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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 September 30, 2004
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 140,048,308 common units outstanding at October 31, 2004.
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 and Nine Months Ended September 30, 3
2004 and 2003....................................................................
Consolidated Balance Sheets - September 30, 2004 and December 31, 2003........... 4
Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2004 5
and 2003.........................................................................
Notes to Consolidated Financial Statements....................................... 6
Item 2: Management's Discussion and Analysis of Financial Condition and Results of 47
Operations..........................................................................
Critical Accounting Policies and Estimates....................................... 47
Results of Operations............................................................ 47
Financial Condition.............................................................. 57
Information Regarding Forward-Looking Statements................................. 62
Item 3: Quantitative and Qualitative Disclosures About Market Risk.......................... 63
Item 4: Controls and Procedures............................................................. 63
` PART II. OTHER INFORMATION
Item 1: Legal Proceedings................................................................... 64
Item 2: Unregistered Sales of Equity Securities and Use of Proceeds......................... 64
Item 3: Defaults Upon Senior Securities..................................................... 64
Item 4: Submission of Matters to a Vote of Security Holders................................. 64
Item 5: Other Information................................................................... 64
Item 6: Exhibits............................................................................ 64
Signatures.......................................................................... 66
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 Nine Months Ended
September 30 , September 30,
----------------------------- ---------------------------
2004 2003 2004 2003
------------- ------------- ------------- -----------
Revenues
Natural gas sales............................................... $ 1,485,585 $ 1,209,888 $ 4,261,372 $ 3,827,246
Services........................................................ 389,794 344,826 1,142,215 1,026,655
Product sales and other......................................... 139,280 96,128 390,510 250,226
--------- --------- --------- ---------
2,014,659 1,650,842 5,794,097 5,104,127
--------- --------- --------- ---------
Costs and Expenses
Gas purchases and other costs of sales.......................... 1,475,241 1,212,200 4,231,876 3,822,989
Operations and maintenance...................................... 116,807 96,818 347,396 289,602
Fuel and power.................................................. 39,109 29,476 110,621 78,393
Depreciation, depletion and amortization........................ 72,214 55,031 209,623 158,594
General and administrative...................................... 37,816 36,818 125,527 108,544
Taxes, other than income taxes.................................. 20,636 15,534 59,712 46,326
--------- --------- --------- ---------
1,761,823 1,445,877 5,084,755 4,504,448
--------- --------- --------- ---------
Operating Income.................................................. 252,836 204,965 709,342 599,679
Other Income (Expense)
Earnings from equity investments................................ 20,645 20,841 61,723 67,764
Amortization of excess cost of equity investments............... (1,394) (1,394) (4,182) (4,182)
Interest, net................................................... (46,365) (44,714) (140,178) (134,535)
Other, net...................................................... 149 972 403 2,757
Minority Interest................................................. (2,789) (2,591) (7,332) (6,930)
--------- --------- --------- ---------
Income Before Income Taxes and Cumulative Effect of a Change in
Accounting Principle........................................... 223,082 178,079 619,776 524,553
Income Taxes...................................................... (5,740) (3,903) (15,462) (14,407)
---------- ---------- ---------- ----------
Income Before Cumulative Effect of a Change in Accounting Principle 217,342 174,176 604,314 510,146
Cumulative effect adjustment from change in accounting for asset
retirement obligations......................................... - - - 3,465
--------- --------- --------- ---------
Net Income........................................................ $ 217,342 $ 174,176 $ 604,314 $ 513,611
========= ========= ========= =========
Calculation of Limited Partners' interest in Net Income:
Income Before Cumulative Effect of a Change in Accounting Principle $ 217,342 $ 174,176 $ 604,314 $ 510,146
Less: General Partner's interest.................................. (100,320) (82,727) (287,851) (239,682)
---------- ---------- ---------- ----------
Limited Partners' interest...................................... 117,022 91,449 316,463 270,464
Add: Limited Partners' interest in Change in Accounting Principle. - - - 3,430
--------- --------- --------- ---------
Limited Partners' interest in Net Income........................ $ 117,022 $ 91,449 $ 316,463 $ 273,894
========= ========= ========= =========
Basic and Diluted Limited Partners' Net Income per Unit:
Income Before Cumulative Effect of a Change in Accounting Principle $ 0.59 $ 0.49 $ 1.62 $ 1.47
Cumulative effect adjustment from change in accounting for asset
retirement obligations......................................... - - - 0.02
--------- --------- --------- ----------
Net Income........................................................ $ 0.59 $ 0.49 $ 1.62 $ 1.49
========= ========= ========= =========
Weighted average number of units used in computation of Limited
Partners' Net Income per unit:
Basic............................................................. 196,854 187,813 195,112 184,285
========= ========= ========= =========
Diluted........................................................... 196,937 187,912 195,196 184,400
========= ========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
3
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
September 30, December 31,
2004 2003_
------------- -------------
Assets
Current Assets
Cash and cash equivalents......................... $ 6,426 $ 23,329
Accounts, notes and interest receivable, net
Trade........................................... 603,618 563,012
Related parties................................. 23,269 27,587
Inventories
Products........................................ 12,289 7,214
Materials and supplies.......................... 10,763 10,783
Gas imbalances
Trade........................................... 19,976 36,449
Related parties................................. 1,625 9,084
Gas in underground storage........................ 1,397 8,160
Other current assets.............................. 32,142 19,904
------------- -------------
711,505 705,522
------------- -------------
Property, Plant and Equipment, net................... 7,603,851 7,091,558
Investments.......................................... 410,395 404,345
Notes receivable
Trade........................................... 2,422 2,422
Related parties................................. 95,210 -
Goodwill............................................. 726,470 729,510
Other intangibles, net............................... 14,259 13,202
Deferred charges and other assets.................... 219,729 192,623
------------- -------------
Total Assets......................................... $ 9,783,841 $ 9,139,182
============= =============
Liabilities and Partners' Capital
Current Liabilities
Accounts payable
Trade........................................... $ 532,545 $ 477,783
Related parties................................. 11,215 -
Current portion of long-term debt................. - 2,248
Accrued interest.................................. 25,710 52,356
Accrued taxes..................................... 54,177 20,857
Deferred revenues................................. 8,559 10,752
Gas imbalances.................................... 35,827 49,912
Accrued other current liabilities................. 364,530 190,471
------------- -------------
1,032,563 804,379
------------- -------------
Long-Term Liabilities and Deferred Credits
Long-term debt, outstanding....................... 4,616,724 4,316,678
Market value of interest rate swaps............... 123,367 121,464
------------- -------------
4,740,091 4,438,142
Deferred revenues................................. 16,013 20,975
Deferred income taxes............................. 40,213 38,106
Asset retirement obligations...................... 36,071 34,898
Other long-term liabilities and deferred credits.. 472,636 251,691
------------- -------------
5,305,024 4,783,812
Commitments and Contingencies (Note 3)
Minority Interest.................................... 39,877 40,064
------------- -------------
Partners' Capital
Common Units...................................... 2,122,346 1,946,116
Class B Units..................................... 118,149 120,582
i-Units........................................... 1,610,894 1,515,659
General Partner................................... 96,819 84,380
Accumulated other comprehensive loss.............. (541,831) (155,810)
------------- -------------
3,406,377 3,510,927
Total Liabilities and Partners' Capital.............. $ 9,783,841 $ 9,139,182
============= =============
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
(Increase/(Decrease) in Cash and Cash Equivalents In Thousands)
(Unaudited)
Nine Months Ended
September 30,
2004 2003
--------------- ----------
Cash Flows From Operating Activities
Net income............................................................................. $ 604,314 $ 513,611
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect adj. from change in accounting for asset retirement obligations.... -- (3,465)
Depreciation, depletion and amortization............................................. 209,623 158,594
Amortization of excess cost of equity investments.................................... 4,182 4,182
Earnings from equity investments..................................................... (61,723) (67,764)
Distributions from equity investments.................................................. 49,425 61,084
Changes in components of working capital............................................... 41,568 (107,284)
FERC rate reparations and refunds...................................................... - (44,944)
Other, net............................................................................. (9,519) (6,760)
------------ ------------
Net Cash Provided by Operating Activities............................................ 837,870 507,254
------------ ------------
Cash Flows From Investing Activities
Acquisitions of assets................................................................. (142,534) (40,714)
Acquisitions of investments............................................................ - (10,000)
Additions to property, plant and equip. for expansion and maintenance projects......... (565,231) (413,228)
Sale of investments, property, plant and equipment, net of removal costs............... 859 2,118
Contributions to equity investments.................................................... (7,000) (11,210)
Other.................................................................................. 730 8,904
------------ ------------
Net Cash Used in Investing Activities................................................ (713,176) (464,130)
------------ ------------
Cash Flows From Financing Activities
Issuance of debt....................................................................... 4,410,926 3,162,365
Payment of debt........................................................................ (4,123,527) (2,880,518)
Loans to related party................................................................. (97,223) --
Debt issue costs....................................................................... (2,152) (1,119)
Proceeds from issuance of common units................................................. 238,075 175,336
Proceeds from issuance of i-units...................................................... 14,925 --
Contributions from General Partner..................................................... 3,641 1,764
Distributions to partners:
Common units......................................................................... (287,677) (252,011)
Class B units........................................................................ (11,052) (10,175)
General Partner...................................................................... (275,412) (231,186)
Minority interest.................................................................... (7,221) (7,345)
Other, net............................................................................. (4,900) 1,122
------------ ------------
Net Cash Used in Financing Activities................................................ (141,597) (41,767)
------------- -------------
(Decrease)/Increase in Cash and Cash Equivalents....................................... (16,903) 1,357
Cash and Cash Equivalents, beginning of period......................................... 23,329 41,088
------------ ------------
Cash and Cash Equivalents, end of period............................................... $ 6,426 $ 42,445
============ ============
Noncash Investing and Financing Activities:
Assets acquired by the assumption of liabilities..................................... $ 13,932 $ 1,978
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. and its
consolidated subsidiaries. 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 which are solely
normal and recurring 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, 2003.
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.
2. Acquisitions and Joint Ventures
During the first nine months of 2004, 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
6
allocation of assets and liabilities may be adjusted to reflect the final
determined amounts during a short period of time following the acquisition. The
results of operations from these acquisitions are included in our consolidated
financial statements from the acquisition date.
Allocation of Purchase Price
------------------------------------------------------------------
Property Deferred
Purchase Current Plant & Charges Minority
Ref. Date Acquisition Price Assets Equipment & Other Interest
------ --------- --------------------------------------------- -------------- ---------- -------------- ------------ -----------
(in millions)
(1) 11/03 Yates Field Unit and Carbon Dioxide Assets... $ 259.9 $ 3.6 $ 256.6 $ - $(0.3)
(2) 12/03 ConocoPhillips Products Terminals............ 15.3 - 14.3 1.0 -
(3) 12/03 Tampa, Florida Bulk Terminals................ 29.1 - 29.1 - -
(4) 3/04 ExxonMobil Products Terminals................ 50.9 - 50.9 - -
(5) 8/04 Kinder Morgan Wink Pipeline, L.P............. $ 100.9 $ 0.2 $ 100.7 $ - $ -
(1) Yates Field Unit and Carbon Dioxide Assets
Effective November 1, 2003, we acquired certain assets in the Permian Basin
of West Texas from a subsidiary of Marathon Oil Corporation. Our purchase price
was approximately $259.9 million, consisting of $230.2 million in cash and the
assumption of $29.7 million of liabilities. The assets acquired consisted of the
following:
o Marathon's approximate 42.5% interest in the Yates oil field unit. We
previously owned a 7.5% ownership interest in the Yates field unit and we
now operate the field;
o Marathon's 100% interest in the crude oil gathering system surrounding the
Yates field unit; and
o Kinder Morgan Carbon Dioxide Transportation Company, formerly Marathon
Carbon Dioxide Transportation Company. Kinder Morgan Carbon Dioxide
Transportation Company owns a 65% ownership interest in the Pecos Carbon
Dioxide Pipeline Company, which owns a 25-mile carbon dioxide pipeline. We
previously owned a 4.27% ownership interest in the Pecos Carbon Dioxide
Pipeline Company and accounted for this investment under the cost method of
accounting. After the acquisition of our additional 65% interest in Pecos,
its financial results are included in our consolidated results and we
recognize the appropriate minority interest.
Together, the acquisition of these assets complemented our existing carbon
dioxide assets in the Permian Basin, increased our working interest in the Yates
field to nearly 50% and allowed us to become the operator of the field. We
recorded our final purchase price adjustment in the third quarter of 2004; we
recorded a deferred tax liability of $0.8 million in August 2004 to properly
reflect the tax obligations of Kinder Morgan Carbon Dioxide Transportation
Company. The acquired operations are included as part of our CO2 business
segment.
(2) ConocoPhillips Products Terminals
Effective December 11, 2003, we acquired seven refined petroleum products
terminals in the southeastern United States from ConocoPhillips Company and
Phillips Pipe Line Company. Our purchase price was approximately $15.3 million,
consisting of approximately $14.1 million in cash and $1.2 million in assumed
liabilities. The terminals are located in Charlotte and Selma, North Carolina;
Augusta and Spartanburg, South Carolina; Albany and Doraville, Georgia; and
Birmingham, Alabama. We fully own and operate all of the terminals except for
the Doraville, Georgia facility, which is operated and owned 70% by Citgo. As of
our acquisition date, we expected to invest an additional $1.3 million in the
facilities. Combined, the terminals have 35 storage tanks with total capacity of
approximately 1.15 million barrels for gasoline, diesel fuel and jet fuel. As
part of the transaction, ConocoPhillips entered into a long-term contract to use
the terminals. The contract consists of a five-year terminaling agreement, an
intangible asset which we valued at $1.0 million. The acquisition broadened our
refined petroleum products operations in the southeastern United States as three
of the terminals are connected to the Plantation pipeline system, which is
operated and owned 51% by us. The acquired operations are included as part of
our Products Pipelines business segment.
7
(3) Tampa, Florida Bulk Terminals
In December 2003, we acquired two bulk terminal facilities in Tampa, Florida
for an aggregate consideration of approximately $29.1 million, consisting of
$26.3 million in cash and $2.8 million in assumed liabilities. As of our
acquisition date, we expected to invest an additional $16.9 million in the
facilities. The principal facility purchased was a marine terminal acquired from
a subsidiary of The Mosaic Company, formerly IMC Global, Inc. We entered into a
long-term agreement with Mosaic pursuant to which Mosaic will be the primary
user of the facility, which we will operate and refer to as the Kinder Morgan
Tampaplex terminal. The terminal sits on a 114-acre site, and serves as a
storage and receipt point for imported ammonia, as well as an export location
for dry bulk products, including fertilizer and animal feed. We closed on the
Tampaplex portion of this transaction on December 23, 2003. The second facility
purchased was the former Nitram, Inc. bulk terminal, which we plan to use as an
inland bulk storage warehouse facility for overflow cargoes from our Port
Sutton, Florida import terminal. We closed on the Nitram portion of this
transaction on December 10, 2003. We recorded our final purchase price
adjustments in the third quarter of 2004. The adjustments included the removal
of a property tax liability in the amount of $0.6 million, which had been
established in December 2003 pending final determination of assumed tax
obligations. The acquired operations are included as part of our Terminals
business segment and complement our existing businesses in the Tampa area by
generating additional fee-based income.
(4) ExxonMobil Products Terminals
Effective March 9, 2004, we acquired seven refined petroleum products
terminals in the southeastern United States from Exxon Mobil Corporation. Our
purchase price was approximately $50.9 million, consisting of approximately
$48.2 million in cash and $2.7 million in assumed liabilities. The terminals are
located in Collins, Mississippi; Knoxville, Tennessee; Charlotte and Greensboro,
North Carolina; and Richmond, Roanoke and Newington, Virginia. Combined, the
terminals have a total storage capacity of approximately 3.2 million barrels for
gasoline, diesel fuel and jet fuel. As part of the transaction, ExxonMobil
entered into a long-term contract to store products at the terminals. As of our
acquisition date, we expected to invest an additional $1.2 million in the
facilities. The acquisition enhanced our terminal operations in the Southeast
and complemented our December 2003 acquisition of seven products terminals from
ConocoPhillips Company and Phillips Pipe Line Company. The acquired operations
are included as part of our Products Pipelines business segment.
(5) Kinder Morgan Wink Pipeline, L.P.
Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P. from KPL Pipeline Company, LLC and RHC Holdings,
L.P. for a purchase price of approximately $100.9 million, consisting of $90.9
million in cash and the assumption of approximately $10.0 million of
liabilities. We renamed the limited partnership Kinder Morgan Wink Pipeline,
L.P., and since August 31, 2004, we have included its results as part of our
consolidated financial statements under our CO2 business segment. The
acquisition included a 450-mile crude oil pipeline system, consisting of four
mainline sections, numerous gathering systems and truck off-loading stations.
The mainline sections, all in Texas, have a total capacity of 115,000 barrels of
crude oil per day. As part of the transaction, we entered into a long-term
throughput agreement with Western Refining Company, L.P. to transport crude oil
into Western's 107,000 barrel per day refinery in El Paso, Texas. As of our
acquisition date, we expected to invest approximately $11.0 million over the
next five years to upgrade the assets. The acquisition allows us to better
manage crude oil deliveries from our oil field interests in West Texas. Our
allocation of the purchase price to assets acquired and liabilities assumed is
preliminary, pending final purchase price adjustments that we expect to make by
the end of the first quarter of 2005 related to both working capital and other
adjustments specified by the purchase agreement.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement
information for the nine months ended September 30, 2004 and 2003, assumes that
all of the acquisitions we have made and joint ventures we have entered into
since January 1, 2003, including the ones listed above, had occurred as of the
beginning of the period presented. 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
8
completed these acquisitions and joint ventures as of the beginning of the
period presented or the results that will be attained in the future. Amounts
presented below are in thousands, except for the per unit amounts:
Pro Forma
Nine Months Ended September 30,
2004 2003
------------ ------------
(Unaudited)
Revenues................................................................ $ 5,808,364 $ 5,215,180
Operating Income........................................................ 714,276 661,412
Income Before Cumulative Effect of a Change in Accounting Principle..... 607,203 561,422
Net Income.............................................................. $ 607,203 $ 564,887
Basic and Diluted Limited Partners' Net Income per unit:
Income Before Cumulative Effect of a Change in Accounting Principle... $ 1.64 $ 1.74
Net Income............................................................ $ 1.64 $ 1.76
Subsequent Events
Effective October 6, 2004, we acquired Global Materials Services LLC for
approximately $70.9 million, consisting of $33.5 million in cash and $37.4
million of assumed liabilities. Global Materials Services LLC operates a network
of 21 river terminals and two rail transloading facilities primarily located
along the Mississippi River system. The network provides loading, storage and
unloading points for various bulk commodity imports and exports. As of our
acquisition date, we expected to invest an additional $9.4 million over the next
two years to expand and upgrade the terminals, which are located in 11
Mid-Continent states. The acquisition further expands and diversifies our
customer base and complements our existing terminal facilities located along the
lower-Mississippi River system. The acquired terminals will be included in our
Terminals business segment.
On October 13, 2004, we announced that Shell Trading (U.S.) Company had
assumed ownership of the processing rights at our transmix facilities located in
Richmond, Virginia; Indianola, Pennsylvania; and Wood River, Illinois. In a
transaction that closed on September 30, 2004, Shell Trading purchased the
eastern transmix trading business formerly owned by Duke Energy Merchants LLC,
which included a transmix processing agreement effective through March 16, 2011.
The arrangement also includes an opportunity to extend the processing agreement
beyond that date.
On October 18, 2004, we entered into a definitive agreement to purchase nine
refined petroleum products terminals in the southeastern United States from
Charter Terminal Company and Charter-Triad Terminals, LLC for approximately $75
million in cash and assumed liabilities. Three terminals, with a combined 3.2
million barrels of storage, are located in Selma, North Carolina, and the
remaining facilities are located in Greensboro and Charlotte, North Carolina;
Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta, South
Carolina. We will fully own seven of the terminals and jointly own the remaining
two. Following our acquisition, we expect to invest an additional $2 million
over the next two years to upgrade the facilities. All of the terminals are
connected to products pipelines owned by either Plantation Pipe Line Company or
Colonial Pipeline Company. The acquisition will complement the existing
terminals we own in the Southeast and will increase our southeast terminal
storage capacity 76% (to 7.7 million barrels) and terminal throughput 62% (to
over 340,000 barrels per day). We expect to close the transaction during the
fourth quarter and the acquired terminals will be included as part of our
Products Pipelines business segment.
3. Litigation and Other Contingencies
SFPP, L.P.
Federal Energy Regulatory Commission Proceedings
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.
9
OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a
consolidated proceeding that began in September 1992 and includes a number of
shipper complaints against certain rates and practices on SFPP's East Line (from
El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California
to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson
Station in Carson, California. The complainants in the case are El Paso
Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company,
Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products
Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing
Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.),
Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco
Corporation (now part of ConocoPhillips Company). The FERC has ruled that the
complainants have the burden of proof in those proceedings.
A FERC administrative law judge held hearings in 1996, and issued an initial
decision in September 1997. The initial decision held that all but one of SFPP's
West Line rates were "grandfathered" under the Energy Policy Act of 1992 and
therefore deemed to be just and reasonable; it further held that complainants
had failed to prove "substantially changed circumstances" with respect to those
rates and that they therefore could not be challenged in the Docket No. OR92-8
et al. proceedings, either for the past or prospectively. However, the initial
decision also made rulings generally adverse to SFPP on certain cost of service
issues relating to the evaluation of East Line rates, which are not
"grandfathered" under the Energy Policy Act. Those issues included the capital
structure to be used in computing SFPP's "starting rate base," the level of
income tax allowance SFPP may include in rates and the recovery of civil and
regulatory litigation expenses and certain pipeline reconditioning costs
incurred by SFPP. The initial decision also held SFPP's Watson Station gathering
enhancement service was subject to FERC jurisdiction and ordered SFPP to file a
tariff for that service.
The FERC subsequently reviewed the initial decision, and issued a series of
orders in which it adopted certain rulings made by the administrative law judge,
changed others and modified a number of its own rulings on rehearing. Those
orders began in January 1999, with FERC Opinion No. 435, and continued through
June 2003.
The FERC affirmed that all but one of SFPP's West Line rates are
"grandfathered" and that complainants had failed to satisfy the threshold burden
of demonstrating "substantially changed circumstances" necessary to challenge
those rates. The FERC further held that the one West Line rate that was not
grandfathered did not need to be reduced. The FERC consequently dismissed all
complaints against the West Line rates in Docket Nos. OR92-8 et al. without any
requirement that SFPP reduce, or pay any reparations for, any West Line rate.
The FERC initially modified the initial decision's ruling regarding the
capital structure to be used in computing SFPP's "starting rate base" to be more
favorable to SFPP, but later reversed that ruling. The FERC also made certain
modifications to the calculation of the income tax allowance and other cost of
service components, generally to SFPP's disadvantage.
On multiple occasions, the FERC required SFPP to file revised East Line rates
based on rulings made in the FERC's various orders. SFPP was also directed to
submit compliance filings showing the calculation of the revised rates, the
potential reparations for each complainant and in some cases potential refunds
to shippers. SFPP filed such revised East Line rates and compliance filings in
March 1999, July 2000, November 2001 (revised December 2001), October 2002 and
February 2003 (revised March 2003). Most of those filings were protested by
particular SFPP shippers. The FERC has held that certain of the rates SFPP filed
at the FERC's directive should be reduced retroactively and/or be subject to
refund; SFPP has challenged the FERC's authority to impose such requirements in
this context.
While the FERC initially permitted SFPP to recover certain of its litigation,
pipeline reconditioning and environmental costs, either through a surcharge on
prospective rates or as an offset to potential reparations, it ultimately
limited recovery in such a way that SFPP was not able to make any such surcharge
or take any such offset. Similarly, the FERC initially ruled that SFPP would not
owe reparations to any complainant for any period prior to the date on which
that party's complaint was filed, but ultimately held that each complainant
could recover reparations for a period extending two years prior to the filing
of its complaint (except for Navajo, which was limited to one month of
pre-complaint reparations under a settlement agreement with SFPP's predecessor).
The FERC also ultimately held that SFPP was not required to pay reparations or
refunds for Watson Station gathering enhancement fees charged prior to filing a
FERC tariff for that service.
10
In April 2003, SFPP paid complainants and other shippers reparations and/or
refunds as required by FERC's orders. In August 2003, SFPP paid shippers an
additional refund as required by FERC's most recent order in the Docket No.
OR92-8 et al. proceedings. We made aggregate payments of $44.9 million in 2003
for reparations and refunds pursuant to a FERC order.
Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond
Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for
review of FERC's Docket OR92-8 et al. orders in the United States Court of
Appeals for the District of Columbia Circuit. Certain of those petitions were
dismissed by the Court of Appeals as premature, and the remaining petitions were
held in abeyance pending completion of agency action. However, in December 2002,
the Court of Appeals returned to its active docket all petitions to review the
FERC's orders in the case through November 2001 and severed petitions regarding
later FERC orders. The severed orders were held in abeyance for later
consideration.
Briefing in the Court of Appeals was completed in August 2003, and oral
argument took place on November 12, 2003. On July 20, 2004, the U.S. Court of
Appeals for the District of Columbia Circuit issued an opinion affirming the
FERC orders under review on most issues, vacating the tax provision that the
FERC had allowed SFPP to include under the FERC's "Lakehead" policy giving a tax
allowance to partnership pipelines and remanding for further FERC proceedings on
other issues.
The court held that, in the context of the Docket No. OR92-8, et al.
proceedings, all of SFPP's West Line rates were grandfathered other than the
charge for use of SFPP's Watson Station gathering enhancement facility and the
rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded
that the FERC had a reasonable basis for concluding that the addition of a West
Line origin point at East Hynes, California did not involve a new "rate" for
purposes of the Energy Policy Act. It rejected arguments from West Line Shippers
that certain protests and complaints had challenged West Line rates prior to the
enactment of the Energy Policy Act.
The court also held that complainants had failed to satisfy their burden of
demonstrating substantially changed circumstances, and therefore could not
challenge grandfathered West Line rates in the Docket No. OR92-8 et al.
proceedings. It specifically rejected arguments that other shippers could
"piggyback" on the special Energy Policy Act exception permitting Navajo to
challenge grandfathered West Line rates, which Navajo had withdrawn under a
settlement with SFPP. The court remanded the changed circumstances issue "for
further consideration" by the FERC in light of the court's decision, described
below, regarding SFPP's tax allowance. The FERC has previously held in the
OR96-2 proceeding that the tax allowance policy should not be used as a
stand-alone factor in determining when there have been substantially changed
circumstances.
The court upheld the FERC's rulings on most East Line rate issues. However,
it found the FERC's reasoning inadequate on some issues, including the tax
allowance.
The court held the FERC had sufficient evidence to use SFPP's December 1988
stand-alone capital structure to calculate its starting rate base as of June
1985. It rejected SFPP arguments that would have resulted in a higher starting
rate base.
The court analyzed at length the tax allowance for pipelines that are
organized as partnerships. It concluded that the FERC had provided "no rational
basis" on the record before it for giving SFPP a tax allowance, and denied
recovery by SFPP of "income taxes not incurred and not paid."
The court accepted the FERC's treatment of regulatory litigation costs,
including the limitation of recoverable costs and their offset against
"unclaimed reparations" - that is, reparations that could have been awarded to
parties that did not seek them. The court also accepted the FERC's denial of any
recovery for the costs of civil litigation by East Line shippers against SFPP
based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix.
However, the court did not find adequate support for the FERC's decision to
allocate the limited litigation costs that SFPP was allowed to recover in its
rates equally between the East Line and the West Line, and ordered the FERC to
explain that decision further on remand.
The court held the FERC had failed to justify its decision to deny SFPP any
recovery of funds spent to
11
recondition pipe on the East Line, for which SFPP had spent nearly $6 million
between 1995 and 1998. It concluded that the Commission's reasoning was
inconsistent and incomplete, and remanded for further explanation, noting that
"SFPP's shippers are presently enjoying the benefits of what appears to be an
expensive pipeline reconditioning program without sharing in any of its costs."
The court affirmed the FERC's rulings on reparations in all respects. It held
the Arizona Grocery doctrine did not apply to orders requiring SFPP to file
"interim" rates, and that "FERC only established a final rate at the completion
of the OR92-8 proceedings." It held that the Energy Policy Act did not limit
complainants' ability to seek reparations for up to two years prior to the
filing of complaints against rates that are not grandfathered. It rejected
SFPP's arguments that the FERC should not have used a "test period" to compute
reparations, that it should have offset years in which there were
underrecoveries against those in which there were overrecoveries, and that it
should have exercised its discretion against awarding any reparations in this
case.
The court also rejected:
o Navajo's argument that its prior settlement with SFPP's predecessor did not
limit its right to seek reparations;
o Valero's argument that it should have been permitted to recover reparations
in the Docket No. OR92-8 et al. proceedings rather than waiting to seek
them, as appropriate, in the Docket No. OR96-2 et al. proceedings;
o arguments that the former ARCO and Texaco had challenged East Line rates
when they filed a complaint in January 1994 and should therefore be
entitled to recover East Line reparations; and
o Chevron's argument that its reparations period should begin two years
before its September 1992 protest regarding the six-inch line reversal
rather than its August 1993 complaint against East Line rates.
On September 2, 2004, BP West Coast Products, ChevronTexaco, ConocoPhillips
and ExxonMobil filed a petition for rehearing and rehearing en banc asking the
Court of Appeals to reconsider its ruling that West Line rates were not subject
to investigation at the time the Energy Policy Act was enacted. On September 3,
2004, SFPP filed a petition for rehearing asking the Court to confirm that the
FERC has the same discretion to address the income tax allowance issue on remand
that administrative agencies normally have when their decisions are set aside by
reviewing courts because they have failed to provide a reasoned basis for their
conclusions. On October 4, 2004, the Court of Appeals denied both petitions
without further comment.
We are continuing to review the potential impact of the Court of Appeals
decision and prepare for proceedings before the FERC on the issues that have
been remanded to it. In addition to participating in the FERC's proceedings on
remand, we may also seek review by the United States Supreme Court on one or
more issues.
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 claimed that the
rate for that service was unlawful. Several other West Line shippers filed
similar complaints and/or motions to intervene.
Following a hearing in March 1997, a FERC administrative law 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 pre-existing
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 set a hearing to determine
whether SFPP possessed market power in the origin market.
Following a hearing, on December 21, 2000, an administrative law judge found
that SFPP possessed market power over the Sepulveda origin market. On February
28, 2003, the FERC issued an order upholding that decision. SFPP filed a request
for rehearing of that order on March 31, 2003. The FERC denied SFPP's request
for rehearing on July 9, 2003.
12
As part of its February 28, 2003 order denying SFPP's application for
market-based ratemaking authority, the FERC remanded to the ongoing litigation
in Docket No. OR96-2, et al. the question of whether SFPP's current rate for
service on the Sepulveda line is just and reasonable. That issue is currently
pending before the administrative law judge in the Docket No. OR96-2, et al.
proceeding. The procedural schedule in this remanded matter was activated upon
the issuance of the phase two initial decision in the Docket No. OR96-2, et al.
proceeding (see below). A hearing in this proceeding is scheduled to commence on
February 15, 2005.
OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar Diamond
Shamrock Corporation 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 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 SFPP's
lines. The FERC accepted the complaints and consolidated them into one
proceeding (Docket No. OR96-2, et al.), but held 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. In August 2000, Navajo and Western 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. These complaints were consolidated 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. A FERC administrative law judge issued his initial decision on June 24,
2003. The initial decision found that, for the years at issue, the complainants
had shown substantially changed circumstances for rates on SFPP's West, North
and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson
Station and thus found that those rates should not be "grandfathered" under the
Energy Policy Act of 1992. The initial decision also found that most of SFPP's
rates at issue were unjust and unreasonable. The initial decision indicated that
a phase two initial decision will address prospective rates and whether
reparations are necessary.
SFPP filed a brief on exceptions to the FERC that contested the findings in
the initial decision. SFPP's opponents responded to SFPP's brief. On March 26,
2004, the FERC issued an order on the phase one initial decision. The FERC's
phase one order reversed the initial decision by finding that SFPP's rates for
its North and Oregon Lines should remain "grandfathered" and amended the initial
decision by finding that SFPP's West Line rates (i) to Yuma, Tucson and CalNev,
as of 1995, and (ii) to Phoenix, as of 1997, should no longer be "grandfathered"
and are not just and reasonable. The FERC's phase one order did not address
prospective West Line rates and whether reparations are necessary. As discussed
below, those issues have been addressed in the non-binding phase two initial
decision recently issued by the presiding administrative law judge. The FERC's
phase one order also did not address the "grandfathered" status of the Watson
Station fee, noting that it would address that issue once it was ruled on by the
United States Court of Appeals for the District of Columbia Circuit in its
review of the FERC's Opinion No. 435 orders. Several of the participants in the
proceeding requested rehearing of the FERC's phase one order. FERC action on
those requests is pending. In addition, several participants, including SFPP,
filed petitions with the United States Court of Appeals for the District of
Columbia Circuit for review of the FERC's phase one order. On August 13, 2004,
the FERC filed a motion to dismiss the pending petitions for review of the phase
one order. On August 30, 2004, Petitioners, including SFPP, filed answers to
that motion, which the FERC responded to on September 2, 2004. Court action on
those petitions and motions is pending.
The FERC's phase one order also held that SFPP failed to seek authorization
for the accounting entries necessary to reflect in SFPP's books, and thus in its
annual report to FERC ("FERC Form 6"), the purchase price adjustment ("PPA")
arising from SFPP's 1998 acquisition by us. The phase one order directed SFPP to
file for permission to reflect the PPA in its FERC Form 6 for the calendar year
1998 and each subsequent year. In its April 26, 2004
13
compliance filing, SFPP noted that it had previously requested such permission
and that the FERC's regulations require an oil pipeline to include a PPA in its
Form 6 without first seeking FERC permission to do so. Several parties protested
SFPP's compliance filing. SFPP answered those protests, and FERC action on this
matter is pending.
On September 9, 2004, the presiding administrative law judge issued his
non-binding initial decision in the phase two portion of this proceeding. If
affirmed by the FERC, the phase two initial decision would establish the basis
for prospective rates and the calculation of reparations for complaining
shippers with respect to the West Line and East Line. However, as with the phase
one initial decision, the phase two initial decision must be fully reviewed by
the FERC, which may accept, reject or modify the decision. Briefs on exceptions
to the phase two initial decision are due to be filed on November 2, 2004, and
briefs opposing exceptions are due to be filed on December 17, 2004. A FERC
order on phase two of the case is not expected before the second quarter of
2005. Any such order may be subject to further FERC review, review by the United
States Court of Appeals for the District of Columbia Circuit, or both.
Currently, 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. The final outcome will depend, in part, on the outcomes of the
appeals of these proceedings and the OR92-8, et al. proceedings taken by SFPP,
complaining shippers, and an intervenor.
We have estimated that shippers sought reparations of $154 million and
prospective rate reductions with an aggregate average annual impact of $45
million. Extending the assumed timing for implementation of rate reductions and
the payment of reparations has the effect of increasing total reparations and
the interest accruing on the reparations. For each calendar quarter of delay in
the implementation of rate reductions sought, we estimate that reparations and
accrued interest accumulates by approximately $9 million. We now assume that any
potential rate reductions will be implemented in the third quarter of 2005 and
that reparations and accrued interest thereon will be paid late in the third
quarter of 2006. If the phase two initial decision were to be largely adopted by
the FERC, the estimated reparations and rate reductions noted above would
increase modestly. We continue to estimate the combined annual impact of the
rate reductions and the capital costs associated with financing the payment of
reparations sought by shippers and accrued interest thereon to be approximately
15 cents of distributable cash flow per unit. We believe, however, that the
ultimate resolution of these complaints will be for amounts substantially less
than the amounts sought.
Chevron complaint OR02-4 proceedings. On February 11, 2002, Chevron, an
intervenor in the Docket No. OR96-2, et al. proceeding, filed a complaint
against SFPP in Docket No. OR02-4 along with a motion to consolidate the
complaint with the Docket No. OR96-2, et al. proceeding. On May 21, 2002, the
FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed a
request for rehearing, which the FERC dismissed on September 25, 2002. In
October 2002, Chevron filed a request for rehearing of the FERC's September 25,
2002 Order, which the FERC denied on May 23, 2003. On July 1, 2003, Chevron
filed a petition for review of this denial at the U.S. Court of Appeals for the
District of Columbia Circuit. On August 18, 2003, SFPP filed a motion to dismiss
Chevron's petition on the basis that Chevron lacks standing to bring its appeal
and that the case is not ripe for review. Chevron answered on September 10,
2003. SFPP's motion was pending, when the Court of Appeals, on December 8, 2003,
granted Chevron's motion to hold the case in abeyance pending the outcome of the
appeal of the Docket No. OR92-8, et al. proceeding. On January 8, 2004, the
Court of Appeals granted Chevron's motion to have its appeal of the FERC's
decision in Docket No. OR03-5 (see below) consolidated with Chevron's appeal of
the FERC's decision in the Docket No. OR02-4 proceeding. Chevron continues to
participate in the Docket No. OR96-2 et al. proceeding as an intervenor.
OR03-5 proceedings. On June 30, 2003, Chevron filed another complaint against
SFPP - substantially similar to its previous complaint - and moved to
consolidate the complaint with the Docket No. OR96-2, et al. proceeding. This
complaint was docketed as Docket No. OR03-5. Chevron requested that this new
complaint be treated as if it were an amendment to its complaint in Docket No.
OR02-4, which was previously dismissed by the FERC. By this request, Chevron
sought to, in effect, back-date its complaint, and claim for reparations, to
February 2002. SFPP answered Chevron's complaint on July 22, 2003, opposing
Chevron's requests for consolidation and for the back-dating of its complaint.
On October 28, 2003 , the FERC accepted Chevron's complaint, but held it in
abeyance pending the outcome of the Docket No. OR96-2, et al. proceeding. The
FERC denied Chevron's request for
14
consolidation and for back-dating. On November 21, 2003, Chevron filed a
petition for review of the FERC's October 28, 2003 Order at the Court of Appeals
for the District of Columbia Circuit. On January 8, 2004, the Court of Appeals
granted Chevron's motion to have its appeal consolidated with Chevron's appeal
of the FERC's decision in the Docket No. OR02-4 proceeding and to have the two
appeals held in abeyance pending the outcome of the appeal of the Docket No.
OR92-8, et al. proceeding. On August 13, 2004, the FERC filed a motion to
dismiss the pending petitions for review of the FERC's orders in the OR02-4 and
OR03-5 proceedings. SFPP filed a motion to dismiss Chevron's petitions for
review on August 18, 2004. Chevron answered those motions on August 30, 2004 and
the FERC responded to Chevron's answer on September 7, 2004. Court action in
these dockets is pending.
OR04-3 proceeding. On September 21, 2004, America West Airlines, Inc.,
Southwest Airlines, Co., Northwest Airlines, Inc. and Continental Airlines, Inc.
(collectively "Airlines") filed a complaint against SFPP at the FERC. The
Airlines' complaint alleges that the rates on SFPP's West Line and SFPP's charge
for its gathering enhancement service at Watson Station are not just and
reasonable. The Airlines seek rate reductions and reparations for two years
prior to the filing of their complaint. SFPP answered the Airlines' complaint on
October 12, 2004. FERC action on the complaint is pending.
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
resolution of these submitted matters is anticipated within the fourth quarter
of 2004.
The CPUC subsequently 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 required SFPP to submit cost data for
2001, 2002, and 2003, and 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,
were the subject of evidentiary hearings conducted in December 2003 and may be
resolved by the CPUC in the fourth quarter of 2004.
15
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. With regard to 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, such refunds could
total about $6 million per year from October 2002 to the anticipated date of a
CPUC decision during the fourth quarter of 2004.
SFPP believes the submission of the required, representative cost data
required by the CPUC indicates 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, results of operations or
cash flows.
Trailblazer Pipeline Company
Rate Case
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 a number of non-rate tariff changes. By
an order issued December 31, 2002, the FERC effectively bifurcated the
proceeding. The FERC accepted the rate decrease effective January 1, 2003,
subject to refund and a hearing. The FERC suspended most of the non-rate tariff
changes until June 1, 2003, subject to refund and a technical conference
procedure.
Trailblazer sought rehearing of the FERC rate decrease order with respect to
the refund condition. On April 15, 2003, the FERC granted Trailblazer's
rehearing request to remove the refund condition that had been imposed in the
FERC's December 31, 2002 order. Certain intervenors have sought rehearing as to
the FERC's acceptance of certain non-rate tariff provisions.
The technical conference on non-rate tariff issues was held on February 6,
2003. The non-rate tariff 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 the non-rate tariff issues as discussed at the technical
conference were filed by parties in March 2003. On May 23, 2003, the FERC issued
an order deciding non-rate tariff issues and denying rehearing of its prior
order. In the May 23, 2003 order, the FERC:
o accepted Trailblazer's proposed capacity award procedures with very limited
changes;
o accepted Trailblazer's credit procedures subject to very extensive changes,
consistent with numerous recent orders involving other pipelines;
o accepted a compromise agreed to by Trailblazer and the active parties under
which existing shippers must match competing bids in the right of first
refusal process for up to ten years (in lieu of the current five years);
and
o accepted Trailblazer's withdrawal of daily imbalance charges.
More specifically, the May 23, 2003 order:
16
o allowed shortened notice periods for suspension of service, but required at
least thirty days notice for service termination;
o limited prepayments and any other assurance of future performance, such as
a letter of credit, to three months of service charges except for new
facilities;
o required the pipeline to pay interest on prepayments or allow those funds
to go into an interest-bearing escrow account; and
o required much more specificity about credit criteria and procedures in
tariff provisions.
Certain shippers and Trailblazer sought rehearing of the May 23, 2003 order.
Trailblazer made its compliance filing on June 20, 2003. The tariff changes
under the May 23, 2003 order were made effective as of May 23, 2003, except that
Trailblazer filed to make the revised credit procedures effective August 15,
2003. In an order issued July 13, 2004, the FERC accepted Trailblazer's
compliance filing of June 20, 2003, but required some minor changes, and denied
the rehearing requests.
With respect to the rate review portion of the case, direct testimony was
filed by the FERC Staff and the Indicated Shippers on May 22, 2003 and
cross-answering testimony was filed by the Indicated Shippers on June 19, 2003.
Trailblazer's answering testimony was filed on July 29, 2003.
On September 22, 2003, Trailblazer filed an offer of settlement with the FERC
with respect of the rate review portion of the case. Under the settlement,
Trailblazer's rate would be reduced effective January 1, 2004, from $0.12 to
$0.09 per dekatherm of natural gas, and Trailblazer would file a new rate case
to be effective January 1, 2010.
On January 23, 2004, the FERC issued an order approving, with modification,
the settlement that was filed on September 22, 2003. The FERC modified the
settlement to expand the scope of severance of contesting parties to present and
future direct interests, including capacity release agreements. The settlement
had provided the scope of the severance to be limited to present direct
interests. On February 20, 2004, Trailblazer filed a letter with the FERC
accepting the modifications to the settlement. As of March 1, 2004, all members
of the Indicated Shippers group opposing the settlement had filed to withdraw
their opposition. On April 9, 2004, the FERC accepted tariff sheets setting out
the settlement rates and, recognizing that the settlement is now unopposed,
dismissed the pending initial decision on Trailblazer's rates as moot. The
settlement rates were put into effect January 1, 2004. On March 26, 2004,
Trailblazer refunded approximately $0.9 million to shippers covering the period
January 1, 2004 through February 29, 2004 pursuant to the terms of the rate case
settlement. On July 13, 2004, the FERC issued an order requiring Trailblazer to
refund additional amounts to shippers previously contesting the settlement.
Trailblazer issued these additional refunds, totaling approximately $73,000 on
July 23, 2004.
Fuel Tracking Filing
On March 31, 2004, Trailblazer made its annual filing to revise its fuel
tracker percentage (its fuel rate) applicable to its expansion shippers. In the
filing, Trailblazer proposed to reduce its fuel rate from the previous level of
2.0% to 1.57%. On April 12, 2004, Marathon Oil Company filed a protest stating
that Trailblazer overstated projected volumes at the Station 601 compressor
facility and proposed that the volumes at the station be reduced, which would
result in a reduction of the fuel rate to 1.20%. On April 30, 2004, the FERC
issued an order allowing Trailblazer to place its proposed 1.57% fuel rate into
effect, subject to refund, on May 1, 2004. The order also established a comment
procedure, pursuant to which Trailblazer filed comments supporting its proposal
on May 20, 2004 and Marathon filed reply comments on June 1, 2004. On July 9,
2004, the FERC issued an order adopting Marathon's position. Trailblazer
implemented the 1.20% fuel rate on August 1, 2004. In addition, in September
2004, Trailblazer refunded approximately $600,000 to affected shippers for the
period May 1, 2004 to July 31, 2004; the period in which Trailblazer's rejected
fuel rate was billed to shippers.
FERC Order 637
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:
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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 rights of first refusal, but 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's October 15, 2001 order 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 its compliance filing subject to modifications.
Trailblazer made those modifications in a compliance filing submitted to the
FERC on May 16, 2003. On March 24, 2004, the FERC issued an order directing
Trailblazer to make relatively minor changes to its filing of May 16, 2003.
Trailblazer submitted its compliance filing on April 8, 2004. The FERC issued
an order accepting the April 8, 2004 filing on August 5, 2004. Under the FERC's
orders, limited aspects of Trailblazer's plan (revenue crediting) were
effective as of May 1, 2003. The entire Order No. 637 plan went into effect on
December 1, 2003.
Trailblazer anticipates no adverse impact on its business as a result of the
implementation of Order No. 637.
Standards of Conduct Rulemaking
FERC Order No. 2004
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 Kinder Morgan Interstate Gas Transmission LLC,
Trailblazer and their respective affiliates. In addition, the Notice could be
read to require separate staffing of Kinder Morgan Interstate Gas Transmission
LLC and its affiliates, and Trailblazer and its affiliates. Comments on the
Notice of Proposed Rulemaking were due December 20, 2001. Numerous parties,
including Kinder Morgan Interstate Gas Transmission LLC, 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, Kinder Morgan Interstate Gas Transmission
LLC and numerous other parties filed additional written comments under a
procedure adopted at the technical conference.
On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards
of Conduct to become effective February 9, 2004. Every interstate natural gas
pipeline was required to file a compliance plan by that date and was required to
be in full compliance with the Standards of Conduct by June 1, 2004. The primary
change from existing regulation is to make such standards applicable to an
interstate natural gas pipeline's interaction with many more affiliates
(referred to as "energy affiliates"), including intrastate/Hinshaw natural gas
pipelines (in general, a Hinshaw pipeline is a pipeline that receives gas at or
within a state boundary, is regulated by an agency of that state, and all the
gas it transports is consumed within that state), processors and gatherers and
any company involved in natural gas or electric markets (including natural gas
marketers) even if they do not ship on the affiliated interstate
18
natural gas pipeline. Local distribution companies are excluded, however, if
they do not make sales to customers not physically attached to their system. The
Standards of Conduct require, among other things, separate staffing of
interstate pipelines and their energy affiliates (but support functions and
senior management at the central corporate level may be shared) and strict
limitations on communications from an interstate pipeline to an energy
affiliate.
Kinder Morgan Interstate Gas Transmission LLC filed for clarification and
rehearing of Order No. 2004 on December 29, 2003. In the request for rehearing,
Kinder Morgan Interstate Gas Transmission LLC asked that intrastate/Hinshaw
pipeline affiliates not be included in the definition of energy affiliates. On
February 19, 2004, Kinder Morgan Interstate Gas Transmission LLC and Trailblazer
Pipeline Company filed exemption requests with the FERC. The pipelines seek a
limited exemption from the requirements of Order No. 2004 for the purpose of
allowing their affiliated Hinshaw and intrastate pipelines, which are subject to
state regulation and do not make any sales to customers not physically attached
to their system, to be excluded from the rule's definition of energy affiliate.
Separation from these entities would be the most burdensome requirement of the
new rules for us.
On April 16, 2004, the FERC issued Order No. 2004-A. The FERC extended the
effective date of the new Standards of Conduct from June 1, 2004, to September
1, 2004. Otherwise, the FERC largely denied rehearing of Order No. 2004, but
provided further clarification or adjustment in several areas. The FERC
continued the exemption for local distribution companies which do not make
off-system sales, but clarified that the local distribution company exemption
still applies if the local distribution company is also a Hinshaw pipeline. The
FERC also clarified that a local distribution company can engage in certain
sales and other energy affiliate activities to the limited extent necessary to
support sales to customers located on its distribution system, and sales
necessary to remain in balance under pipeline tariffs, without becoming an
energy affiliate. The FERC declined to exempt natural gas producers. The FERC
also declined to exempt natural gas intrastate and Hinshaw pipelines, processors
and gatherers, but did clarify that such entities will not be energy affiliates
if they do not participate in gas or electric commodity markets, interstate
capacity markets (as capacity holder, agent or manager), or in financial
transactions related to such markets.
The FERC also clarified further the personnel and functions which can be
shared by interstate natural gas pipelines and their energy affiliates,
including senior officers and risk management personnel, and the permissible
role of holding or parent companies and service companies. The FERC also
clarified that day-to-day operating information can be shared by interconnecting
entities. Finally, the FERC clarified that an interstate natural gas pipeline
and its energy affiliate can discuss potential new interconnects to serve the
energy affiliate, but subject to very onerous posting and record-keeping
requirements.
On July 21, 2004, Kinder Morgan Interstate Gas Transmission LLC and
Trailblazer Pipeline Company filed additional joint requests with the interstate
natural gas pipelines owned by KMI asking for limited exemptions from certain
requirements of FERC Order 2004 and asking for an extension of the deadline for
full compliance with Order 2004 until 90 days after the FERC has completed
action on the pipelines' various rehearing and exemption requests. These
exemptions request relief from the independent functioning and information
disclosure requirements of Order 2004. The exemption requests propose to treat
as energy affiliates, within the meaning of Order 2004, two groups of employees:
o individuals in the Choice Gas Commodity Group within KMI's retail
operations; and
o commodity sales and purchase personnel within our Texas intrastate natural
gas operations.
Order 2004 regulations governing relationships between interstate pipelines
and their energy affiliates would apply to relationships with these two groups.
Under these proposals, certain critical operating functions could continue to be
shared.
On August 2, 2004, the FERC issued Order No. 2004-B. In this order, the FERC
extended the effective date of the new Standards of Conduct from September 1,
2004 to September 22, 2004. Also in this order, among other actions, the FERC
denied the request for rehearing made by the interstate pipelines of KMI and us
to clarify the applicability of the local distribution company and parent
company exemptions to them. In addition, the FERC denied the interstate
pipelines' request for a 90 day extension of time to comply with Order 2004.
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On September 20, 2004, the FERC issued an order which conditionally granted
the July 21, 2004 joint requests for limited exemptions from the requirements of
the Standards of Conduct described above. In that order, FERC directed Kinder
Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company and the
affiliated interstate pipelines owned by KMI to submit compliance plans
regarding these exemptions within 30 days. These compliance plans were filed on
October 19, 2004, and set out certain steps taken by us to assure that employees
in the Choice Gas Commodity Group of KMI and the commodity sales and purchase
personnel of our Texas intrastate organizations do not have access to restricted
interstate natural gas pipeline information or receive preferential treatment as
to interstate natural gas pipeline services. The FERC will not enforce
compliance with the independent functioning requirement of the Standards of
Conduct as to these employees until 30 days after it acts on these compliance
filings. In all other respects, we were required to comply with the Standards of
Conduct as of September 22, 2004.
We have implemented compliance with the Standards of Conduct as of September
22, 2004, subject to the exemptions described in the prior paragraph. Compliance
includes, among other things, the posting of compliance procedures and
organizational information for each interstate pipeline on its Internet website,
the posting of discount and tariff discretion information and the implementation
of independent functioning for energy affiliates not covered by the prior
paragraph (electric and gas gathering, processing or production affiliates).
FERC Policy statement re: Use of Gas Basis Differentials for Pricing
On July 25, 2003, the FERC issued a Modification to Policy Statement stating
that FERC regulated natural gas pipelines will, on a prospective basis, no
longer be permitted to use gas basis differentials to price negotiated rate
transactions. Effectively, we will no longer be permitted to use commodity price
indices to structure transactions on our FERC regulated natural gas pipelines.
Negotiated rates based on commodity price indices in existing contracts will be
permitted to remain in effect until the end of the contract period for which
such rates were negotiated. Price indexed contracts currently constitute an
insignificant portion of our contracts on our FERC regulated natural gas
pipelines; consequently, we do not believe that this Modification to Policy
Statement will have a material impact on our operations, financial results or
cash flows.
Quarterly Financial Reports Rulemaking
On February 11, 2004, the FERC approved a final rule in Docket No. RM03-8-000
requiring jurisdictional entities to file quarterly financial reports with the
FERC. Electric utilities, natural gas companies, and licensees will file Form
3-Q, while oil pipeline companies will submit Form 6-Q. The final rule also
adopts some minimal changes to the annual financial reports filed with the FERC.
The final rule modifies the Notice of Proposed Rulemaking by eliminating the
management discussion and analysis section from both the quarterly and annual
reports, and eliminating the use of fourth quarter data in the annual report. In
addition, the final rule eliminates the cash management notification requirement
adopted in FERC Order No. 634-A. The FERC said it will also use the quarterly
financial information when reviewing the adequacy of traditional cost-based
rates. Major public utilities, licensees and natural gas companies will file
quarterly reports 60 days after the end of the quarter; non-major public
utilities, licensees, natural gas companies, and all oil pipeline companies will
file 70 days after the end of the quarter.
Other Regulatory
In addition to the matters described above, we may face additional challenges
to our rates in the future. Shippers on our pipelines do have rights to
challenge the rates we charge under certain circumstances prescribed by
applicable regulations. There can be no assurance that we will not face
challenges to the rates we receive for services on our pipeline systems in the
future. In addition, since many of our assets are subject to regulation, we are
subject to potential future changes in applicable rules and regulations that may
have an adverse effect on our business, financial position, results of
operations or cash flows.
On July 20, 2004, the United States Court of Appeals for the District of
Columbia Circuit issued its opinion in BP West Coast Products, LLC v. Federal
Energy Regulatory Commission, No. 99-1020, On Petitions for Review of Orders of
the Federal Energy Regulatory Commission (Circuit opinion), addressing in part
the tariffs of SFPP, L.P. Among other things, the Circuit opinion vacated the
income tax allowance portion of the FERC opinion and order
20
allowing recovery in SFPP's rates for income taxes and remanded this and other
matters for further proceedings consistent with the Circuit opinion. By its
terms, the opinion only pertains to SFPP, L.P. and it is based on the record in
that case.
Union Pacific Railroad Company Easements
SFPP, L.P. and Union Pacific Railroad Company (the successor to Southern
Pacific Transportation Company) are engaged in two proceedings 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 UPRR should be adjusted pursuant to existing
contractual arrangements for each of the ten year periods beginning January 1,
1994 and January 1, 2004 (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; and Union Pacific Railroad Company vs.
Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. "D",
Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for
the County of Los Angeles, filed July 28, 2004). In the second quarter of 2003,
the trial court set the rent for years 1994 - 2003 at approximately $5.0 million
per year as of January 1, 1994, subject to annual inflation increases throughout
the ten year period. UPRR has appealed this matter to the California Court of
Appeals.
On August 17, 2004, SFPP was served with a lawsuit seeking to determine
the rent for the ten year period commencing January 1, 2004. A trial date has
not been set.
Carbon Dioxide Litigation
Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company are among the
named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al.,
No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case
involves claims by overriding royalty interest owners in the McElmo Dome and Doe
Canyon Units for underpayment of royalties on carbon dioxide produced from the
McElmo Dome Unit, failure to develop carbon dioxide reserves at the Doe Canyon
Unit, and failure to develop hydrocarbons at both McElmo Dome and Doe Canyon.
The plaintiffs also possess a small working interest at Doe Canyon. Plaintiffs
claim breaches of contractual and potential fiduciary duties owed by the
defendants and also allege other theories of liability including breach of
covenants, civil theft, conversion, fraud/fraudulent concealment, violation of
the Colorado Organized Crime Control Act, deceptive trade practices, and
violation of the Colorado Antitrust Act. In addition to actual or compensatory
damages, plaintiffs seek treble damages, punitive damages, and declaratory
relief relating to the Cortez Pipeline tariff and the method of calculating and
paying royalties on McElmo Dome carbon dioxide. Various motions for summary
judgment have been filed and are pending before the Court. The parties are
continuing to engage in discovery. No trial date is currently set.
Kinder Morgan CO2 Company, L.P., Kinder Morgan G.P., Inc., and Cortez
Pipeline Company are among the named defendants in Shores, et al. v. Mobil Oil
Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas
filed December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil
Corp., et al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed
March 29, 2001). These cases involve claims brought on behalf of classes of
overriding royalty interest owners (Shores) and royalty interest owners (Bank of
Denton) for underpayment of royalties on carbon dioxide produced from the McElmo
Dome Unit. The plaintiffs' claims include claims for breach of contractual
duties and covenants, breach of agency duties, civil conspiracy, and declaratory
relief. In addition to their claims for actual damages, plaintiffs seek an
equitable accounting, imposition of a constructive trust over the defendants'
interests, and punitive damages. After the trial court certified classes in both
cases, the Fort Worth Court of Appeals reversed and vacated the trial court's
class certification order in Shores because the trial court lacked jurisdiction
to certify a class. The court of appeals also ruled that most of the named
plaintiffs in Shores could not establish proper venue in Denton County and
dismissed those parties' claims. The trial court's class certification order in
Bank of Denton is currently on appeal to the Fort Worth Court of Appeals, but
the plaintiffs have filed a motion with the trial court to vacate its class
certification order, which was unopposed by the defendants. This motion was
granted in May 2004. The remaining claims in the Shores and Bank of Denton cases
are currently scheduled to go to trial in January 2005.
On May 13, 2004, William Armor, one of the former plaintiffs in the Shores
matter whose claims were dismissed for improper venue by the Court of Appeals,
filed a new case alleging the same claims against the same defendants
21
as he had previously asserted in the Shores case. Armor v. Shell Oil Company, et
al, No. 04-03559 (14th Judicial District, Dallas County Court). Defendants filed
their answers and special exceptions on June 4, 2004. Trial, if necessary, has
been scheduled for July 25, 2005.
Shell CO2 Company, Ltd., predecessor in interest to Kinder Morgan CO2
Company, L.P., is among the named counter-claim defendants in Shell Western E&P
Inc. v. Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial
District Court, Harris County, Texas filed June 17, 1998) (the "SWEPI Action").
The counter-claim plaintiffs are overriding royalty interest owners in the
McElmo Dome Unit and have sued for underpayment of royalties on carbon dioxide
produced from the McElmo Dome Unit. The counter-claim plaintiffs have asserted
claims for fraud/fraudulent inducement, real estate fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, negligence,
negligence per se, unjust enrichment, violation of the Texas Securities Act, and
open account. Counter-claim plaintiffs seek actual damages, punitive damages, an
accounting, and declaratory relief. The trial court granted a series of summary
judgment motions filed by counter-claim defendants on all of plaintiffs'
counter-claims except for the fraud-based claims. The parties agreed to abate
the case pending settlement efforts. While the agreed abatement period has
lapsed, no current trial date is set.
On March 1, 2004, Bridwell Oil Company, one of the named defendants/counter
- -claim plaintiffs in the SWEPI Action filed a new matter in which it asserts
claims which are virtually identical to the counterclaims it asserts in the
SWEPI Action against virtually the same parties. Bridwell Oil Co. v. Shell Oil
Co. et al, No. 160,199-B (78th Judicial District, Wichita County Court). On June
25, 2004, defendants filed answers, special exceptions, pleas in abatement and
motions to transfer venue back to the Harris County District Court, which
motions are currently pending.
J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually
and on behalf of all other private royalty and overriding royalty owners in the
Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan
CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court, Union County New
Mexico).
On August 3, 2004, plaintiffs in the above-captioned matter filed a purported
Class Action Complaint against Kinder Morgan CO2 Company, L.P. alleging that
defendant has failed to pay the full royalty and overriding royalty ("Royalty
Interests") on the true and proper settlement value of compressed carbon dioxide
produced from the Bravo Dome Unit. The complaint purports to assert claims for
violation of the Unfair Practices Act, Constructive Fraud, Breach of Contract
and of the Covenant of Good Faith and Fair Dealing, Breach of the Implied
Covenant to Market, and claims for an Accounting, Unjust Enrichment and
Injunctive Relief. The purported class is alleged to be comprised of current and
former owners, during the period January 2000 to the present, who have private
property Royalty Interests burdening the oil and gas leases held by the
defendant, excluding the Commissioner of Public Lands, the United States of
America, and those private Royalty Interests that are not unitized as part of
the Bravo Dome Unit. The plaintiffs allege that they were members of a class
previously certified as a class action by the United States District Court for
the District of New Mexico in the matter Doris Feerer, et al. v. Amoco
Production Company, et al., USDC N.M. Civ. No. 95-0012 (the "Feerer Class
Action"). Plaintiffs allege that defendant's method of paying Royalty Interests
is contrary to the methodology established in the previous settlement of the
Feerer Class Action. Defendant has filed a Motion to Compel Arbitration of this
matter pursuant to the arbitration provisions contained in the Feerer Class
Action Settlement Agreement, which motion is currently pending. Based on the
information available to date, we believe that the claims against us in this
matter are without merit and intend to defend against them vigorously.
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
22
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. On June
12, 2003, plaintiff served discovery requests on certain defendants. On July 11,
2003, defendants moved to stay any responses to such discovery.
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
Claims 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 to determine issues
related to the Court's subject matter jurisdiction, arising out of the False
Claims Act is complete and briefing is underway. On May 7, 2003, Grynberg sought
leave to file a Third Amended Complaint, which adds allegations of
undermeasurement related to CO2 production. Defendants have filed briefs
opposing leave to amend.
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 tortious 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 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.
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.
The parties have engaged in some discovery and depositions. At this stage of
discovery, we believe that our actions were justified and defensible under
applicable Texas law and that the decision not to renew the underlying gas sales
agreements was made unilaterally by persons acting on behalf of Entex. The
plaintiffs have moved for summary judgment asking the court to declare that a
fiduciary relationship existed for purposes of Sweatman's claims. We have moved
for summary judgment on the grounds that:
o there is no cause-in-fact of the gas sales nonrenewals attributable to us;
and
o the defense of legal justification applies to the claims for tortuous
interference.
23
In September 2003 and then again in November 2003, Sweatman and Paz filed
their third and fourth amended petitions, respectively, asserting all of the
claims for relief described above. In addition, the plaintiffs asked that the
court impose a constructive trust on (i) the proceeds of the sale of Tejas and
(ii) any monies received by any Kinder Morgan entity for sales of gas to any
Entex/Reliant entity following June 30, 2002 that replaced volumes of gas
previously sold under contracts to which Sweatman and Paz had a participating
interest pursuant to the joint venture agreement between Tejas, Sweatman and
Paz. In October 2003, the court granted, and then rescinded its order after a
motion to reconsider heard on February 13, 2004, a motion for partial summary
judgment on the issue of the existence of a fiduciary duty.
We believe this suit is without merit and we intend to defend the case
vigorously. We have moved for partial summary judgment on all of Sweatman's
claims, asserting that even in the light most favorable to Sweatman's
assertions, there is no issue of material fact on whether Sweatman even owned an
interest in the underlying gas sales agreements in dispute. That motion was
heard on August 13, 2004, and was granted on October 26, 2004 as to four of the
five gas sales contracts at issue, leaving for further determination at a later
time any remaining claims based upon other theories of recovery not dependent
upon the four gas sales agreements being joint venture property. We have also
filed a no-evidence motion for summary judgment on the plaintiffs' defamation
claims. Trial of the case is set preferentially for January 17, 2005.
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, among other things, 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.
Weldon Johnson and Guy Sparks , individually and as Representative of Others
Similarly Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2 (Circuit
Court, Miller County Arkansas).
On October 8, 2004, plaintiffs filed the above-captioned matter against
numerous defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan
Energy Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder
Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.;
Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC;
and Midcon Corp. (the "Kinder Morgan Defendants"). The Complaint purports to
bring a class action on behalf of those who purchased natural gas from the
24
Centerpoint defendants from October 1, 1994 to the date of class certification.
The Complaint alleges that the Centerpoint Energy, Inc., by and through its
affiliates, has artificially inflated the price charged to residential consumers
for natural gas that it allegedly purchased from the non-Centerpoint defendants,
including the above-listed Kinder Morgan entities. The Complaint further alleges
that in exchange for Centerpoint's purchase of such natural gas at above market
prices, the non-Centerpoint defendants, including the above-listed Kinder Morgan
entities, sell natural gas to Centerpoint's non-regulated affiliates 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, unlawful enrichment and civil conspiracy
against all of the defendants, and seeks relief in the form of actual, exemplary
and punitive damages, interest, and attorneys' fees. The Complaints were served
on the Kinder Morgan Defendants on October 21, 2004, and thus no response is due
to be filed at this time. 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"); 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
I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial District Court,
State of Nevada, County of Washoe) ("Galaz II); Frankie Sue Galaz, et al v. The
United States of America, the City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC (United States District
Court, District of Nevada)("Galaz III)
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
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 filed a Notice of Appeal to the United
States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit
affirmed the dismissal of this case.
On December 3, 2002, plaintiffs filed an additional Complaint for Class
Action in the Galaz I 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 I 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. Plaintiffs have filed a Notice of Appeal to the United States
Court of Appeals for the
25
9th Circuit. On November 17, 2003, the 9th Circuit dismissed the appeal,
upholding the District Court's dismissal of the case.
On June 20, 2003, plaintiffs filed an additional Complaint for Class Action
(the "Galaz II" matter) asserting the same claims in Nevada State trial court on
behalf of the same purported class against virtually the same defendants,
including us (and excluding the United States Department of the Navy). On
September 30, 2003, the Kinder Morgan defendants filed a Motion to Dismiss the
Galaz II Complaint along with a Motion for Sanctions. On April 13, 2004,
plaintiffs' counsel voluntarily stipulated to a dismissal with prejudice of the
entire case in State Court. The Court has accepted the stipulation and the
parties are awaiting a final order from the Court dismissing the case with
prejudice.
Also on June 20, 2003, the plaintiffs in the Galaz matters filed yet another
Complaint for Class Action in the United States District Court for the District
of Nevada (the "Galaz III" matter) asserting the same claims in United States
District Court for the District of Nevada on behalf of the same purported class
against virtually the same defendants, including us. The Kinder Morgan
defendants filed a Motion to Dismiss the Galaz III matter on August 15, 2003. On
October 3, 2003, the plaintiffs filed a Motion for Withdrawal of Class Action,
which voluntarily drops the class action allegations from the matter and seeks
to have the case proceed on behalf of the Galaz family only. On December 5,
2003, the District Court granted the Kinder Morgan defendants' Motion to
Dismiss, but granted plaintiff leave to file a second Amended Complaint.
Plaintiff filed a Second Amended Complaint on December 13, 2003, and a Third
Amended Complaint on January 5, 2004. The Kinder Morgan defendants filed a
Motion to Dismiss the Third Amended Complaint on January 13, 2004. The Motion to
Dismiss was granted with prejudice on April 30, 2004. On May 7, 2004, Plaintiff
filed a Notice of Appeal in the United States Court of Appeals for the 9th
Circuit, which appeal is currently pending.
Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482
(Second Judicial District Court, State of Nevada, County of Washoe) ("Jernee").
On May 30, 2003, a separate group of plaintiffs, individually and on behalf
of Adam Jernee, filed a civil action in the Nevada State trial court against us
and several Kinder Morgan related entities and individuals and additional
unrelated defendants ("Jernee"). Plaintiffs in the Jernee matter claim that
defendants negligently and intentionally failed to inspect, repair and replace
unidentified segments of their pipeline and facilities, allowing "harmful
substances and emissions and gases" to damage "the environment and health of
human beings." Plaintiffs claim that "Adam Jernee's death was caused by leukemia
that, in turn, is believed to be due to exposure to industrial chemicals and
toxins." Plaintiffs purport to assert claims for wrongful death, premises
liability, negligence, negligence per se, intentional infliction of emotional
distress, negligent infliction of emotional distress, assault and battery,
nuisance, fraud, strict liability, and aiding and abetting, and seek unspecified
special, general and punitive damages. The Kinder Morgan defendants filed
Motions to Dismiss the complaint on November 20, 2003, which Motions are
currently pending. In addition, plaintiffs and the defendant City of Fallon have
appealed the Trial Court's ruling on initial procedural matters concerning
proper venue. On March 29, 2004, the Nevada Supreme Court stayed the action
pending resolution of these procedural matters on appeal.
Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326
(Second Judicial District Court, State of Nevada, County of Washoe) ("Sands").
On August 28, 2003, a separate group of plaintiffs, represented by the
counsel for the plaintiffs in the Jernee matter, individually and on behalf of
Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court
against us and several Kinder Morgan related entities and individuals and
additional unrelated defendants ("Sands"). Plaintiffs in the Sands matter claim
that defendants negligently and intentionally failed to inspect, repair and
replace unidentified segments of their pipeline and facilities, allowing
"harmful substances and emissions and gases" to damage "the environment and
health of human beings." Plaintiffs claim that Stephanie Suzanne Sands' death
was caused by leukemia that, in turn, is believed to be due to exposure to
industrial chemicals and toxins. Plaintiffs purport to assert claims for
wrongful death, premises liability, negligence, negligence per se, intentional
infliction of emotional distress, negligent infliction of emotional distress,
assault and battery, nuisance, fraud, strict liability, and aiding and abetting,
and seek unspecified special, general and punitive damages. The Kinder Morgan
defendants were served with the Complaint on January 10, 2004. On February 26,
2004, the Kinder Morgan defendants filed a Motion to Dismiss and a Motion to
Strike, which motions are currently pending. In addition, plaintiffs and the
26
defendant City of Fallon have appealed the Trial Court's ruling on initial
procedural matters concerning proper venue and a peremptory challenge of the
trial judge by the plaintiffs. On April 27, 2004, the Nevada Supreme Court
stayed the action pending resolution of these procedural matters on appeal.
Based on the information available to date, our own preliminary
investigation, and the positive results of investigations conducted by State and
Federal agencies, we believe that the claims against us in these matters are
without merit and intend to defend against them vigorously.
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.
A settlement has been reached between most of the plaintiffs and Plantation.
It is anticipated that all of the proceedings to complete the settlement will be
completed by the end of the fourth quarter of 2004. We believe that the ultimate
resolution of these Marion County, Mississippi cases will not have a material
effect on our business, financial position, results of operations or cash flows.
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. We filed our answer to the
Complaint on June 27, 2003, in which we denied ExxonMobil's claims and
allegations as well as included counterclaims against ExxonMobil. 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 as a responsible party 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, if any,
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. The parties have recently completed discovery.
We intend to take depositions of several key ST Services personnel who were
involved in the transaction with GATX Terminals. Once the depositions are
complete, the parties will discuss the effectiveness of various methods of
alternative dispute resolutions in an effort to resolve the case. In October
2004, the judge assigned to the case dismissed himself from the case based on a
conflict and the case is delayed until another judge can be assigned. The
plaintiffs have requested an extension of the discovery deadline, which we will
not oppose.
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.,
27
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 economic damages for the
period from November 1987 through March 1997 in the amount of $30.7 million. On
May 2, 2003, Plaintiff added claims for the period from April 1997 through
February 2003 in the amount of $12.9 million. On June 23, 2003, Plaintiff filed
a Fourth Amended Petition that reduced its total claim for economic damages to
$30.0 million. On October 5, 2003, Plaintiff filed a Fifth Amended Petition that
purported to add a cause of action for embezzlement. On February 10, 2004,
Plaintiff filed its Eleventh Supplemental Responses to Requests for Disclosure
that restated its alleged economic damages for the period of November 1987
through December 2003 as approximately $37.4 million. The matter went to trial
on June 21, 2004. On June 30, 2004, the jury returned a unanimous verdict in
favor of all defendants as to all counts. Final Judgment was entered in favor of
the defendants on August 19, 2004. On September 17, 2004, Defendants filed a
Motion to Modify Judgment for Entry of Sanctions against the Plaintiff, which
motion is currently pending. The Plaintiff has stated that it is currently
reviewing its appellate options.
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, results of operations or cash flows.
Proposed Office of Pipeline Safety Civil Penalty and Compliance Order
On July 15, 2004, the U.S. Department of Transportation's Office of Pipeline
Safety ("OPS") issued a Proposed Civil Penalty and Proposed Compliance Order
(the "Proposed Order") concerning alleged violations of certain federal
regulations concerning our pipeline Integrity Management Program. The violations
alleged in the Proposed Order are based upon the results of inspections of our
Integrity Management Program at our products pipelines facilities in Orange,
California and Doraville, Georgia conducted in April and June of 2003,
respectively. As a result of the alleged violations, the OPS seeks to have us
implement a number of changes to our Integrity Management Program and also seeks
to impose a proposed civil penalty of $350,000. We have already addressed a
number of the concerns identified by the OPS and intend to continue to work with
the OPS to ensure that our Integrity Management Program satisfies all applicable
regulations. However, we dispute some of the OPS findings and disagree that
civil penalties are appropriate, and therefore have requested an administrative
hearing on these matters according to the U.S. Department of Transportation
regulations. A hearing date has not been set.
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
28
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.
Tucson, Arizona
Also, on July 30, 2003, SFPP, L.P. suffered a sudden and accidental rupture
of one of its liquid products pipelines in the vicinity of Tucson, Arizona. The
rupture resulted in the release of petroleum product into the soil and
groundwater in the immediate vicinity of the rupture.
On September 11, 2003, the Arizona Department of Environmental Quality
("ADEQ") issued a Notice of Violation indicating that ADEQ "has reason to
believe" that SFPP violated certain Arizona statutes and rules due to the
discharge of petroleum product to the environment as a result of the pipeline
rupture. ADEQ asserted that such alleged violations could result in the
imposition of civil penalties against SFPP. SFPP timely responded to the Notice
of Violation, disputed its validity, and provided the requested information
therein.
On November 13, 2003, ADEQ sent a second Notice of Violation with respect to
the pipeline rupture and release, stating that ADEQ had reason to believe that a
violation of additional Arizona regulations had resulted from the discharge of
petroleum, because the petroleum had reached groundwater. ADEQ asserted that
such alleged violations could result in the imposition of civil penalties
against SFPP. SFPP timely responded to this second Notice of Violation, disputed
its validity, and provided the requested information therein.
According to ADEQ written policy, a Notice of Violation is not an enforcement
action, and is instead "an enforcement compliance assurance tool used by ADEQ."
ADEQ's policy also states that although ADEQ has the "authority to issue
appealable administrative orders compelling compliance, a Notice of Violation
has no such force or effect." As of September 30, 2004, ADEQ has not issued any
such administrative orders. SFPP is currently in discussions with ADEQ regarding
the investigation and remediation of the contamination resulting from the
pipeline rupture and a mutually satisfactory resolution of the Notice of
Violations.
Cordelia, California
On April 28, 2004, we discovered a spill of diesel fuel into a marsh near
Cordelia, California from a section of pipeline on our Pacific Operations.
Current estimates indicate that the size of the spill was approximately 2,450
barrels. Upon discovery of the spill and notification to regulatory agencies, a
unified response was implemented with the United States Coast Guard, the
California Department of Fish and Game, the Office of Spill Prevention and
Response ("OSPR") and us. The damaged section of the pipeline has been removed
and replaced, and the pipeline resumed operations on May 2, 2004. We have
completed recovery of free flowing diesel from the marsh and completed an
enhanced biodegradation program for removal of the remaining constituents bound
up in soils. The property has been turned back to the owners for its stated
purpose. There will be ongoing monitoring under the oversight of the California
Regional Water Quality Control Board until the site conditions demonstrate there
are no
29
further actions required. The circumstances surrounding the release and impact
thereof are currently under review by the OSPR and the United States
Environmental Protection Agency.
San Diego, California
In June 2004, we entered into discussions with the City of San Diego with
respect to impacted groundwater beneath the City's stadium property in San Diego
resulting from operations at the Mission Valley terminal facility. The City has
requested that SFPP work with the City as they seek to re-develop options for
the stadium area including future use of both groundwater aquifer and real
estate development. The City of San Diego and SFPP are working cooperatively
towards a settlement and a long term plan as SFPP continues to remediate the
impacted groundwater. We do not expect the cost of any settlement and
remediation plan to be material. This site has been, and currently is, under the
regulatory oversight and order of the California Regional Water Quality Control
Board.
Other Environmental
On March 30, 2004, the Texas Commission on Environmental Quality (TCEQ)
issued a Notice of Enforcement Action related to our CO2 segment's Snyder Gas
Plant. We are currently in settlement discussions with TCEQ regarding this
issue. 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, results of operations or
cash flows. As of September 30, 2004, we have recorded a total reserve for
environmental claims in the amount of $27.8 million. However, we are 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, results of
operations or cash flows.
4. Change in Accounting for Asset Retirement Obligations
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, we follow the accounting and reporting provisions of Statement
of Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations." 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 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
30
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 theassociated long-lived asset; and
o accumulated depreciation on that capitalized cost.
Amounts resulting from initial application of this Statement are measured
using current information, current assumptions and current interest rates. The
amount recognized as an asset retirement cost is measured as of the date the
asset retirement obligation was incurred. Cumulative accretion and accumulated
depreciation are 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 resulted 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 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 September 30, 2004, we have recognized asset retirement
obligations in the aggregate amount of $34.2 million relating to these
requirements at existing sites within our CO2 business segment.
In our Natural Gas Pipelines business segment, if we were to 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 September 30, 2004, we have recognized
asset retirement obligations in the aggregate amount of $2.7 million relating to
the businesses within our Natural Gas Pipelines business segment.
We have included $0.8 million of our total $36.9 million asset retirement
obligations as of September 30, 2004 with "Accrued other current liabilities" in
our accompanying consolidated balance sheet. The remaining $36.1 million
obligation is reported separately as a non-current liability. 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 each of the nine months ended September 30,
2004 and 2003 is as follows (in thousands):
Nine Months Ended September 30,
-------------------------------
2004 2003
---------- ----------
Balance at beginning of period................. $ 35,708 $ -
Initial ARO balance upon adoption.............. - 14,125
Liabilities incurred........................... 130 2,199
Liabilities settled............................ (516) (582)
Accretion expense.............................. 1,559 654
Revisions in estimated cash flows.............. - 208
---------- ----------
Balance at end of period....................... $ 36,881 $ 16,604
========== ==========
31
5. Distributions
On August 13, 2004, we paid a cash distribution of $0.71 per unit to our
common unitholders and our Class B unitholders for the quarterly period ended
June 30, 2004. KMR, our sole i-unitholder, received 920,140 additional i-units
based on the $0.71 cash distribution per common unit. The distributions were
declared on July 21, 2004, payable to unitholders of record as of July 31, 2004.
On October 20, 2004, we declared a cash distribution of $0.73 per unit for
the quarterly period ended September 30, 2004. The distribution will be paid on
or before November 12, 2004, to unitholders of record as of October 31, 2004.
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 $0.73
distribution per common unit. The number of i-units distributed will be 929,105.
For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.017892)
will be issued. The fraction was determined by dividing:
o $0.73, the cash amount distributed per common unit
by
o $40.80, the average of KMR's limited liability shares' closing market
prices from October 13-26, 2004, 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
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. Following
is information related to our intangible assets still subject to amortization
and our goodwill (in thousands):
September 30, December 31,
2004 2003
----------- -----------
Goodwill
Gross carrying amount...... $ 740,612 $ 743,652
Accumulated amortization... (14,142) (14,142)
----------- -----------
Net carrying amount........ 726,470 729,510
----------- -----------
Lease value
Gross carrying amount...... 6,592 6,592
Accumulated amortization... (993) (888)
----------- -----------
Net carrying amount........ 5,599 5,704
----------- -----------
Contracts and other
Gross carrying amount...... 9,498 7,801
Accumulated amortization... (838) (303)
----------- -----------
Net carrying amount........ 8,660 7,498
----------- -----------
Total intangibles, net..... $ 740,729 $ 742,712
=========== ===========
Changes in the carrying amount of goodwill for the nine months ended
September 30, 2004 are summarized as follows (in thousands):
Products Natural Gas
Pipelines Pipelines CO2 Terminals Total
----------- ----------- ----------- ----------- -----------
Balance as of December 31, 2003.... $ 263,182 $ 253,358 $ 46,101 $ 166,869 $ 729,510
Acquisitions..................... - - - - -
Disposals - purchase price adjs.. - (3,040) - - (3,040)
Impairment losses................ - - - - -
----------- ----------- ----------- ----------- -----------
Balance as of September 30, 2004... $ 263,182 $ 250,318 $ 46,101 $ 166,869 $ 726,470
=========== =========== =========== =========== ===========
Amortization expense on our intangibles consisted of the following (in
thousands):
32
Three Months Ended September 30, Nine Months Ended September 30,
--------------------------------- --------------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
Lease value............ $ 35 $ 35 $ 105 $ 105
Contracts and other.... 205 17 535 48
------------ ------------ ------------ ------------
Total amortization..... $ 240 $ 52 $ 640 $ 153
============ ============ ============ ============
As of September 30, 2004, our weighted average amortization period for our
intangible assets was approximately 25.1 years. Our estimated amortization
expense for these assets for each of the next five fiscal years is approximately
$1.0 million.
In addition, pursuant to ABP No. 18, any premium paid by an investor, which
is analogous to goodwill, must be identified. The premium, representing excess
cost over underlying fair value of net assets accounted for under the equity
method of accounting, is referred to as equity method goodwill, and is not
subject to amortization but rather to impairment testing. The impairment test
under APB No. 18 considers whether the fair value of the equity investment as a
whole, not the underlying net assets, has declined and whether that decline is
other than temporary. This test requires equity method investors to continue to
assess impairment of investments in investees by considering whether declines in
the fair values of those investments, versus carrying values, may be other than
temporary in nature. As of both September 30, 2004 and December 31, 2003, we
have reported $150.3 million in equity method goodwill within the caption
"Investments" in our accompanying consolidated balance sheets.
7. Debt
Our outstanding short-term debt as of September 30, 2004 was $1,016.5
million. The balance primarily consisted of $812.7 million of commercial paper
borrowings, $200 million of 8.0% senior notes due March 15, 2005, and $5.0
million in Central Florida Pipeline LLC senior notes due July 23, 2005. As of
September 30, 2004, we intended and had the ability to refinance all 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.
The weighted average interest rate on all of our borrowings was approximately
4.591% during the third quarter of 2004 and 4.419% during the third quarter of
2003.
Credit Facilities
On August 18, 2004, we replaced our existing bank facilities with a $1.25
billion five-year, unsecured revolving credit facility due August 18, 2009.
Similar to our previous credit facilities, our current credit facility is with a
syndicate of financial institutions and Wachovia Bank, National Association is
the administrative agent. Our five-year credit facility contains borrowing rates
and restrictive financial covenants that are similar to the borrowing rates and
covenants under our previous bank facilities as discussed in our Annual Report
on Form 10-K for the year ended December 31, 2003. However, our current facility
no longer requires us to maintain a tangible net worth of at least $2.1 billion
as of the last day of any fiscal quarter. Our previous credit facilities
consisted of a $570 million unsecured 364-day credit facility due October 12,
2004 and a $480 million unsecured three-year credit facility due October 15,
2005.
There were no borrowings under our five-year credit facility as of
September 30, 2004, and no borrowings under either of our previous facilities as
of December 31, 2003. The amount available for borrowing under our credit
facility as of September 30, 2004 is reduced by:
o our outstanding commercial paper borrowings ($812.7 million as of September
30, 2004);
o a $50 million letter of credit ($125 million as of October 31, 2004) that
supports our hedging of commodity price risks involved from the sale of
natural gas, natural gas liquids, oil and carbon dioxide;
o a $26.9 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 located
at Fernandina Beach, Florida);
33
o a $24.1 million letter of credit that supports Kinder Morgan Operating L.P.
"B"'s tax-exempt bonds; and
o a $0.2 million letter of credit entered into on June 4, 2002 that supports
a workers' compensation insurance policy.
Our five-year credit facility also permits us to obtain bids for fixed rate
loans from members of the lending syndicate. None of our debt or credit facility
borrowings 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 facility varies with our credit ratings.
Interest Rate Swaps
Information on our interest rate swaps is contained in Note 10.
Commercial Paper Program
On October 15, 2004, we increased our commercial paper program by $200
million to provide for the issuance of up to $1.25 billion. Our new $1.25
billion unsecured 5-year credit facility supports our commercial paper program,
and borrowings under our commercial paper program reduce the borrowings allowed
under our credit facilities. As of September 30, 2004, we had $812.7 million of
commercial paper outstanding with an average interest rate of 1.731%.
Kinder Morgan Wink Pipeline, L.P. Debt
Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P., which we renamed Kinder Morgan Wink Pipeline,
L.P. As part of our purchase price, we assumed Kaston's $9.5 million note
payable to Western Refining Company, L.P. In September 2004, we paid the $9.5
million outstanding balance under the note, and following our repayment of the
note, Kinder Morgan Wink Pipeline, L.P. had no outstanding debt.
Central Florida Pipeline LLC Debt
Effective January 1, 2001, we acquired Central Florida Pipeline LLC. As part
of our purchase price, we assumed an aggregate principal amount of $40 million
of Senior Notes originally issued to a syndicate of eight insurance companies.
The Senior Notes have a fixed annual interest rate of 7.84% with repayments in
annual installments of $5 million beginning July 23, 2001. The final payment is
due July 23, 2008. Interest is payable semiannually on January 1 and July 23 of
each year. At December 31, 2003, Central Florida's outstanding balance under the
Senior Notes was $25 million. In July 2004, we made an annual repayment of $5
million and at September 30, 2004, Central Florida's outstanding balance under
the Senior Notes was $20 million.
Kinder Morgan Liquids Terminals LLC Debt
Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC.
As part of our purchase price, we assumed debt of $87.9 million, consisting of
five series of tax-exempt industrial revenue bonds. Kinder Morgan Liquids
Terminals LLC was the obligor on the bonds, which consisted of the following:
o $4.1 million of 7.30% New Jersey industrial revenue bonds due September 1,
2019;
o $59.5 million of 6.95% Texas industrial revenue bonds due February 1, 2022;
o $7.4 million of 6.65% New Jersey industrial revenue bonds due September 1,
2022;
o $13.3 million of 7.00% Louisiana industrial revenue bonds due March 1,
2023; and
o $3.6 million of 6.625% Texas industrial revenue bonds due February 1, 2024.
34
In May 2004, we exercised our right to call and retire all of the industrial
revenue bonds (other than the $3.6 million of 6.625% bonds due February 1, 2024,
which we retired on October 13, 2004) prior to maturity at a redemption price of
$84.3 million, plus approximately $1.9 million for interest, prepayment premiums
and redemption fees. We borrowed the necessary funds under our commercial paper
program. Pursuant to Accounting Principles Board Opinion No. 26, "Early
Extinguishment of Debt," we recognized the $1.4 million excess of our
reacquisition price over both the carrying value of the bonds and unamortized
debt issuance costs as a loss on bond repurchases and we included this amount
under the caption "Other, net" in our accompanying consolidated statements of
income.
Contingent Debt
We apply the disclosure provisions of FASB Interpretation (FIN) No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" to our agreements that contain
guarantee or indemnification clauses. These disclosure provisions expand those
required by FASB No. 5, "Accounting for Contingencies," by requiring a guarantor
to disclose certain types of guarantees, even if the likelihood of requiring the
guarantor's performance is remote. The following is a description of our
contingent debt agreements.
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 several, 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 several 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 September 30, 2004, the debt facilities of Cortez Capital Corporation
consisted of:
o $85 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 22, 2004
(to support the above-mentioned $175 million commercial paper program).
As of September 30, 2004, Cortez Capital Corporation had $118.7 million of
commercial paper outstanding with an average interest rate of 1.6705%, the
average interest rate on the Series D notes was 7.0835% and there were no
borrowings under the credit facility.
Plantation Pipe Line Company Debt
On April 30, 1997, Plantation Pipe Line Company entered into a $10 million,
ten-year floating-rate term credit agreement. We, as an owner of Plantation Pipe
Line Company, severally guarantee this debt on a pro rata basis equivalent to
our respective 51.17% ownership interest. During 1999, this agreement was
amended to reduce the maturity date by three years. In April 2004, we extended
the maturity to July 20, 2004.
35
In July 2004, Plantation repaid the $10 million note outstanding and $175
million in outstanding commercial paper with funds of $190 million borrowed from
its owners. We loaned Plantation $97.2 million, which corresponds to our 51.17%
ownership interest, in exchange for a seven year note receivable bearing
interest at the rate of 4.72% per annum. The note provides for semiannual
payments of principal and interest on December 31 and June 30 each year
beginning on December 31, 2004 based on a 25 year amortization schedule, with a
final principal payment of $156.6 million due July 20, 2011. We funded our loan
of $97.2 million with borrowings under our commercial paper program. ExxonMobil
owns the remaining approximate 49% interest in Plantation and funded the
remaining $92.8 million on similar terms.
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 under joint and several liability. The principal is
to be repaid in seven equal installments beginning on October 31, 2004 and
ending on October 31, 2010. The $55 million was outstanding as of September 30,
2004.
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 LLC, the operator of the
port facilities. In July 2002, we acquired Nassau Terminals LLC 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. As of September 30, 2004, the value of this
letter of credit outstanding under our credit facilities was $26.9 million.
Principal payments on the bonds are made on the first of December each year and
reductions are made to the letter of credit.
Certain Relationships and Related Transactions
KMI Asset Contributions
In conjunction with our acquisition of Natural Gas Pipelines assets from KMI
effective 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, 2003
and September 30, 2004. KMI would be obligated to perform under this guarantee
only if we and/or our assets were unable to satisfy our obligations.
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, 2003.
8. Partners' Capital
As of September 30, 2004 and December 31, 2003, our partners' capital
consisted of the following limited partner units:
September 30, December 31,
2004 2003
------------- ------------
Common units.................. 140,047,108 134,729,258
Class B units................. 5,313,400 5,313,400
i-units....................... 51,928,536 48,996,465
------------- ------------
Total limited partner units. 197,289,044 189,039,123
============= ============
36
The total limited partner units represent our limited partners' interest and
an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights.
As of September 30, 2004, our common unit totals consisted of 127,091,373
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. As of December 31, 2003, our common unit total consisted of
121,773,523 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. On both September 30, 2004, and December 31, 2003,
our Class B units were held entirely by KMI and our i-units were held entirely
by KMR.
In February 2004, we issued, in a public offering, 5,300,000 of our common
units at a price of $46.80 per unit, less commissions and underwriting expenses.
After commissions and underwriting expenses, we received net proceeds of $237.8
million for the issuance of these common units. We used the proceeds to reduce
the borrowings under our commercial paper program.
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.
Our 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 us, and controlling and managing our business and affairs and
the business and affairs of our operating limited partnerships and their
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.
On March 25, 2004, KMR issued an additional 360,664 of its shares at a price
of $41.59 per share, less closing fees and commissions. The net proceeds from
the offering were used to buy additional i-units from us. After closing and
commission expenses, we received net proceeds of $14.9 million for the issuance
of 360,664 i-units. We used the proceeds from the i-unit issuance to reduce the
borrowings under our commercial paper program.
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 cash to the holders of our i-units
but will retain the cash for use 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 920,140 i-units on August 13, 2004.
These additional i-units distributed were based on the $0.71 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 quarterly distributions to unitholders exceed certain specified
target levels. Our distribution of $0.71 per unit paid on August 13, 2004 for
the second quarter of 2004 required an incentive distribution to our general
partner of $94.9 million. Our distribution of
37
$0.65 per unit paid on August 14, 2003 for the second quarter of 2003 required
an incentive distribution to our general partner of $79.6 million. Our declared
distribution for the third quarter of 2004 of $0.73 per unit will result in an
incentive distribution to our general partner of approximately $99.1 million.
This compares to our distribution of $0.66 per unit and incentive distribution
to our general partner of approximately $81.8 million for the third quarter of
2003.
9. Comprehensive Income
SFAS No. 130, "Accounting for Comprehensive Income," requires that
enterprises report a total for comprehensive income. For each of the three
months and nine months ended September 30, 2004 and 2003, the only difference
between our net income and our comprehensive income was the unrealized gain or
loss on derivatives utilized for hedging purposes. For more information on our
hedging activities, see Note 10. Our total comprehensive income is as follows
(in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -----------------------
2004 2003 2004 2003
------------ ---------- --------- ----------
Net income............................................................... $ 217,342 $ 174,176 $ 604,314 $ 513,611
Change in fair value of derivatives used for hedging purposes............ (268,212) (35,508) (504,234) (108,682)
Reclassification of change in fair value of derivatives to net income.... 45,002 15,798 118,214 67,046
---------- ---------- --------- ----------
Comprehensive income/(loss)............................................ $ (5,868) $ 154,466 $ 218,294 $ 471,975
========== ========== ========= ==========
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. 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. These risk management instruments are also called derivatives, which are
defined as financial instruments or contracts (options, swaps, futures, etc.)
whose value is derived from some other financial measure called the underlying,
(for example, commodity prices) and includes payment provisions called the
notional amount (for example, payment in cash, commodities, etc.). The value of
a derivative is a function of the underlying and the notional amount, and while
the underlying changes due to changes in market conditions, the notional amount
remains constant throughout the life of the derivative contract.
Current accounting standards require derivatives to be reflected as assets or
liabilities at their fair market values and the fair value of our 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, including: commodity futures and options contracts, fixed-price swaps,
and basis swaps.
Pursuant to our management's approved policy, we are to engage in these
activities 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 primarily 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
38
are monitored by our Risk Management Committee, which is charged with the review
and enforcement of our management's risk management policy.
Certain of our business activities expose us to foreign currency
fluctuations. However, due to the limited size of this exposure, we do not
believe the risks associated with changes in foreign currency will have a
material adverse effect on our business, financial position, results of
operations or cash flows.
Our derivatives hedge the commodity price risks derived from our normal
business activities, which include the sale of natural gas, natural gas liquids,
oil and carbon dioxide, and these derivatives have been designated by us 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 is reclassified into earnings when the forecasted transaction
affects earnings. If the transaction results in an asset or liability, amounts
in accumulated other comprehensive income should be reclassified into earnings
when the asset or liability affects earnings through cost of sales,
depreciation, interest expense, etc. To be considered 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 and any component excluded from the computation of
the effectiveness of the derivative instrument is reported in earnings
immediately.
The gains and losses included in "Accumulated other comprehensive loss" in
our accompanying consolidated balance sheets are reclassified into earnings as
the hedged sales and purchases take place. Approximately $235.7 million of the
Accumulated other comprehensive loss balance of $541.8 million representing
unrecognized net losses on derivative activities as of September 30, 2004 is
expected to be reclassified into earnings during the next twelve months. During
the nine months ended September 30, 2004, we reclassified $118.2 million of
Accumulated other comprehensive income into earnings. This reclassification
reduced the accumulated other comprehensive loss balance of $155.8 million
representing unrecognized net losses on derivative activities as of December 31,
2003.
During each of the nine months ended September 30, 2004 and 2003, no gains or
losses included in "Accumulated other comprehensive loss" were reclassified into
earnings as a result of the discontinuance of cash flow hedges due to a
determination that the forecasted transactions would no longer occur by the end
of the originally specified time period.
We recognized a minimal amount (less than $0.1 million) of gain or loss
during the third quarter and the first nine months of 2004 as a result of
ineffective hedges. We also recognized a gain of $0.2 million during the third
quarter of 2003 and a gain of $0.6 million during the first nine months of 2003
as a result of hedge ineffectiveness. All of these amounts were reported within
the captions "Gas purchases and other costs of sales" in our accompanying
consolidated statements of income. For each of the nine months ended September
30, 2004 and 2003, we did not exclude any component of our 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 included within
"Other current assets", "Accrued other liabilities", "Deferred charges and other
assets" and "Other long-term liabilities and deferred credits" in our
accompanying consolidated balance sheets.
The following table summarizes the net fair value of our energy financial
instruments associated with our risk management activities and included on our
accompanying consolidated balance sheets as of September 30, 2004 and December
31, 2003 (in thousands):
September 30, December 31,
2004 2003
------------- -------------
Derivatives-net asset/(liability)
Other current assets............................. $ 28,620 $ 18,157
Deferred charges and other assets................ 19,774 2,722
Accrued other liabilities........................ (270,829) (90,426)
Other long-term liabilities and deferred credits. $ (333,265) $ (101,463)
39
As of September 30, 2004, we had an outstanding $50 million letter of credit
issued to Morgan Stanley in support of our hedging activities. As of October 31,
2004, the amount of this letter of credit was $125 million.
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; however, as of both September 30, 2004
and December 31, 2003, we were essentially in a net payable position and had
virtually no amounts owed to us from other parties. In addition, 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 both
September 30, 2004 and December 31, 2003, we were a party to interest rate swap
agreements with a notional principal amount of $2.1 billion for the purpose of
hedging the interest rate risk associated with our fixed and variable rate debt
obligations.
As of September 30, 2004, a notional principal amount of $2.0 billion of
these agreements effectively converts the interest expense associated with the
following series of our senior notes from fixed rates to variable rates based on
an interest rate of LIBOR plus a spread:
o $200 million principal amount of our 8.0% senior notes due March 15, 2005;
o $200 million principal amount of our 5.35% senior notes due August 15,
2007;
o $250 million principal amount of our 6.30% senior notes due February 1,
2009;
o $200 million principal amount of our 7.125% senior notes due March 15,
2012;
o $250 million principal amount of our 5.0% senior notes due December 15,
2013;
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 September 30,
2004, the maximum length of time over which we have hedged a portion of our
exposure to the variability in future cash flows associated with interest rate
risk is through August 15, 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 in March 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 or seven 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
40
accounting is to reflect in earnings the extent to which the hedge is not
effective in achieving offsetting changes in fair value.
As of September 30, 2004, we also had swap agreements that effectively
convert the interest expense associated with $100 million of our variable rate
debt to fixed rate debt. Half of these agreements, converting $50 million of our
variable rate debt to fixed rate debt, mature on August 1, 2005, and the
remaining half mature on September 1, 2005. These swaps are 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 $100 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.
The differences between fair value and the original carrying value
associated with our interest rate swap agreements are included within "Deferred
charges and other assets" and "Other long-term liabilities and deferred credits"
in our accompanying consolidated balance sheets. The offsetting entry to adjust
the carrying value of the debt securities whose fair value was being hedged is
recognized as "Market value of interest rate swaps" on our accompanying
consolidated balance sheets.
The following table summarizes the net fair value of our interest rate swap
agreements associated with our interest rate risk management activities and
included on our accompanying consolidated balance sheets as of September 30,
2004 and December 31, 2003 (in thousands):
September 30, December 31,
2004 2003
------------- -------------
Derivatives-net asset/(liability)
Deferred charges and other assets................ $ 126,529 $ 129,618
Other long-term liabilities and deferred credits. (3,162) (8,154)
Market value of interest rate swaps............ $ 123,367 $ 121,464
=========== ============
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:
o Products Pipelines;
o Natural Gas Pipelines;
o CO2; and
o Terminals.
We evaluate performance principally based on each segments' earnings before
depreciation, depletion and amortization, 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.
41
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 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 Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2004 2003 2004 2003
--------- --------- ---------- ----------
Revenues
Products Pipelines................ $ 160,867 $ 145,874 $ 475,187 $ 435,575
Natural Gas Pipelines............. 1,598,554 1,321,651 4,591,293 4,143,765
CO2............................... 121,777 66,577 337,935 169,664
Terminals......................... 133,461 116,740 389,682 355,123
----------- ----------- ----------- -----------
Total consolidated revenues....... $ 2,014,659 $ 1,650,842 $ 5,794,097 $ 5,104,127
=========== =========== =========== ===========
Operating expenses (a)
Products Pipelines................ $ 46,489 $ 42,784 $ 135,792 $ 124,450
Natural Gas Pipelines............. 1,498,030 1,234,149 4,301,857 3,887,905
CO2............................... 43,331 21,372 123,620 54,175
Terminals......................... 63,943 55,723 188,336 170,780
----------- ----------- ----------- -----------
Total consolidated operating
expenses........................ $ 1,651,793 $ 1,354,028 $ 4,749,605 $ 4,237,310
=========== =========== =========== ===========
Depreciation, depletion and amortization
Products Pipelines................ $ 17,951 $ 16,827 $ 52,751 $ 50,110
Natural Gas Pipelines............. 13,191 13,777 38,959 40,006
CO2............................... 30,465 15,298 86,583 41,341
Terminals......................... 10,607 9,129 31,330 27,137
----------- ----------- ----------- -----------
Total consolidated depreciation $ 72,214 $ 55,031 $ 209,623 $ 158,594
and amortization................ =========== =========== =========== ===========
Earnings from equity investments
Products Pipelines................ $ 7,658 $ 6,989 $ 21,610 $ 22,619
Natural Gas Pipelines............. 5,280 5,877 14,558 18,260
CO2............................... 7,711 7,978 25,552 26,848
Terminals......................... (4) (3) 3 37
----------- ----------- ----------- -----------
Total consolidated equity
earnings........................ $ 20,645 $ 20,841 $ 61,723 $ 67,764
=========== =========== =========== ===========
Amortization of excess cost of equity
investments
Products Pipelines................ $ 819 $ 819 $ 2,461 $ 2,461
Natural Gas Pipelines............. 70 70 208 208
CO2............................... 505 505 1,513 1,513
Terminals......................... - - - -
----------- ----------- ----------- -----------
Total consol. amortization of
excess cost of invests.......... $ 1,394 $ 1,394 $ 4,182 $ 4,182
=========== =========== =========== ===========
Interest income
Products Pipelines................ $ 930 $ - $ 930 $ -
Natural Gas Pipelines............. - - - -
CO2............................... - - - -
Terminals......................... - - - -
----------- ----------- ----------- ----------
Total segment interest income..... 930 - 930 -
Unallocated interest income....... 236 310 713 1,172
----------- ----------- ----------- ----------
Total consolidated interest income $ 1,166 $ 310 $ 1,643 $ 1,172
=========== =========== =========== ==========
42
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2004 2003 2004 2003
--------- --------- ---------- ----------
Other, net - income (expense)
Products Pipelines................ $ 171 $ 193 $ 936 $ 1,703
Natural Gas Pipelines............. 29 515 1,155 1,040
CO2............................... 10 (52) 42 (47)
Terminals......................... (61) 316 (306) 61
----------- ----------- ----------- ----------
Total segment other, net - income
(expense)....................... 149 972 1,827 2,757
Loss from early extinguishment of
debt - - (1,424) -
----------- ----------- ----------- ----------
Total consolidated other, net -
income (expense)................ $ 149 $ 972 $ 403 $ 2,757
=========== =========== =========== ==========
Income tax benefit (expense)
Products Pipelines................ $ (2,784) $ (2,328) $ (8,968) $ (8,294)
Natural Gas Pipelines............. (622) (695) (1,395) (1,528)
CO2............................... (49) (10) (96) (30)
Terminals......................... (2,285) (870) (5,003) (4,555)
----------- ----------- ----------- ----------
Total consolidated income tax
benefit (expense)............... $ (5,740) $ (3,903) $ (15,462) $ (14,407)
=========== =========== =========== ==========
Segment earnings
Products Pipelines................ $ 101,583 $ 90,298 $ 298,691 $ 274,582
Natural Gas Pipelines............. 91,950 79,352 264,587 233,418
CO2............................... 55,148 37,318 151,717 99,406
Terminals......................... 56,561 51,331 164,710 152,749
----------- ----------- ----------- ----------
Total segment earnings(b)......... 305,242 258,299 879,705 760,155
Interest and corporate
administrative expenses (c) (87,900) (84,123) (275,391) (246,544)
----------- ----------- ----------- ----------
Total consolidated net income..... $ 217,342 $ 174,176 $ 604,314 $ 513,611
=========== =========== =========== ==========
Segment earnings before depreciation, depletion
and amortization expense and amortization of
excess cost of equity investments
Products Pipelines................ $ 120,353 $ 107,944 $ 353,903 $ 327,153
Natural Gas Pipelines............. 105,211 93,199 303,754 273,632
CO2............................... 86,118 53,121 239,813 142,260
Terminals......................... 67,168 60,460 196,040 179,886
----------- ----------- ----------- ----------
Total segment earnings before
DD&A(d) 378,850 314,724 1,093,510 922,931
Total consolidated depreciation,
depletion and amortiz. ......... (72,214) (55,031) (209,623) (158,594)
Total consol. amortization of
excess cost of invests.......... (1,394) (1,394) (4,182) (4,182)
Interest and corporate
administrative expenses......... (87,900) (84,123) (275,391) (246,544)
----------- ----------- ----------- ----------
Total consolidated net income .... $ 217,342 $ 174,176 $ 604,314 $ 513,611
=========== =========== =========== ==========
Capital expenditures
Products Pipelines................ $ 104,154 $ 25,845 $ 171,116 $ 64,161
Natural Gas Pipelines............. 23,831 20,421 77,904 74,135
CO2............................... 65,423 71,937 224,630 196,330
Terminals......................... 32,297 21,623 91,580 78,602
----------- ----------- ----------- ----------
Total consolidated capital
expenditures.................... $ 225,705 $ 139,826 $ 565,230 $ 413,228
=========== =========== =========== ==========
September 30, December 31,
------------- -------------
2004 2003
---------- ----------
Assets
Products Pipelines..............$3,465,381 $3,198,107
Natural Gas Pipelines.......... 3,265,481 3,253,792
CO2............................ 1,480,326 1,177,645
Terminals...................... 1,445,251 1,368,279
---------- ----------
Total segment assets........... 9,656,439 8,997,823
Corporate assets(e)............ 127,402 141,359
---------- ----------
Total consolidated assets...... $9,783,841 $9,139,182
========== ==========
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
(b) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses,
depreciation, depletion and amortization, and amortization of excess cost
of equity investments.
(c) Includes unallocated interest income, interest and debt expense, general
and administrative expenses, minority interest expense,
43
loss from early extinguishment of debt (2004 only) and cumulative effect
adjustment from a change in accounting principle (2003 only).
(d) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses.
(e) Includes cash, cash equivalents and certain unallocable deferred charges.
12. Pensions and Other Post-retirement Benefits
In connection with our acquisitions of SFPP, L.P. and Kinder Morgan Bulk
Terminals, Inc. in 1998, we acquired certain liabilities for pension and
post-retirement benefits. We provide medical and life insurance benefits to
current employees, their covered dependents and beneficiaries of SFPP and Kinder
Morgan Bulk Terminals. We also provide the same benefits to former salaried
employees of SFPP. Additionally, we will continue to fund these costs for those
employees currently in the plan during their retirement years. SFPP's
post-retirement benefit plan is frozen and no additional participants may join
the plan.
The noncontributory defined benefit pension plan covering the former
employees of Kinder Morgan Bulk Terminals is the Employee Benefit Plan for
Employees of Hall-Buck Marine Services Company and the benefits under this plan
were based primarily upon years of service and final average pensionable
earnings. Benefit accruals were frozen as of December 31, 1998 for the Hall-Buck
plan.
Net periodic benefit costs for these plans include the following components
(in thousands):
Other Post-retirement Benefits
-------------------------------------------------------------------
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------------------------------------------
2004 2003 2004 2003
---- ---- ---- ----
Net periodic benefit cost
Service cost........................ $ 28 $ 11 $ 84 $ 32
Interest cost....................... 97 202 291 605
Amortization of prior service cost.. (31) (156) (93) (467)
Actuarial gain...................... (244) - (732) -
------- ------- ------- -------
Net periodic (benefit) cost......... $ (150) $ 57 $ (450) $ 170
======= ======= ======= =======
Our net periodic benefit cost for the third quarter and first nine months of
2004 resulted in increases to income, largely due to the amortization of an
actuarial gain in the amount of $244,000 in each of the first three quarters of
2004. The actuarial gain was primarily related to the following:
o there have been changes to the plan for both 2003 and 2004 which reduced
liabilities, creating a negative prior service cost that is being amortized
each year; and
o there was a significant drop in the number of retired participants reported
as pipeline retirees by Burlington Northern Santa Fe, which holds a 0.5%
special limited partner interest in SFPP, L.P.
As of September 30, 2004, we estimate our overall net periodic
post-retirement benefit cost to be an annual credit of approximately $0.6
million. This amount could change in the remaining months of 2004 if there is a
significant event, such as a plan amendment or a plan curtailment, which would
require a remeasurement of liabilities.
As previously disclosed in our Annual Report on Form 10-K for the year ended
December 31, 2003, we expect to contribute approximately $0.3 million to our
post-retirement benefit plans in 2004. As of September 30, 2004, we have
contributed approximately $0.2 million and we presently anticipate contributing
an additional $0.1 million in the fourth quarter of 2004 for a total of $0.3
million.
13. Related Party Transactions
In June 2004, we bought two LM6000 gas-fired turbines and two boilers from a
subsidiary of KMI for their estimated fair market value of $21.1 million, which
we paid in cash. This equipment was a portion of the equipment that became
surplus as a result of KMI's decision to exit the power development business.
44
In July 2004, Plantation repaid a $10 million note outstanding and $175
million in outstanding commercial paper borrowings with funds of $190 million
borrowed from its owners. We loaned Plantation $97.2 million, which corresponds
to our 51.17% ownership interest, in exchange for a seven year note receivable
bearing interest at the rate of 4.72% per annum. For more information on this
transaction, see Note 7.
14.New Accounting Pronouncements
FIN 46 (revised December 2003)
In December 2003, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 46 (revised December 2003), "Consolidation of Variable
Interest Entities." This interpretation of Accounting Research Bulletin No. 51,
"Consolidated Financial Statements," addresses consolidation by business
enterprises of variable interest entities, which have one or more of the
following characteristics:
o the equity investment at risk is not sufficient to permit the entity to
finance its activities without additional subordinated financial support
provided by any parties, including the equity holders;
o the equity investors lack one or more of the following essential
characteristics of a controlling financial interest:
o the direct or indirect ability to make decisions about the entity's
activities thorough voting rights or similar rights;
o the obligation to absorb the expected losses of the entity; and
o the right to receive the expected residual returns of the entity; and
o the equity investors have voting rights that are not proportionate to their
economic interests, and the activities of the entity involve or are
conducted on behalf of an investor with a disproportionately small voting
interest.
The objective of this Interpretation is not to restrict the use of variable
interest entities but to improve financial reporting by enterprises involved
with variable interest entities. The FASB believes that if a business enterprise
has a controlling financial interest in a variable interest entity, the assets,
liabilities, and results of the activities of the variable interest entity
should be included in consolidated financial statements with those of the
business enterprise.
This Interpretation explains how to identify variable interest entities and
how an enterprise assesses its interests in a variable interest entity to decide
whether to consolidate that entity. It requires existing unconsolidated variable
interest entities to be consolidated by their primary beneficiaries if the
entities do not effectively disperse risks among parties involved. Variable
interest entities that effectively disperse risks will not be consolidated
unless a single party holds an interest or combination of interests that
effectively recombines risks that were previously dispersed.
An enterprise that consolidates a variable interest entity is the primary
beneficiary of the variable interest entity. The primary beneficiary of a
variable interest entity is the party that absorbs a majority of the entity's
expected losses, receives a majority of its expected residual returns, or both,
as a result of holding variable interests, which are the ownership, contractual,
or other monetary interests in an entity that change with changes in the fair
value of the entity's net assets excluding variable interests. The primary
beneficiary of a variable interest entity is required to disclose:
o the nature, purpose, size and activities of the variable interest entity;
o the carrying amount and classification of consolidated assets that are
collateral for the variable interest entity's obligations; and
45
o any lack of recourse by creditors (or beneficial interest holders) of a
consolidated variable interest entity to the general credit of the primary
beneficiary.
In addition, an enterprise that holds significant variable interests in a
variable interest entity but is not the primary beneficiary is required to
disclose:
o the nature, purpose, size and activities of the variable interest entity;
o its exposure to loss as a result of the variable interest holder's
involvement with the entity; and
o the nature of its involvement with the entity and date when the involvement
began.
Application of this Interpretation is required in financial statements of
public entities that have interests in variable interest entities or potential
variable interest entities commonly referred to as special-purpose entities for
periods ending after December 15, 2003. Application by public entities (other
than small business issuers) for all other types of entities is required in
financial statements for periods ending after March 15, 2004. This
Interpretation does not have any immediate effect on our consolidated financial
statements.
FASB Staff Position Nos. FAS 106-1 and FAS 106-2
In January 2004, the Financial Accounting Standards Board issued FASB Staff
Position FAS 106-1, "Accounting and Disclosure Requirements Related to the New
Medicare Prescription Drug, Improvement and Modernization Act of 2003" (the
"Act"). This Staff Position permits a sponsor of a post-retirement health care
plan that provides a prescription drug benefit to make a one-time election to
postpone accounting for the effects of the Act.
In May 2004, the Financial Accounting Standards Board issued FASB Staff
Position FAS 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003," which
supersedes Staff Position FAS 106-1 effective July 1, 2004. Staff Position FAS
106-2 provides transitional guidance for accounting for the effects of the Act
on the accumulated projected benefit obligation and periodic post-retirement
health care benefit expense. This Staff Position does not have any immediate
effect on our consolidated financial statements.
EITF 03-06
In March 2004, the Emerging Issues Task Force issued Statement No. 03-06, or
EITF 03-06, "Participating Securities and the Two-Class Method under Financial
Accounting Standards Board Statement No. 128, Earnings Per Share." EITF 03-06
addresses a number of questions regarding the computation of earnings per share
by companies that have issued securities other than common stock that
contractually entitle the holder to participate in dividends and earnings of the
company when, and if, it declares dividends on its common stock. The issue also
provides further guidance in applying the two-class method of calculating
earnings per share, clarifying what constitutes a participating security and how
to apply the two-class method of computing earnings per share once it is
determined that a security is participating, including how to allocate
undistributed earnings to such a security. EITF 03-06 was effective for fiscal
periods beginning after March 31, 2004. The adoption of EITF 03-06 did not
result in a change in our earnings per unit for any of the periods presented and
prior periods.
46
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
The following discussion and analysis of our financial condition and results
of operations provides you with a narrative on our financial results. It
contains a discussion and analysis of the results of operations for each segment
of our business, followed by a discussion and analysis of our financial
condition. The following discussion and analysis should be read in conjunction
with (i) our accompanying interim consolidated financial statements and related
notes (included elsewhere in this report and prepared in accordance with
accounting principles generally accepted in the United States of America), and
(ii) our consolidated financial statements, related notes and management's
discussion and analysis of financial condition and results of operations
included in our Annual Report on Form 10-K for the year ended December 31, 2003.
Critical Accounting Policies and Estimates
Certain amounts included in or affecting our consolidated financial
statements and related disclosures must be estimated, requiring us to make
certain assumptions with respect to values or conditions that cannot be known
with certainty at the time the financial statements are prepared. These
estimates and assumptions affect the amounts we report for assets and
liabilities and our disclosure of contingent assets and liabilities at the date
of the financial statements. We evaluate these estimates on an ongoing basis,
utilizing historical experience, consultation with experts and other methods we
consider reasonable in the particular circumstances. Nevertheless, actual
results may differ significantly from our estimates. Any effects on our
business, financial position or results of operations resulting from revisions
to these estimates are recorded in the period in which the facts that give rise
to the revision become known.
In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, the fair
values used to determine possible asset impairment charges, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. Further information about us
and information regarding our accounting policies and estimates that we
considered to be "critical" can be found in our Annual Report on Form 10-K for
the year ended December 31, 2003. There have not been any significant changes in
these policies and estimates during the first nine months of 2004.
Results of Operations
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands)
Earnings before depreciation, depletion and amortization expense
and amortization of excess cost of equity investments
Products Pipelines........................................... $ 120,353 $ 107,944 $ 353,903 $ 327,153
Natural Gas Pipelines........................................ 105,211 93,199 303,754 273,632
CO2.......................................................... 86,118 53,121 239,813 142,260
Terminals.................................................... 67,168 60,460 196,040 179,886
----------- ----------- ----------- -----------
Segment earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments(a)................................................. 378,850 314,724 1,093,510 922,931
Total consolidated depreciation, depletion and amortization
expense....................................................... (72,214) (55,031) (209,623) (158,594)
Total consolidated amortization of excess cost of equity (1,394) (1,394) (4,182) (4,182)
investments....................................................
Interest and corporate administrative expenses(b)................ (87,900) (84,123) (275,391) (246,544)
----------- ----------- ----------- -----------
Net income....................................................... $ 217,342 $ 174,176 $ 604,314 $ 513,611
=========== =========== =========== ===========
- ----------
(a) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses.
(b) Includes unallocated interest income, interest and debt expense, general
and administrative expenses, minority interest expense, loss from early
extinguishment of debt (2004 only) and cumulative effect adjustment from a
change in accounting principle (2003 only).
Our consolidated net income for the third quarter of 2004 was $217.3 million
($0.59 per diluted unit), compared to $174.2 million ($0.49 per diluted unit) in
the third quarter of last year. Net income for the nine months ended September
30, 2004 was $604.3 million ($1.62 per diluted unit), compared to $513.6 million
($1.49 per diluted unit)
47
in the first nine months of 2003. We earned total revenues of $2,014.7 million
and $1,650.8 million, respectively, in the three month periods ended September
30, 2004 and 2003, and revenues of $5,794.1 million and $5,104.1 million,
respectively, in the nine month periods ended September 30, 2004 and 2003.
The increases in our net income and diluted earnings per unit in the third
quarter and first nine months of 2004 compared to the third quarter and first
nine months of 2003, respectively, were primarily due to:
o higher earnings from both oil and gas producing activities and carbon
dioxide sales, transportation and related services;
o higher margins from our Texas intrastate natural gas pipeline group; and
o incremental earnings attributable to internal expansion projects and
strategic acquisitions completed since the third quarter of 2003.
Our net income for the first nine months of 2003 included a $3.5 million
benefit from the cumulative effect of a change in accounting principle. This
change in accounting principle 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. Before the cumulative effect adjustment, our net income for the
nine months ended September 30, 2003 totaled $510.1 million ($1.47 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.
Because our partnership agreement requires us to distribute 100% of our
available cash to our partners on a quarterly basis (available cash consists
primarily of all our cash receipts, less cash disbursements and changes in
reserves), we look at each period's earnings before all non-cash depreciation,
depletion and amortization expenses, including amortization of excess cost of
equity investments, as an important measure of our success in maximizing returns
to our partners. In each of the third quarter and third quarter year-to-date
periods of 2004, all four of our reportable business segments reported increases
in earnings before depreciation, depletion and amortization, compared to the
same periods of 2003, with the strongest growth coming from our CO2 (carbon
dioxide), Natural Gas Pipelines and Products Pipelines business segments.
We declared a record cash distribution of $0.73 per unit for the third
quarter of 2004 (an annualized rate of $2.92). This distribution is 11% higher
than the $0.66 per unit distribution we made for the third quarter of 2003. We
expect to declare cash distributions of at least $2.86 per unit for 2004;
however, no assurance can be given that we will be able to achieve this level of
distribution.
Products Pipelines
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- --------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 160,867 $ 145,874 $ 475,187 $ 435,575
Operating Expenses(a)...................................... (46,489) (42,784) (135,792) (124,450)
Earnings from equity investments........................... 7,658 6,989 21,610 22,619
Interest income and Other, net............................. 1,101 193 1,866 1,703
Income taxes............................................... (2,784) (2,328) (8,968) (8,294)
----------- ----------- ----------- -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments........................................... 120,353 107,944 353,903 327,153
Depreciation, depletion and amortization expense........... (17,951) (16,827) (52,751) (50,110)
Amortization of excess cost of equity investments.......... (819) (819) (2,461) (2,461)
----------- ----------- ----------- -----------
Segment earnings......................................... $ 101,583 $ 90,298 $ 298,691 $ 274,582
Refined product volumes (MMBbl)............................ 190.2 186.2 554.0 536.9
Natural gas liquids (MMBbl)................................ 10.1 9.4 31.1 30.6
----------- ----------- ----------- -----------
Total delivery volumes (MMBbl)(b).......................... 200.3 195.6 585.1 567.5
=========== =========== =========== ===========
- ----------
48
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
Our Products Pipelines segment reported earnings before depreciation,
depletion and amortization of $120.4 million on revenues of $160.9 million in
the third quarter of 2004. This compares to earnings before depreciation,
depletion and amortization of $107.9 million on revenues of $145.9 million in
the third quarter of 2003. For the comparable nine-month periods ended September
30, the segment reported earnings before depreciation, depletion and
amortization of $353.9 million on revenues of $475.2 million in 2004, and
earnings before depreciation, depletion and amortization of $327.2 million on
revenues of $435.6 million in 2003. The segment's $12.5 million (12%) third
quarter increase and $26.7 million (8%) nine-month increase in earnings before
depreciation, depletion and amortization in 2004 versus 2003 was driven by
higher earnings from our Pacific operations, our Southeast terminals and our
44.8% ownership interest in the Cochin pipeline system.
For our Pacific operations, earnings before depreciation, depletion and
amortization increased $5.9 million (10%) and $13.0 million (8%), respectively,
in the three and nine months ended September 30, 2004, when compared to the same
periods in 2003. The increases were primarily driven by incremental fees earned
from ethanol-related services, higher product gathering fees, and incremental
revenues related to the refined products terminal operations we acquired from
Shell Oil Products in October 2003. Our Southeast terminals, which include the
operations of 14 refined products terminals located in the southeastern United
States that we acquired in December 2003 and March 2004, reported earnings
before depreciation, depletion and amortization in the third quarter and first
nine months of 2004 of $3.6 million and $8.4 million, respectively. For our
proportional interest in Cochin, an approximate 1,900-mile pipeline that
transports natural gas liquids to the Midwestern United States and eastern
Canada petrochemical and fuel markets, earnings before depreciation, depletion
and amortization increased $1.6 million (92%) and $5.4 million (51%),
respectively, in the third quarter and first nine months of 2004, compared to
the same periods last year. The increases were primarily driven by higher
revenues from pipeline throughput deliveries. Cochin's earnings and revenues for
the third quarter of 2003 were negatively impacted by a pipeline rupture and
fire in July 2003 that led to the shut-down of the system for 29 days during the
quarter.
The overall increases in segment earnings before depreciation, depletion and
amortization in both the third quarter and first nine months of 2004, compared
to the same periods of 2003, were partly offset by lower earnings from our North
System and CALNEV Pipeline. Although combined earnings before depreciation,
depletion and amortization for these two businesses were essentially flat in the
comparative third quarter periods, the North System and CALNEV reported
decreases of $2.4 million (15%) and $1.7 million (5%), respectively, in earnings
before depreciation, depletion and amortization in the first nine months of 2004
versus the first nine months of 2003. For CALNEV, the decrease was driven by
lower ancillary terminal revenue and higher fuel, power and operating expenses.
For our North System, the decrease was primarily due to lower transport
revenues, related to an almost 9% decrease in throughput delivery volumes, and
to higher storage expenses. The decline in delivery volumes was primarily due to
a lack of propane supplies in the first half of 2004 caused by shippers reducing
line-fill and storage volume to lower levels than last year. In April 2004, we
filed a plan with the Federal Energy Regulatory Commission to produce a
line-fill service, which we expect will mitigate the supply problems we
experienced on our North System in the first half of 2004. Pursuant to this
plan, we have purchased $14.7 million of line-fill during the first nine months
of 2004.
Revenues for the segment increased $15.0 million (10%) in the third quarter
of 2004 versus the third quarter of 2003. Significant quarter-to-quarter
increases in revenues included $5.7 million in incremental revenues from our
recently acquired Southeast terminals, a $5.3 million (7%) increase from our
Pacific operations, largely due to higher terminal fees, and a $2.0 million
(45%) increase from Cochin, largely due to a 29% increase in delivery volumes
and higher average tariff rates. Combined, the segment benefited from a 2%
increase in the volume of refined products delivered during the third quarter of
2004 compared to the third quarter of 2003. Jet fuel delivery volumes, boosted
by strong military demand, and natural gas liquids delivery volumes, led by
higher deliveries from our Cypress Pipeline, increased 8% and 7%, respectively,
in the third quarter of 2004 compared to the third quarter of 2003.
Revenues for the segment increased $39.6 million (9%) in the first nine
months of 2004 compared to the first nine months of 2003. In addition to $13.6
million of incremental revenues attributable to the acquisition of our
49
Southeast terminals, other period-to-period increases in revenues included a
$14.1 million (6%) increase from our Pacific operations and a $9.1 million (51%)
increase in revenues from Cochin. Pacific's year-over-year increase was due to
both higher terminal revenues, discussed above, and higher transport revenues
due largely to an almost 3% increase in mainline delivery volumes. Cochin's
increase in revenues was mainly due to a 34% increase in delivery volumes, due
to the third quarter 2003 fire disruption and to lower product inventory levels
in western Canada in the first half of 2003 caused by lower profit margins on
propane production. Combined, the segment benefited from a 3% increase in the
volume of refined products delivered during the first nine months of 2004
compared to the first nine months of 2003. The overall increase in segment
revenues for the first nine months of 2004 compared to the same period of 2003
was partially offset by a $2.3 million (8%) decrease in revenues from our North
System, due to the decrease in throughput delivery volumes discussed above.
The segment's operating expenses increased $3.7 million (9%) and $11.3
million (9%), respectively, in the third quarter and first nine months of 2004,
compared to the same periods last year. The quarter-to-quarter increase in
operating expenses included incremental expenses of $2.1 million from our
Southeast terminals, an increase of $0.6 million (16%) from the North System,
primarily due to higher natural gas liquids storage expenses, and an increase of
$0.4 million (7%) in expenses such as labor and outside services incurred while
operating the Plantation Pipe Line Company. The $11.3 million increase in
year-over-year segment operating expenses included $5.2 million of expenses from
our Southeast terminals and increases of $1.4 million (17%) from each of the
Cochin and CALNEV pipeline systems. Cochin's increase was related to higher
expenses associated with the increased delivery volumes, and CALNEV's increase
was mostly due to higher fuel and power expenses in 2004 due to favorable credit
adjustments to electricity access and surcharge reserves taken in the first nine
months of 2003.
Earnings from equity investments consisted primarily of earnings related to
our approximate 51% ownership interest in Plantation Pipe Line Company and our
50% ownership interest in the Heartland Pipeline Company. Total equity earnings
for the third quarter and first nine months of 2004 increased $0.7 million (10%)
and decreased $1.0 million (4%), respectively, from comparable periods in 2003.
The quarter-to-quarter increase resulted primarily from a $0.4 million (6%)
increase in equity earnings from our investment in Plantation, due to higher net
income driven by a 5% increase in gasoline delivery volumes. The decrease in
equity earnings in the first nine months of 2004 versus the first nine months of
2003 includes a $1.4 million (6%) decrease in equity earnings from Plantation,
mainly due to a $3.2 million expense recorded in the first quarter of 2004 for
our share of an environmental litigation settlement reached between Plantation
and various plaintiffs. In 2005, we expect to recover the cost of the settlement
under various insurance policies; furthermore, the decrease in equity earnings
from Plantation that resulted from higher litigation settlement costs was
partially offset by an increase associated with higher product delivery
revenues, due to a 4% increase in throughput delivery volumes in the first nine
months of 2004 compared to the first nine months of 2003.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased $1.1 million (6%) and $2.6
million (5%), respectively, in the third quarter and first nine months of 2004,
compared to the same periods last year. The increases were primarily due to
incremental depreciation charges associated with our Pacific operations, related
to the capital spending we have made since the end of the third quarter of 2003,
and our Southeast terminals, which we acquired after the third quarter of 2003.
50
Natural Gas Pipelines
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- --------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 1,598,554 $ 1,321,651 $ 4,591,293 $ 4,143,765
Operating Expenses(a)...................................... (1,498,030) (1,234,149) (4,301,857) (3,887,905)
Earnings from equity investments........................... 5,280 5,877 14,558 18,260
Other, net................................................. 29 515 1,155 1,040
Income taxes............................................... (622) (695) (1,395) (1,528)
----------- ----------- ----------- -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments............................................ 105,211 93,199 303,754 273,632
Depreciation, depletion and amortization expense........... (13,191) (13,777) (38,959) (40,006)
Amortization of excess cost of equity investments.......... (70) (70) (208) (208)
----------- ----------- ----------- -----------
Segment earnings......................................... $ 91,950 $ 79,352 $ 264,587 $ 233,418
=========== =========== =========== ===========
Natural gas transport volumes (Bcf)(b)..................... 310.6 317.6 868.0 901.6
=========== =========== =========== ===========
Natural gas sales volumes (Bcf)(c)......................... 260.9 242.9 748.8 677.8
=========== =========== =========== ===========
- ----------
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
(b) Includes Kinder Morgan Interstate Gas Transmission, Texas Intrastate group
and Trailblazer pipeline volumes.
(c) Includes Texas Intrastate group volumes.
Our Natural Gas Pipelines business segment reported earnings before
depreciation, depletion and amortization of $105.2 million on revenues of
$1,598.6 million in the third quarter of 2004. This compares to earnings before
depreciation, depletion and amortization of $93.2 million on revenues of
$1,321.7 million in the third quarter of 2003. For the nine-month periods ended
September 30, the segment reported earnings before depreciation, depletion and
amortization of $303.8 million on revenues of $4,591.3 million in 2004, and
earnings before depreciation, depletion and amortization of $273.6 million on
revenues of $4,143.8 million in 2003.
The segment's $12.0 million (13%) and $30.2 million (11%) increases in
earnings before depreciation, depletion and amortization expenses in the third
quarter and first nine months of 2004, respectively, versus the same periods
last year were mainly driven by higher earnings from our Texas intrastate
natural gas pipeline group, which includes the operations of the following four
natural gas pipeline systems: Kinder Morgan Tejas, Kinder Morgan Texas Pipeline,
North Texas Pipeline and Mier-Monterrey Mexico Pipeline. Combined, the
intrastate group reported increases in earnings before depreciation, depletion
and amortization of $7.1 million (15%) and $36.5 million (27%), respectively, in
the third quarter and first nine months of 2004, compared to the same periods of
2003. These increases were primarily due to improved margins and higher volumes
from natural gas sales activities, and higher fee revenues from the segmented
gas services provided within the State of Texas.
We also benefited from higher earnings before depreciation, depletion and
amortization expenses from our Kinder Morgan Interstate Gas Transmission system,
which owns approximately 5,000 miles of natural gas transmission lines and
provides transportation and storage services throughout the Rocky Mountain
region. KMIGT reported increases of $10.2 million (46%) and $5.0 million (7%),
respectively, in earnings before depreciation, depletion and amortization in the
three and nine months ended September 30, 2004, when compared to the same
periods last year. These increases were primarily due to higher natural gas
sales revenues in the third quarter of 2004, driven by volume increases largely
associated with additional gas capacity at KMIGT's Cheyenne Market Center. The
Cheyenne Market Center, which began providing service to customers in June 2004,
offers firm natural gas transportation storage capabilities and allows for
transportation between and interconnections with other pipelines at applicable
points located in the vicinity of the Cheyenne Hub in Weld County, Colorado and
our Huntsman storage facility in Cheyenne County, Nebraska.
The segment's overall increases in earnings before depreciation, depletion
and amortization for the third quarter and first nine months of 2004, compared
to the same periods of 2003, were partly offset by lower earnings from our
Trailblazer Pipeline Company. Trailblazer reported decreases of $5.3 million
(36%) and $9.1 million (24%),
51
respectively, in earnings before depreciation, depletion and amortization in the
three and nine months ended September 30, 2004, when compared to the same prior
year periods. The period-to-period decreases were primarily due to lower
revenues, due to both timing on imbalance cashouts and lower gas transportation
revenues in 2004 versus 2003. The decreases in transportation revenues were due
to lower tariff rates that became effective January 1, 2004, pursuant to a rate
case settlement.
Revenues earned by our Natural Gas Pipelines segment during the third quarter
and first nine months of 2004 increased $276.9 million (21%) and $447.5 million
(11%), respectively, over comparable periods in 2003. The increases from both
periods were principally due to higher natural gas sales revenues earned by our
Texas intrastate pipeline system. The system purchases and sells significant
volumes of natural gas and reported increases in natural gas sales revenues of
$266.1 million (22%) and $433.8 million (11%), respectively, in the third
quarter and first nine months of 2004, versus the same periods of 2003. The
increase in the third quarter of 2004 compared to the third quarter of 2003
resulted from a 14% increase in average gas prices (from $4.93 per dekatherm in
2003 to $5.61 per dekatherm in 2004) and a 7% increase in sales volumes. The
increase in the first nine months of 2004 compared to the first nine months of
2003 resulted from a slight 1% increase in average sale prices (from $5.57 per
dekatherm in 2003 to $5.62 per dekatherm in 2004) and a 10% increase in gas
sales volumes. Revenues from our KMIGT system increased $13.6 million (41%) and
$8.7 million (8%), respectively, in the third quarter and first nine months of
2004, compared to the same periods last year, and revenues from our Trailblazer
pipeline system decreased $4.0 million (27%) and $10.4 million (23%),
respectively, in the same comparable periods. The period-to-period changes in
revenues from our two Rocky Mountain pipelines are described in the preceding
paragraph.
The segment's operating expenses, including natural gas purchase costs,
increased $263.9 million (21%) and $414.0 million (11%), respectively, in the
third quarter and first nine months of 2004, versus the same periods of 2003.
The overall increases in operating expenses for the two comparable periods were
mainly due to higher natural gas purchase costs incurred by our Kinder Morgan
Tejas and Kinder Morgan Texas Pipeline systems. The higher gas purchase costs
reflected the growth in both natural gas sales volumes, as described above in
our revenues discussion, and in the average cost of natural gas. Combined, the
two systems reported increases of $255.5 million (21%) and $404.7 million (11%),
respectively, in the costs of gas sold in the third quarter and first nine
months of 2004, compared to the same periods in 2003. The average price of
purchased gas increased 14% (from $4.85 per dekatherm in the third quarter of
2003 to $5.51 per dekatherm in the third quarter of 2004) and 1% (from $5.47 per
dekatherm in the first nine months of 2003 to $5.51 per dekatherm in the first
nine months of 2004), respectively, in the third quarter and first nine months
of 2004, compared to the same periods last year.
Earnings from equity investments for the third quarter of 2004 were
essentially flat versus the same period in 2003; however, equity earnings
decreased $3.7 million (20%) in the first nine months of 2004 compared to the
same period last year. The decrease was chiefly due to lower earnings from our
49% investment in the Red Cedar Gas Gathering Company, mainly due to higher
operational sales of natural gas by Red Cedar in the first nine months of 2003.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, decreased slightly in both the three
and nine month periods ended September 30, 2004, compared to the same periods in
2003. The decreases, $0.6 million (4%) in the comparable third quarters, and
$1.0 million (3%) in the comparable nine month periods, resulted from lower
period-to-period depreciation expense on our Trailblazer Pipeline Company due to
the rate case settlement which became effective January 1, 2004. Trailblazer's
lower depreciation expenses more than offset normal increases in depreciation
charges from other segment operations.
52
CO2
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 121,777 $ 66,577 $ 337,935 $ 169,664
Operating Expenses(a)...................................... (43,331) (21,372) (123,620) (54,175)
Earnings from equity investments........................... 7,711 7,978 25,552 26,848
Other, net................................................. 10 (52) 42 (47)
Income taxes............................................... (49) (10) (96) (30)
----------- ----------- ----------- ------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments............................................ 86,118 53,121 239,813 142,260
Depreciation, depletion and amortization expense(b)........ (30,465) (15,298) (86,583) (41,341)
Amortization of excess cost of equity investments.......... (505) (505) (1,513) (1,513)
----------- ----------- ----------- ------------
Segment earnings......................................... $ 55,148 $ 37,318 $ 151,717 $ 99,406
=========== =========== =========== ============
Carbon dioxide volumes transported (Bcf)(c)................ 149.4 129.2 470.5 336.1
=========== =========== =========== ============
SACROC oil production (MBbl/d)(d).......................... 27.7 20.9 27.1 19.2
=========== =========== =========== ============
Yates oil production (MBbl/d)(d)........................... 20.2 19.7 18.8 19.1
=========== =========== =========== ============
Natural gas liquids sales volumes (MBbl/d)(e).............. 7.7 3.4 7.3 3.6
=========== =========== =========== ============
Realized weighted average oil price per Bbl(f)(g).......... $ 25.21 $ 23.50 $ 25.28 $ 24.05
=========== =========== =========== ============
Realized weighted average natural gas liquids price per
Bbl(g)................................................... $ 33.05 $ 21.47 $ 29.25 $ 21.31
=========== =========== =========== ============
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) Includes expenses associated with oil and gas production activities in the
amount of $26,901 for the third quarter of 2004, $12,370 for the third
quarter of 2003, $75,501 for the first nine months of 2004 and $33,158 for
the first nine months of 2003. Includes expenses associated with sales and
transportation services activities in the amount of $3,564 for the third
quarter of 2004, $2,928 for the third quarter of 2003, $11,082 for the
first nine months of 2004 and $8,183 for the first nine months of 2003.
(c) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos
pipeline volumes.
(d) Represents 100% production from the field.
(e) Net to Kinder Morgan.
(f) Includes all Kinder Morgan crude oil properties.
(g) Hedge gains/losses for oil and natural gas liquids are included with crude
oil.
Our CO2 business segment reported earnings before depreciation, depletion and
amortization of $86.1 million on revenues of $121.8 million in the third quarter
of 2004. These amounts compare to earnings before depreciation, depletion and
amortization of $53.1 million on revenues of $66.6 million in the same quarter
last year. For the comparable nine-month periods ended September 30, our CO2
segment reported earnings before depreciation, depletion and amortization of
$239.8 million on revenues of $337.9 million in 2004, and earnings before
depreciation, depletion and amortization of $142.3 million on revenues of $169.7
million in 2003.
Both the $33.0 million (62%) increase in earnings before depreciation,
depletion and amortization in the third quarter of 2004 over the third quarter
of 2003 and the $97.5 million (69%) increase in the first nine months of 2004
over the first nine months of 2003 were driven by higher earnings from oil and
gas producing activities, higher deliveries of carbon dioxide, and our November
1, 2003 acquisitions of an additional 42.5% interest in the Yates oil field
unit, the crude oil gathering system surrounding the Yates field unit and an
additional 65% ownership interest in the Pecos Carbon Dioxide Pipeline Company.
The acquisition of the additional 42.5% interest in the Yates unit increased our
ownership interest to nearly 50% and allowed us to become operator of the field.
For the comparable nine month periods, we also benefited, in 2004, from having a
full nine months of operations that included an additional ownership interest in
the SACROC oil field unit. Effective June 1, 2003, we acquired MKM Partners,
L.P.'s 12.75% ownership interest in the SACROC unit, thereby increasing our
interest in SACROC to approximately 97%. Both the SACROC and Yates oil field
units are located in the Permian Basin area of West Texas. For more information
on our acquisitions, see Note 2 to our consolidated financial statements,
included elsewhere in this report.
53
Our CO2 segment's oil and gas producing activities reported increases of
$30.3 million (130%) and $75.0 million (104%), respectively, in earnings before
depreciation, depletion and amortization for the three and nine months ended
September 30, 2004, when compared to the same periods a year ago. The growth in
oil and gas related activities was attributable to increased oil production, as
average oil production for the third quarter of 2004, compared to the third
quarter of 2003, increased almost 33% at the SACROC unit located in Scurry
County, Texas and by almost 3% at the Yates unit, located south of Midland,
Texas. For the two units combined, we benefited from increases of 18% and 20%,
respectively, in daily oil production volumes for the third quarter and first
nine months of 2004, compared to the same periods a year ago. We also benefited
from increases of 7% and 5%, respectively, in our realized weighted average
price of oil per barrel in the third quarter and first nine months of 2004,
versus the same time periods in 2003. We mitigate our commodity price risk
through a long-term hedging strategy that is intended to generate more stable
realized prices. For more information on our hedging activities, see Note 10 to
our consolidated financial statements, included elsewhere in this report.
For the first nine months of 2004, capital expenditures for our CO2 business
segment totaled $224.6 million, which was $28.3 million (14%) higher than the
amount of capital expenditures made during the first nine months of 2003. The
increase largely represented incremental spending for new well and injection
compression facilities at the SACROC and Yates oil field units in order to
enhance oil recovery from carbon dioxide injection.
Our CO2 segment's carbon dioxide sales and transportation activities reported
increases of $2.7 million (9%) and $22.5 million (32%), respectively, in
earnings before depreciation, depletion and amortization for the three and nine
months ended September 30, 2004, when compared to the same periods last year.
The increases were driven by higher revenues from carbon dioxide sales and
deliveries, mainly due to the continued expansions and additional ownership
interests at the SACROC and Yates oil field units. We also benefited from the
inclusion of a full nine months of operations from our Centerline carbon dioxide
pipeline, completed in May 2003. We do not recognize profits on carbon dioxide
sales to ourselves.
Revenues earned by our CO2 business segment during the third quarter and
first nine months of 2004 increased $55.2 million (83%) and $168.2 million
(99%), respectively, over comparable periods in 2003. The increases were mainly
due to higher crude oil and gasoline plant product sales revenues, driven by
higher oil and gas production volumes, higher average crude oil and gasoline
product prices, and the additional working interest in the Yates oil field that
we acquired since the end of the third quarter of 2003. Combined, the assets we
acquired on November 1, 2003 contributed incremental revenues of approximately
$24.1 million and $81.7 million, respectively, in the third quarter and first
nine months of 2004 versus the same periods a year-ago.
Additionally, in 2004, we benefited from higher revenues from carbon dioxide
sales and transportation. The quarter-to-quarter increase was primarily due to
higher average prices on carbon dioxide sales and higher transportation
revenues, the nine-month period-to-period increase was mainly due to higher
prices and volumes from sales of carbon dioxide, and to increases in carbon
dioxide delivery volumes throughout the Permian Basin. Combined deliveries of
carbon dioxide on our Central Basin Pipeline, our majority-owned Canyon Reef
Carriers and Pecos Pipelines, our Centerline Pipeline, and our 50% owned Cortez
Pipeline, which is accounted for under the equity method of accounting,
increased 20.2 billion cubic feet (16%) and 134.4 billion cubic feet (40%),
respectively, in the third quarter and first nine months of 2004, compared to
the same periods in 2003.
Operating expenses incurred during the third quarter and first nine months of
2004 increased $22.0 million (103%) and $69.4 million (128%), respectively, over
the same periods in 2003. Both period-to-period increases resulted from higher
operating and maintenance expenses, higher fuel and power costs, and higher
production taxes, all due to the increases in oil production volumes and carbon
dioxide delivery volumes.
Earnings from equity investments for the third quarter of 2004 were
essentially flat versus the same period in 2003. For the comparable nine month
periods, earnings from equity investments decreased $1.3 million (5%) in 2004
versus 2003. The decrease resulted from the absence of equity earnings, in 2004,
from our previous 15% ownership interest in MKM Partners, L.P. Following our
June 1, 2003 acquisition of its 12.75% interest in the SACROC unit, MKM Partners
was dissolved effective June 30, 2003, and the lack of equity earnings in the
first nine months of 2004 more than offset a $3.7 million (17%) increase in
equity earnings from our 50% investment in the Cortez Pipeline Company. The
increase in equity earnings from Cortez was mainly due to higher carbon dioxide
delivery volumes in the first nine months of 2004 versus the same period in
2003.
54
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased $15.2 million (96%) and
$45.2 million (106%), respectively, in the third quarter and first nine months
of 2004, when compared to the same periods last year. The increases were
primarily due to higher oil production, higher unit-of-production depletion
rates and the acquisition of our additional interests in the SACROC and Yates
oil fields.
Terminals
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 133,461 $ 116,740 $ 389,682 $ 355,123
Operating Expenses(a)...................................... (63,943) (55,723) (188,336) (170,780)
Earnings from equity investments........................... (4) (3) 3 37
Other, net................................................. (61) 316 (306) 61
Income taxes............................................... (2,285) (870) (5,003) (4,555)
----------- ----------- ----------- -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments............................................ 67,168 60,460 196,040 179,886
Depreciation, depletion and amortization expense........... (10,607) (9,129) (31,330) (27,137)
Amortization of excess cost of equity investments.......... - - - -
----------- ----------- ----------- -----------
Segment earnings......................................... $ 56,561 $ 51,331 $ 164,710 $ 152,749
Bulk transload tonnage (MMtons)(b)......................... 16.6 13.3 48.3 43.5
=========== =========== =========== ===========
Liquids leaseable capacity (MMBbl)......................... 36.5 36.0 36.5 36.0
=========== =========== =========== ===========
Liquids utilization %...................................... 95.8% 95.5% 95.8% 96.0%
=========== =========== =========== ===========
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs; excludes operatorship of LAXT bulk terminal.
Our Terminals segment includes the operations of our coal, petroleum coke and
other dry-bulk material terminals, as well as all the operations of our
petroleum and petrochemical-related liquids terminal facilities. For the third
quarter of 2004, our Terminals segment reported earnings before depreciation,
depletion and amortization of $67.2 million on revenues of $133.5 million. This
compares to earnings before depreciation, depletion and amortization of $60.5
million on revenues of $116.7 million in the third quarter last year. For the
comparable nine-month periods, the segment reported earnings before
depreciation, depletion and amortization of $196.0 million on revenues of $389.7
million in 2004, and earnings before depreciation, depletion and amortization of
$179.9 million on revenues of $355.1 million in 2003.
Earnings before depreciation, depletion and amortization in the third quarter
and first nine months of 2004 increased $6.7 million (11%) and $16.1 million
(9%), respectively, over comparable periods in 2003. The increases were driven
by higher revenues from both our bulk terminal businesses, due to higher
transfer volumes of bulk products, and our liquids terminals businesses, due to
high demand for storage and distribution services offered for petroleum and
liquid chemical products.
Period-to-period increases in segment revenues and earnings before
depreciation, depletion and amortization in the third quarter and first nine
months of 2004 were driven by increases at our Gulf Coast liquids terminals
located in Pasadena and Galena Park, Texas; our Northeast terminals, which
include our Port Newark, New Jersey bulk terminal and our Carteret and Perth
Amboy, New Jersey liquids terminals; our Mid-Atlantic terminals, which include
our Chesapeake Bay, Maryland bulk terminal and our Pier IX bulk terminal located
in Newport News, Virginia; and our 66 2/3% ownership interest in the
International Marine Terminals Partnership, a multi-purpose facility located in
Port Sulphur, Louisiana. We also benefited from incremental earnings and
revenues from both the Kinder Morgan Tampaplex marine terminal and the inland
bulk storage warehouse facility that are located in Tampa, Florida and were
acquired in December 2003.
55
Revenues earned by our Terminals segment during the third quarter and first
nine months of 2004 increased $16.8 million (14%) and $34.6 million (10%),
respectively, over comparable periods in 2003. The overall increase in revenues
in the third quarter of 2004 compared to the third quarter of 2003 includes
increases of $3.9 million largely related to higher coal and petroleum coke
tonnage volumes at Chesapeake Bay, $2.3 million from our acquired Tampa bulk
terminal operations, $2.2 million from higher salt tonnage transfers and
services rendered at Port Newark, $2.1 million from higher coal and dry-bulk
tonnage volumes and higher dockage fees at IMT, and $1.8 million from higher
synfuel and coal transfer revenues at Pier IX.
The $34.6 million increase in segment revenues in the first nine months of
2004 versus the same period last year was driven by increases of $7.4 million
from our acquired Tampa bulk terminal operations, $6.0 million from higher
volumes and dockage fees at IMT and $4.6 million from our Chesapeake Bay
facility, primarily due to strong third quarter 2004 revenues earned by
providing stevedoring services and storage and transportation for products such
as petroleum coke, coal, iron and steel slag and other bulk materials. Other
period-to-period increases in revenues included $4.5 million from our Pasadena
and Galena Park liquids facilities, $4.1 million from our Carteret and Perth
Amboy liquids facilities, $3.7 million from Pier IX and $2.8 million from Port
Newark. The increases from the four liquids facilities were primarily due to
higher throughput volumes, contract price escalations (per the terms of such
contracts), and expansion projects and improvements that have been completed
since the end of the third quarter of 2003. As of September 30, 2004, liquids
terminals expansion projects completed since the end of the third quarter of
2003 have increased total liquids leaseable capacity by approximately 500,000
barrels (1%), more than offsetting a slight decrease in our liquids utilization
rate.
Operating expenses increased $8.2 million (15%) and $17.6 million (10%),
respectively, in the third quarter and first nine months of 2004 versus the same
periods of 2003. The quarter-to-quarter increase in segment operating expenses
includes an increase of $2.5 million from our Chesapeake Bay facility, due to
higher payroll, wharfage costs, and other expenses associated with the increase
in tonnage volumes. Also, each of our Tampaplex, Port Newark and IMT facilities
reported increases of $1.3 million in operating expenses during the third
quarter of 2004 versus the third quarter of 2003. The increases were primarily
due to higher operating, maintenance and payroll expenses, including trucking,
equipment rentals, docking expenses and fuel and electricity charges, all
related to increased dry-bulk transfer volumes and ship conveyance activities.
The $17.6 million increase in operating expenses in the first nine months of
2004 compared to the first nine months of 2003 includes increases of $4.0
million from IMT, $3.2 million from the acquired Kinder Morgan Tampaplex
terminal, $2.8 million from our Chesapeake Bay facility, $1.9 million from Port
Newark, and $1.6 million from Pier IX, all primarily driven by higher operating,
maintenance and utility expenses related to our 11% increase in total bulk
tonnage volumes in the first nine months of 2004 versus the first nine months of
2003.
Other income items were essentially flat year-over-year. Income tax expenses
during the third quarter and first nine months of 2004 increased $1.4 million
and $0.4 million, respectively, over comparable periods in 2003. The increases
were due to higher taxable income from Kinder Morgan Bulk Terminals, Inc., the
tax-paying entity that owns many of our bulk terminal businesses.
Non-cash depreciation, depletion and amortization charges increased $1.5
million (16%) and $4.2 million (15%), respectively, in the third quarter and
first nine months of 2004, over comparable periods in 2003. The increases
reflect higher depreciation charges due to the additional capital spending and
acquisitions we have made since the end of the third quarter of 2003, including
additional transfers of completed project costs into depreciable plant.
Other
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands-income/(expense))
General and administrative expenses........................ $ (37,816) $ (36,818) $ (125,527) $ (108,544)
Unallocable interest, net.................................. (47,295) (44,714) (141,108) (134,535)
Minority interest.......................................... (2,789) (2,591) (7,332) (6,930)
Loss from early extinguishment of debt..................... - - (1,424) -
Cumulative effect adjustment from change in accounting
principle................................................ - - - 3,465
----------- ----------- ----------- -----------
Interest and corporate administrative expenses.......... $ (87,900) $ (84,123) $ (275,391) $ (246,544)
=========== =========== =========== ===========
56
Items not attributable to any segment include general and administrative
expenses, unallocable interest income, interest expense and minority interest.
Also, we included both the $1.4 million loss from our early extinguishment of
debt in May 2004 and the $3.5 million benefit from the cumulative effect
adjustment of a change in accounting for asset retirement obligations as of
January 1, 2003 (discussed above), as items not attributable to any business
segment. The loss from the early extinguishment of debt represented the excess
of the price we paid to repurchase and retire the principal amount of $84.3
million of tax-exempt industrial revenue bonds over the bonds' carrying value.
Pursuant to certain provisions that gave us the right to call and retire the
bonds prior to maturity, we took advantage of the opportunity to refinance at
lower rates. For more information on our early extinguishment of debt, see Note
7 to our consolidated financial statements included elsewhere in this report.
Our general and administrative expenses, which include such items as salaries
and employee-related expenses, payroll taxes, legal fees, insurance and office
supplies and rentals, increased $1.0 million (3%) and $17.0 million (16%),
respectively, in the third quarter and first nine months of 2004, when compared
to the same periods last year. The quarter-to-quarter increase resulted
primarily from higher employee benefit and corporate service expenses, including
legal, information technology and human resources. The year-to-year increase was
mainly due to higher employee bonus and benefit expenses and higher corporate
and employee-related insurance expenses.
Interest expense, net of interest income, increased $2.6 million (6%) and
$6.6 million (5%), respectively, in the third quarter and first nine months of
2004, versus the same year-earlier periods. Although our average borrowing rates
were essentially flat across both years, we incurred higher interest charges as
a result of higher average borrowings during both the three and nine month
periods ended September 30, 2004, compared to the three and nine month periods
ended September 30, 2003. The increases in average borrowings were primarily due
to higher capital spending related to internal expansions and improvements, and
to incremental borrowings made in connection with acquisition expenditures. For
more information on our capital expansion and acquisition expenditures, see
"Financial Condition - Investing Activities," discussed below.
Minority interest, which represents the deduction in our consolidated net
income attributable to all outstanding ownership interests in our operating
limited partnerships and their consolidated subsidiaries that are not held by
us, remained relatively flat across both the comparable three and nine month
periods of 2004 and 2003.
Financial Condition
We attempt to maintain an overall conservative capital structure, with a
target mix of approximately 50% equity and 50% debt. The following table
illustrates the sources of our invested capital (dollars in thousands). In
addition to our results of operations, these balances are affected by our
financing activities as discussed below:
September 30, December 31,
------------- ------------
2004 2003
---- ----
Long-term debt, excluding market value of interest rate
swaps................................................... $ 4,616,724 $ 4,316,678
Minority interest......................................... 39,877 40,064
Partners' capital......................................... 3,406,377 3,510,927
------------ ------------
Total capitalization................................... 8,062,978 7,867,669
Short-term debt, less cash and cash equivalents........... (6,426) (21,081)
------------ ------------
Total invested capital.................................. $ 8,056,552 $ 7,846,588
============ ============
Capitalization:
Long-term debt, excluding market value of interest rate
swaps................................................ 57.3% 54.9%
Minority interest....................................... 0.5% 0.5%
Partners' capital....................................... 42.2% 44.6%
------------ ------------
100.0% 100.0%
============ ============
Invested Capital:
Total debt, less cash and cash equivalents and excluding
market value of interest rate swaps................ 57.2% 54.7%
Partners' capital and minority interest................. 42.8% 45.3%
------------ ------------
100.0% 100.0%
============ ============
57
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 retained
cash (resulting from including i-units in the determination of cash
distributions per unit but paying quarterly distributions on i-units in
additional i-units rather than cash), additional borrowings, the issuance
of additional common units or the issuance of additional i-units to KMR;
o interest payments with 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.
Through the nine months ended September 30, 2004, we have continued to
generate strong cash flow from operations, and we provide for additional
liquidity by maintaining a sizable amount of combined cash and excess borrowing
capacity related to our commercial paper program and long-term revolving credit
facility.
In August 2004, we replaced our previous 364-day and three-year credit
facilities, which had a combined borrowing capacity of $1.05 billion, with a new
five-year senior unsecured revolving credit facility that has a borrowing
capacity of $1.25 billion. The new facility includes covenants and requires
payments of facility fees that are similar in nature to the covenants and
facility fees required by our previous bank facilities as discussed in our
Annual Report on Form 10-K for the year ended December 31, 2003. However, our
current facility no longer requires us to maintain a tangible net worth of at
least $2.1 billion as of the last day of any fiscal quarter. Currently, we do
not anticipate any liquidity problems.
As a publicly traded limited partnership, our common units are attractive
primarily to individual investors, although such 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. We are able to access this segment of the capital market through
KMR's purchases of i-units issued by us with the proceeds from the sale of KMR
shares to institutional investors.
As of September 30, 2004, our budgeted expenditures for the remaining three
months of 2004 for sustaining capital spending were approximately $38 million,
based on our 2004 revised budget. This amount has been committed primarily for
the purchase of plant and equipment and is based on the payments we expect to
make as part of our 2004 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, tariffs 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 provide assurance 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, future results of operations or future cash flows.
Operating Activities
Net cash provided by operating activities was $837.9 million for the nine
months ended September 30, 2004, versus $507.3 million in the comparable period
of 2003. The period-to-period increase of $330.6 million (65%) in cash flow from
operations was primarily due to:
58
o a $154.6 million increase in cash from overall higher partnership income,
net of non-cash items including depreciation charges and undistributed
earnings from equity investments;
o a $148.9 million increase in cash inflows relative to net changes in
working capital items; and
o a $44.9 million increase related to transportation rate reparation and
refund payments made in the first nine months of 2003.
The higher partnership income reflects the record levels of segment earnings
before depreciation, depletion and amortization reported in the first nine
months of 2004 and discussed above in "Results of Operations." The favorable
inflows from working capital in 2004 were mainly related to timing differences
in the collection and payment of both trade and related party receivables and
payables. The reparation and refund payments were mandated by the Federal Energy
Regulatory Commission as part of a settlement reached between shippers and our
Pacific operations pursuant to rates charged by our Pacific operations on the
interstate portion of their products pipelines.
Partially offsetting the overall increase in cash provided by operating
activities was an $11.7 million (19%) decrease in distributions received from
equity investments, primarily due to the dissolution of MKM Partners, L.P. on
June 30, 2003, which eliminated our 15% equity ownership interest.
Investing Activities
Net cash used in investing activities was $713.2 million for the nine month
period ended September 30, 2004, compared to $464.1 million in the comparable
2003 period. The $249.1 million (54%) increase in cash used in investing
activities was primarily attributable to higher expenditures made for both
capital additions on our existing asset infrastructure and strategic
acquisitions.
Including expansion and maintenance projects, our capital expenditures were
$565.2 million in the first nine months of 2004 versus $413.2 million in the
same year-ago period. The $152.0 million (37%) increase was mainly driven by
higher capital investment in our Products Pipelines and CO2 business segments.
Additionally, for the nine months ended September 30, 2004, our acquisition
outlays totaled $142.5 million, including cash outflows of $90.8 million for the
acquisition of Kinder Morgan Wink Pipeline, L.P., formerly Kaston Pipeline
Company, L.P., and $48.1 million for the acquisition of seven refined petroleum
products terminals from Exxon Mobil Corporation. For the nine months ended
September 30, 2003, our acquisition of assets totaled $40.7 million, including
$23.3 million for the acquisition of an additional 12.75% ownership interest in
the SACROC oil field unit in West Texas from MKM Partners, L.P. For more
information on our acquisitions, see Note 2 to our consolidated financial
statements included elsewhere in this report.
Our sustaining capital expenditures were $82.9 million for the first nine
months of 2004 compared to $62.4 million for the first nine months of 2003.
Financing Activities
Net cash used in financing activities amounted to $141.6 million for the nine
months ended September 30, 2004 and $41.8 million for the same prior-year
period. The $99.8 million period-to-period increase in cash used in financing
activities resulted primarily from lower cash inflows from overall debt
financing activities and from higher partnership distributions. The overall
increase in cash used in financing activities was partially offset by an
increase in cash inflows from partnership equity issuances.
In the first nine months of 2004, we received $188.0 million from debt
financing activities, which included both issuances and payments of debt, loans
to related parties and debt issuance costs. This amount was $92.7 million (33%)
lower than the amount we received in the first nine months of 2003, as $99.7
million of net incremental commercial paper borrowings in the first nine months
of 2004 were more than offset by the following three funding transactions:
59
o In May 2004, we paid $84.3 million to redeem and retire the principal
amount of four series of tax-exempt bonds related to certain liquids
terminal facilities. Pursuant to certain provisions that gave us the right
to call and retire the bonds prior to maturity, we took advantage of the
opportunity to refinance at lower rates;
o In July 2004, we loaned $97.2 million, which corresponds to our 51.17%
ownership interest, to Plantation Pipe Line Company to allow Plantation to
pay all of its outstanding credit facility and commercial paper borrowings.
In exchange, we received a seven year note receivable bearing interest at
the rate of 4.72% per annum; and
o In September 2004, we paid the $9.5 million outstanding balance under
Kinder Morgan Wink Pipeline, L.P.'s note payable to Western Refining
Company, L.P.
Distributions to partners, consisting of our common and Class B unitholders,
our general partner and minority interests, totaled $581.4 million in the first
nine months of 2004 compared to $500.7 million in the same year-earlier period.
The increase in distributions was due to an increase in the per unit cash
distributions paid, an increase in the number of units outstanding and an
increase in our general partner incentive distributions. The increase in our
general partner incentive distributions resulted from both increased cash
distributions per unit and an increase in the number of common units and i-units
outstanding.
The period-to-period increase in cash flows from additional partnership
equity issuances primarily related to the excess of cash received from both our
February 2004 issuance of common units and our March 2004 issuance of i-units
over cash received from our June 2003 issuance of common units. On February 9,
2004, we issued, in a public offering, an additional 5,300,000 of our common
units at a price of $46.80 per unit, less commissions and underwriting expenses.
We received net proceeds of $237.8 million for the issuance of these common
units. On March 25, 2004, we issued an additional 360,664 of our i-units to KMR
at a price of $41.59 per share, less closing fees and commissions. We received
net proceeds of $14.9 million for the issuance of these i-units. By comparison,
in a June 2003 public offering, we issued an additional 4,600,000 of our common
units, including 600,000 units upon exercise by the underwriters of an
over-allotment option, at a price of $39.35 per share, less commissions and
underwriting expenses. We received net proceeds of $173.3 million for the
issuance of these common units. We used the proceeds from each of these
issuances to reduce the borrowings under our commercial paper program.
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.
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. The cash equivalent of distributions of
i-units is 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.
60
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. Our general partner's incentive distribution for
the distribution that we declared for the third quarter of 2004 was $99.1
million. Our general partner's incentive distribution for the distribution that
we declared for the third quarter of 2003 was $81.8 million. Our general
partner's incentive distribution that we paid during the third quarter of 2004
to our general partner (for the second quarter of 2004) was $94.9 million. Our
general partner's incentive distribution that we paid during the third quarter
of 2003 to our general partner (for the second quarter of 2003) was $79.6
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.
On August 13, 2004, we paid a quarterly distribution of $0.71 per unit for
the second quarter of 2004, 9% greater than the $0.65 per unit distribution paid
for the second quarter of 2003. We paid this distribution in cash to our common
unitholders and to our Class B unitholders. KMR, our sole i-unitholder, received
920,140 additional i-units based on the $0.71 cash distribution per common unit.
For each outstanding i-unit that KMR held, a fraction (0.018039) of an i-unit
was issued. The fraction was determined by dividing $0.71, the cash amount
distributed per common unit by $39.36, the average of KMR's shares' closing
market prices from July 14-27, 2004, the ten consecutive trading days preceding
the date on which the shares began to trade ex-dividend under the rules of the
New York Stock Exchange.
On October 20, 2004, we declared a cash distribution for the quarterly period
ended September 30, 2004, of $0.73 per unit. The distribution will be paid on or
before November 12, 2004, to unitholders of record as of October 31, 2004. Our
common unitholders and Class B unitholders will receive cash. KMR, our sole
i-unitholder, will receive a distribution in the form of additional i-units
based on the $0.73 distribution per common unit. The number of i-units
distributed will be 929,105. For each outstanding i-unit that KMR holds, a
fraction (0.017892) of an i-unit will be issued. The fraction was determined by
dividing $0.73, the cash amount distributed per common unit by $40.80, the
average of KMR's shares' closing market prices from October 13-26, 2004, 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.
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.
Certain Contractual Obligations
There has been no material changes in either certain contractual obligations
or our obligations with respect to other entities which are not consolidated in
our financial statements that would affect the disclosures presented as of
December 31, 2003 in our 2003 Form 10-K report.
61
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 acquire new businesses and assets and integrate those
operations into our existing operations, as well as our ability to make
expansions to our facilities;
o difficulties or delays experienced by railroads, barges, trucks, ships or
pipelines in delivering products to or from 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 our
services or provide services or products to us;
o changes in laws or regulations, third-party relations and approvals,
decisions of courts, regulators and governmental bodies that 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;
o acts of nature, sabotage, terrorism or other similar acts causing damage
greater than our insurance coverage limits;
o capital markets conditions;
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;
62
o the ability to achieve cost savings and revenue growth;
o inflation;
o interest rates;
o the pace of deregulation of retail natural gas and electricity;
o foreign exchange fluctuations;
o the timing and extent of changes in commodity prices for oil, natural gas,
electricity and certain agricultural products;
o the timing and success of business development efforts; and
o unfavorable results of litigation and the fruition of contingencies
referred to in Note 3 to our consolidated financial statements included
elsewhere in this report.
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 on Form 10-K for the year ended December 31, 2003, 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 2003 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.
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,
2003, in Item 7A of our 2003 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.
As of September 30, 2004, our management, including our Chief Executive
Officer and Chief Financial Officer, has evaluated the effectiveness of the
design and operation of our disclosure controls and procedures pursuant to Rule
13a-15(b) under the Securities Exchange Act of 1934. There are inherent
limitations to the effectiveness of any system of disclosure controls and
procedures, including the possibility of human error and the circumvention or
overriding of the controls and procedures. Accordingly, even effective
disclosure controls and procedures can only provide reasonable assurance of
achieving their control objectives. Based upon and as of the date of the
evaluation, our Chief Executive Officer and our Chief Financial Officer
concluded that the design and operation of our disclosure controls and
procedures were effective in all material respects to provide reasonable
assurance that information required to be disclosed in the reports we file and
submit under the Exchange Act is recorded, processed, summarized and reported as
and when required. There has been no change in our internal control over
financial reporting during the quarter ended September 30, 2004 that has
materially affected, or is reasonably likely to materially affect, our internal
control over financial reporting.
63
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. Unregistered Sales of Equity 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.
On August 26, 2004, we announced that C. Park Shaper has been elected
Executive Vice President of KMI, KMR and Kinder Morgan G.P., Inc. Mr. Shaper
also retains his titles as Director and Chief Financial Officer of KMR and
Kinder Morgan G.P., Inc. and Chief Financial Officer of KMI.
Item 6. 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.
*10.1-- Resignation and Non-Compete agreement dated July 21, 2004 between KMGP
Services, Inc. and Michael C. Morgan, President of Kinder Morgan, Inc.,
Kinder Morgan G.P., Inc. and Kinder Morgan Management, LLC (filed as
Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for
the quarter ended June 30, 2004, filed on August 5, 2004).
10.2 -- 5-Year Credit Agreement dated as of August 18, 2004, among Kinder
Morgan Energy Partners, L.P., the lenders party thereto and Wachovia
Bank, National Association as Administrative Agent.
11 -- Statement re: computation of per share earnings.
31.1 -- Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the
Securities Exchange Act of 1934, as adopted pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
31.2 -- Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the
Securities Exchange Act of 1934, as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
64
32.1 -- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 -- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
- ------------------
* Asterisk indicates exhibits incorporated by reference as indicated; all other
exhibits are filed herewith, except as noted otherwise.
65
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 and Chief Financial Officer of
Kinder Morgan Management, LLC, Delegate of Kinder
Morgan G.P., Inc.(principal financial officer and
principal accounting officer)
Date: November 2, 2004
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