35.5
Jet Fuel (MMBbl)............................... 26.6 27.3
--------- ---------
Total Refined Product Volumes (MMBbl).......... 166.6 171.0
Natural Gas Liquids (MMBbl).................... 12.8 11.1
--------- ---------
Total Delivery Volumes (MMBbl) (1)............. 179.4 182.1
Natural Gas Pipelines
Transport Volumes (Bcf) (2).................... 260.4 242.4
CO2 Pipelines
Delivery Volumes (Bcf) (3)..................... 102.3 113.1
SACROC Oil Production (MBbl/d) ................ 17.0 11.2
Realized Weighted Average Oil Price per Bbl.... $ 24.88 $ 22.98
Terminals
Bulk Terminals
Transload Tonnage (MMtons) (4).............. 14.0 14.2
Liquids Terminals
Leaseable Capacity (MMBbl).................. 35.6 34.5
Utilization %............................... 96% 97%
47
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, Texas Intrastates 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; excludes operatorship of LAXT bulk terminal.
Other
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. For the first
quarter of 2003, these items were offset by the $3.5 million cumulative-effect
adjustment related to our change in accounting for asset retirement obligations.
Together, these items (including the cumulative-effect adjustment) totaled $78.4
million in the first quarter of 2003 and $71.4 million in the first quarter of
2002.
Our general and administrative expenses totaled $34.7 million in the first
quarter of 2003 compared with $29.5 million in the first quarter of 2002. The
$5.2 million (18%) quarter-to-quarter increase in general and administrative
expenses primarily related to higher employee benefit costs, higher labor and
payroll tax expenses, and higher general expenses, mainly resulting from timing
differences in the payment of general services, including legal fees.
Our total interest expense, net of interest income, was $44.9 million in the
first quarter of 2003 and $39.0 million in the first quarter of 2002. The $5.9
million (15%) increase in net interest charges was due to higher average
borrowings during the first quarter of 2003 compared with the same period last
year. The increase in period-to-period net interest charges was partially offset
by lower average interest rates during the first quarter of 2003.
Minority interest totaled $2.2 million in the first quarter of 2003, compared
to $2.8 million in the first quarter of 2002. The $0.6 million (21%) decrease
resulted primarily from our acquisition of an additional ownership interest in
Trailblazer Pipeline Company. In May 2002, we acquired the remaining 33 1/3%
ownership interest in Trailblazer that we did not already own, thereby
eliminating the minority interest relating to Trailblazer Pipeline Company.
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):
March 31, Dec. 31,
2003 2002
----------- -----------
Long-term debt, excluding market value of
interest rate swaps................................ $ 3,787,234 $ 3,659,533
Minority interest.................................... 41,976 42,033
Partners' capital.................................... 3,425,554 3,415,929
___________ ___________
Total capitalization............................... 7,254,764 7,117,495
Short-term debt, less cash and cash equivalents...... (22,361) (41,088)
___________ ___________
Total invested capital............................. $ 7,232,403 $ 7,076,407
=========== ===========
Capitalization:
- --------------
Long-term debt, excluding market value of interest
rate swaps....................................... 52.2% 51.4%
Minority interest.................................. 0.6% 0.6%
Partners' capital.................................. 47.2% 48.0%
------ ------
100.0% 100.0%
====== ======
Invested Capital:
- ----------------
Total debt, less cash and cash equivalents and
excluding market value of interest rate swaps.... 52.1% 51.1%
Partners' capital and minority interest............ 47.9% 48.9%
------ ------
100.0% 100.0%
====== ======
48
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 KMR. In general, we
expect to fund:
o cash distributions and sustaining capital expenditures with existing cash
and cash flows from operating activities;
o expansion capital expenditures and working capital deficits with cash
retained as a result of paying quarterly distributions on i-units in
additional i-units, additional borrowings, the issuance of additional common
units or the issuance of additional i-units to KMR;
o interest payments from cash flows from operating activities; and
o debt principal payments with additional borrowings as such debt principal
payments become due or by the issuance of additional common units or the
issuance of additional i-units to KMR.
As a publicly traded limited partnership, our common units are attractive
primarily to individual investors. Individual investors represent a small
segment of the total equity capital market. We believe institutional investors
prefer shares of KMR over our common units due to tax and other regulatory
considerations. Thus, KMR makes purchases of i-units issued by us with the
proceeds from the sale of KMR shares to institutions.
As of March 31, 2003, our current commitments for sustaining capital
expenditures were approximately $77.8 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 2003 sustaining capital expenditure plan. All of our
capital expenditures, with the exception of sustaining capital expenditures, are
discretionary.
Some of our customers are experiencing severe financial problems that have had
a significant impact on their creditworthiness. We are working to implement, to
the extent allowable under applicable contracts, laws and regulations,
prepayments and other security requirements, such as letters of credit, to
enhance our credit position relating to amounts owed from these customers. We
cannot assure that one or more of our financially distressed customers will not
default on their obligations to us or that such a default or defaults will not
have a material adverse effect on our business, financial position or future
results of operations.
Operating Activities
Net cash provided by operating activities was $171.2 million for the three
months ended March 31, 2003, versus $222.6 million in the comparable period of
2002. The period-to-period decrease of $51.4 million in cash flow from
operations resulted chiefly from a $96.1 million decrease in cash inflows
relative to net changes in working capital items. The unfavorable working
capital change was primarily the result of timing differences in the collection
on and payments of our accounts receivables and payables and from changes in
customer prepayments of natural gas transportation revenues. Partially
offsetting the decrease in cash inflows due to net changes in working capital
items was a $33.3 million increase in cash earnings from across our business
portfolio and an $11.7 million increase in the amount of distributions we
received from our equity investments. The increase in equity investment
distributions related to higher distributions from our 50% equity interest in
Cortez Pipeline Company and from our 49% equity interest in the Red Cedar
Gathering Company.
Investing Activities
Net cash used in investing activities was $158.5 million for the three
month period ended March 31, 2003, compared to $849.3 million in the
comparable 2002 period. The $690.8 million decrease in cash used in
investing activities was primarily attributable to higher expenditures made
for strategic acquisitions in the 2002 period. For
49
the three months ended March 31, 2002, our acquisition outlays totaled $758.3
million, including $700.9 million for Kinder Morgan Tejas. For the three months
ended March 31, 2003, our asset acquisitions totaled $5.6 million, including
$3.5 million used to acquire the remaining 50% ownership interest in ICPT,
L.L.C., a small liquids pipeline limited liability company associated with our
St. Gabriel liquids terminal business. Other investing activities accounted for
$2.5 million of the overall decrease in cash used in investing activities in the
first quarter of 2003 compared to the first quarter of 2002. The decrease
related to higher cash inflows from changes in underground gas storage in the
first quarter of 2003.
Offsetting the overall period-to-period decrease in funds used in investing
activities was a $54.8 million increase in funds used for capital expenditures
and a $9.1 million increase in contributions to equity investments. Including
expansion and maintenance projects, our capital expenditures were $145.8 million
in the first three months of 2003 versus $91.0 million in the same year-ago
period. The increase was mainly due to our 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 and
carbon dioxide flooding operations. We plan to invest approximately $230 million
in additional development at the SACROC Unit in the Permian Basin of West Texas
during 2003. Our sustaining capital expenditures were $17.1 million for the
first three months of 2003 compared to $13.2 million for the first three months
of 2002. The increase in our contributions to equity investments related to an
$8.4 million contribution to Plantation Pipe Line Company in the first quarter
of 2003.
Financing Activities
Net cash used in financing activities amounted to $17.0 million for the three
months ended March 31, 2003. In the comparable quarter of 2002, our financing
activities provided $593.2 million. The decrease of $610.2 million from the
comparable 2002 period was mainly the result of lower cash inflows from overall
debt financing activities. The increase reflects higher net debt issuance in the
first quarter of 2002. In March 2002, we 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. In addition,
net borrowings under our commercial paper program were higher during the first
quarter of 2002 compared to the first quarter of 2003. The increase from net
borrowings was partially offset by the payment of our maturing $200 million in
principal amount of Floating Rate senior notes in March 2002.
The overall decrease in funds provided by our financing activities also
resulted from a $28.1 million increase in distributions to our partners.
Distribution to all partners increased to $160.4 million in the first quarter of
2003 compared to $132.3 million in the first quarter of 2002. 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 February 14, 2003, we paid a quarterly distribution of $0.625 per unit for
the fourth quarter of 2002, 14% greater than the $0.55 per unit distribution
paid for the fourth quarter of 2001. We paid this distribution in cash to our
common unitholders and to our class B unitholders. KMR, our sole i-unitholder,
received 858,981 additional i-units based on the $0.625 cash distribution per
common unit. For each outstanding i-unit that KMR held, a fraction (0.018815) of
an i-unit was issued. The fraction was determined by dividing:
o $0.625, the cash amount distributed per common unit
by
o $33.219, the average of KMR'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.
50
On April 16, 2003, we declared a cash distribution for the quarterly period
ended March 31, 2003, of $0.64 per unit. The distribution will be paid on or
before May 15, 2003, to unitholders of record as of April 30, 2003. Our common
unitholders and Class B unitholders will receive cash. KMR, our sole
i-unitholder, will receive a distribution of 0.018488 i-units for each
outstanding i-unit held based on the $0.64 distribution per common unit. We
believe that future operating results will continue to support similar levels of
quarterly cash and i-unit distributions; however, no assurance can be given that
future distributions will continue at such levels.
Partnership Distributions
Our partnership agreement requires that we distribute 100% of available cash,
as defined in our partnership agreement, to our partners within 45 days
following the end of each calendar quarter in accordance with their respective
percentage interests. Available cash consists generally of all of our cash
receipts, including cash received by our operating partnerships, less cash
disbursements and net additions to reserves (including any reserves required
under debt instruments for future principal and interest payments) and amounts
payable to the former general partner of SFPP, L.P. in respect of its remaining
0.5% interest in SFPP.
Our general partner is granted discretion by our partnership agreement, which
discretion has been delegated to KMR, 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 KMR 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 KMR, the sole owner of our i-units,
receives distributions in additional i-units. For each outstanding i-unit, a
fraction of an i-unit will be issued. The fraction is calculated by dividing the
amount of cash being distributed per common unit by the average closing price of
KMR'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 do not distribute cash to i-unit owners but 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
o fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units in
cash and to owners of i-units in the equivalent number of i-units, and 50%
to our general partner.
Incentive distributions are generally defined as all cash distributions paid
to our general partner that are in excess of 2% of the aggregate value of cash
and i-units being distributed. The general partner's incentive distribution for
51
the distribution that we declared for the first quarter of 2003 was $75.5
million. The general partner's incentive distribution for the distribution that
we declared for the first quarter of 2002 was $61.0 million. The general
partner's incentive distribution that we paid during the first quarter of 2003
to our general partner (for the fourth quarter of 2002) was $72.5 million. The
general partner's incentive distribution that we paid during the first quarter
of 2002 to our general partner (for the fourth quarter of 2001) was $54.4
million. All partnership distributions we declare for the fourth quarter of each
year are declared and paid in the first quarter of the following year.
Information Regarding Forward-Looking Statements
This filing includes forward-looking statements. These forward-looking
statements are identified as any statement that does not relate strictly to
historical or current facts. They use words such as "anticipate," "believe,"
"intend," "plan," "projection," "forecast," "strategy," "position," "continue,"
"estimate," "expect," "may," "will," or the negative of those terms or other
variations of them or comparable terminology. In particular, statements, express
or implied, concerning future actions, conditions or events, future operating
results or the ability to generate sales, income or cash flow or to make
distributions are forward-looking statements. Forward-looking statements are not
guarantees of performance. They involve risks, uncertainties and assumptions.
Future actions, conditions or events and future results of 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;
o economic activity, weather, alternative energy sources, conservation and
technological advances that may affect price trends and demand;
o changes in our tariff rates implemented by the Federal Energy Regulatory
Commission or the California Public Utilities Commission;
o our ability to integrate any acquired operations into our existing
operations;
o our ability to acquire new businesses and assets and to make expansions
to our facilities;
o difficulties or delays experienced by railroads, barges, trucks, ships or
pipelines in delivering products to our terminals or pipelines;
o our ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
o shut-downs or cutbacks at major refineries, petrochemical or chemical
plants, ports, utilities, military bases or other businesses that use or
supply our services;
o changes in laws or regulations, third party relations and approvals,
decisions of courts, regulators and governmental bodies may adversely affect
our business or our ability to compete;
o our ability to offer and sell equity securities and debt securities or
obtain debt financing in sufficient amounts to implement that portion of our
business plan that contemplates growth through acquisitions of operating
businesses and assets and expansions of our facilities;
o our indebtedness could make us vulnerable to general adverse economic and
industry conditions, limit our ability to borrow additional funds and/or
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;
52
o acts of nature, sabotage, terrorism or other similar acts causing damage
greater than our insurance coverage limits;
o the condition of the capital markets and equity markets in the United
States;
o the political and economic stability of the oil producing nations of the
world;
o national, international, regional and local economic, competitive and
regulatory conditions and developments;
o the ability to achieve cost savings and revenue growth;
o rates of inflation;
o interest rates;
o the pace of deregulation of retail natural gas and electricity;
o the timing and extent of changes in commodity prices for oil, natural
gas, electricity and certain agricultural products; and
o the timing and success of business development efforts.
You should not put undue reliance on any forward-looking statements.
See Items 1 and 2 "Business and Properties - Risk Factors" of our annual
report filed on Form 10-K for the year ended December 31, 2002, 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 2002 Form 10-K report. The
risk factors could cause our actual results to differ materially from those
contained in any forward-looking statement. We disclaim any obligation to update
the above list or to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments. Our future
results also could be adversely impacted by unfavorable results of litigation
and the coming to fruition of contingencies referred to in Note 3 to our
consolidated financial statements included elsewhere in this report.
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,
2002, in Item 7A of our 2002 Form 10-K report. For more information on our risk
management activities, see Note 10 to our consolidated financial statements
included elsewhere in this report.
Item 4. Controls and Procedures.
Within the 90-day period prior to the filing of this report, we carried out
an evaluation under the supervision and with the participation of our
management, including our Chief Executive Officer and Chief Financial Officer,
of the effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-14(c) under the Securities Exchange Act of 1934.
Based upon that evaluation, our Chief Executive Officer and Chief Financial
Officer concluded that the design and operation of our disclosure controls and
procedures were effective. No significant changes were made in our internal
controls or in other factors that could significantly affect these disclosure
controls and procedures subsequent to the date of their evaluation.
53
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.
11 --Statement re: computation of per share earnings.
99.1--Chief Executive Officer Certification.
99.2--Chief Financial Officer Certification.
- ---------------------
(b) Reports on Form 8-K
Current report dated January 15, 2003 on Form 8-K was furnished on January 16,
2003, pursuant to Items 7 and 9 of that form. In Item 9, we provided notice that
on January 15, 2003, we issued a press release announcing record earnings in
2002 and an increase in our quarterly distribution to unitholders. Our 2002 net
income totaled $608.4 million, up 38% over our 2001 net income of $442.3
million, and our cash distribution for the fourth quarter of 2002 was raised to
$0.625 per common unit, up 14% over our fourth quarter 2001 cash distribution of
$0.55 per common unit. A copy of the press release was filed in Item 7 as an
exhibit pursuant to Item 9.
Current report dated January 21, 2003 on Form 8-K was furnished on January
21, 2003, pursuant to Item 9 of that form. We provided notice that we, along
with Kinder Morgan, Inc., a subsidiary of which serves as our general partner,
and Kinder Morgan Management, LLC, a subsidiary of our general partner that
manages and controls our business and affairs, intended to make presentations on
January 22, 2003 at the Kinder Morgan 2003 Analyst Conference to address the
fiscal year 2002 results, the fiscal year 2003 outlook, and other business
information about 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,
54
Inc.'s website at: http://www.kindermorgan.com/investor/presentations/.
Interested parties would also be able to access the presentations by audio
webcast, both live and on-demand. Live webcast presentations could be accessed
at: http://www.videonewswire.com/event.asp?id=10577, by choosing the webcast
link and completing the registration page. The on-demand webcast (replay) for
the presentations would be available within 24 hours of the actual presentation,
would remain available for 45 days, and could also be accessed at:
http://www.videonewswire.comevent.asp?id=10577.
Current Report dated May 5, 2003 on Form 8-K was filed on May 6, 2003,
pursuant to Item 5 of that form. We reported that on May 2, 2003 we were
notified by the staff of the SEC that the staff is conducting an informal
investigation concerning our public disclosures regarding the allocation of
purchase price between assets and goodwill in connection with our acquisition of
the assets of Tejas Gas, LLC. The staff has not asserted that we acted
improperly or illegally, and has indicated that the Commission has not issued a
formal order. We have voluntarily agreed to cooperate fully with the staff's
informal investigation. We believe that the informal investigation will not
result in a material change to our financial statements.
55
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
KINDER MORGAN ENERGY PARTNERS, L.P.
(A Delaware limited partnership)
By: KINDER MORGAN G.P., INC.,
its General Partner
By: KINDER MORGAN MANAGEMENT, LLC,
its Delegate
/s/ C. Park Shaper
------------------------------
C. Park Shaper
Vice President, Treasurer and Chief Financial Officer
of Kinder Morgan Management, LLC, Delegate of Kinder
Morgan G.P., Inc. (principal financial officer and
principal accounting officer)
Date: May 14, 2003
56
CERTIFICATIONS
I, Richard D. Kinder, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Kinder Morgan Energy
Partners, L.P.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
/s/ Richard D. Kinder
------------------------------
Richard D. Kinder
Chairman and Chief Executive Officer
Date: May 14, 2003
57
I, C. Park Shaper, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Kinder Morgan Energy
Partners, L.P.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
/s/ C. Park Shaper
------------------------------
C. Park Shaper
Vice President, Treasurer and Chief Financial Officer
Date: May 14, 2003
58