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F O R M 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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 140,039,908 common units outstanding at April 30, 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 Months Ended
March 31, 2004 and 2003.................................. 3
Consolidated Balance Sheets - March 31, 2004 and
December 31, 2003........................................ 4
Consolidated Statements of Cash Flows - Three Months
Ended March 31, 2004 and 2003............................ 5
Notes to Consolidated Financial Statements............... 6
Item 2: Management's Discussion and Analysis of Financial
Condition and Results of Operations......................... 39
Results of Operations.................................... 39
Financial Condition...................................... 48
Information Regarding Forward-Looking Statements......... 52
Item 3: Quantitative and Qualitative Disclosures About Market Risk.. 54
Item 4: Controls and Procedures..................................... 54
` PART II. OTHER INFORMATION
Item 1: Legal Proceedings........................................... 55
Item 2: Changes in Securities, Use of Proceeds and Issuer
Purchases of Equity Securities.............................. 55
Item 3: Defaults Upon Senior Securities............................. 55
Item 4: Submission of Matters to a Vote of Security Holders......... 55
Item 5: Other Information........................................... 55
Item 6: Exhibits and Reports on Form 8-K............................ 55
Signatures.................................................. 57
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Unit Amounts)
(Unaudited)
Three Months Ended March 31,
2004 2003
------------ --------------
Revenues
Natural gas sales.................. $1,326,294 $1,378,288
Services........................... 372,120 334,941
Product sales and other............ 123,842 75,609
---------- ----------
$1,822,256 $1,788,838
---------- ----------
Costs and Expenses
Gas purchases and other costs of
sales........................ 1,317,309 1,375,414
Operations and maintenance......... 111,192 92,537
Fuel and power..................... 33,508 25,138
Depreciation, depletion and
amortization................... 67,531 49,805
General and administrative......... 48,254 36,041
Taxes, other than income taxes..... 19,320 14,751
---------- ----------
1,597,114 1,593,686
---------- ----------
Operating Income..................... 225,142 195,152
Other Income (Expense)
Earnings from equity investments... 20,469 24,305
Amortization of excess cost of
equity investments........... (1,394) (1,394)
Interest, net...................... (47,221) (44,925)
Other, net......................... 743 277
Minority Interest.................... (2,081) (2,214)
---------- ----------
Income Before Income Taxes and
Cumulative Effect of a Change in
Accounting Principle.............. 195,658 171,201
Income Taxes......................... (3,904) (4,188)
---------- ----------
Income Before Cumulative Effect of a
Change in Accounting Principle....... 191,754 167,013
========== ==========
Cumulative effect adjustment from
change in accounting for asset
retirement obligations............ - 3,465
---------- ----------
Net Income........................... $ 191,754 $ 170,478
========== ==========
Calculation of Limited Partners'
interest in Net Income:
Income Before Cumulative Effect of a
Change in Accounting Principle....... $ 191,754 $ 167,013
Less: General Partner's interest..... (91,664) (76,425)
---------- ----------
Limited Partners' interest........... 100,090 90,588
Add: Limited Partners' interest in
Change in Accounting Principle....... - 3,430
---------- ----------
Limited Partners' interest in Net $ 100,090 $ 94,018
Income............................... ========== ==========
Basic and Diluted Limited Partners'
Net Income per Unit:
Income Before Cumulative Effect of a
Change in Accounting Principle.... $ 0.52 $ 0.50
Cumulative effect adjustment from
change in accounting for asset
retirement obligations............ - .02
---------- ----------
Net Income........................... $ 0.52 $ 0.52
========== ==========
Weighted average number of units used
in computation of Limited Partners' Net
Income per unit:
Basic................................ 192,512 181,377
========== ==========
Diluted.............................. 192,602 181,510
========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
3
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
March 31, December 31,
2004 2003
---------- ------------
Assets
Current Assets
Cash and cash equivalents... $ 46,861 $ 23,329
Accounts and notes receivable, net
Trade............................ 546,604 562,974
Related parties.................. 20,309 27,587
Inventories
Products......................... 6,560 7,214
Materials and supplies........... 10,976 10,783
Gas imbalances
Trade............................ 13,492 36,449
Related parties.................. 616 9,084
Gas in underground storage......... 10,546 8,160
Other current assets............... 12,888 19,942
---------- -----------
668,852 705,522
---------- -----------
Property, Plant and Equipment, net.... 7,222,764 7,091,558
Investments........................... 403,016 404,345
Notes receivable...................... 2,422 2,422
Goodwill.............................. 729,510 729,510
Other intangibles, net................ 14,738 13,202
Deferred charges and other assets..... 256,437 192,623
----------- -----------
Total Assets.......................... $ 9,297,739 $ 9,139,182
=========== ===========
Liabilities and Partners' Capital
Current Liabilities
Accounts payable
Trade............................ $ 472,078 $ 477,783
Related parties.................. 7,199 -
Current portion of long-term debt.. 133,483 2,248
Accrued interest................... 26,242 52,356
Deferred revenues.................. 8,877 10,752
Gas imbalances..................... 33,072 49,912
Accrued other current liabilities.. 250,499 211,328
----------- -----------
931,450 804,379
----------- -----------
Long-Term Liabilities and Deferred Credits
Long-term debt, outstanding........ 4,066,860 4,316,678
Market value of interest rate
swaps............................ 172,908 121,464
----------- -----------
4,239,768 4,438,142
Deferred revenues.................. 19,623 20,975
Deferred income taxes.............. 39,026 38,106
Asset retirement obligations....... 35,187 34,898
Other long-term liabilities
and deferred credits............. 292,976 251,691
----------- -----------
4,626,580 4,783,812
----------- -----------
Commitments and Contingencies (Note 3)
Minority Interest..................... 42,009 40,064
----------- -----------
Partners' Capital
Common Units....................... 2,164,145 1,946,116
Class B Units...................... 119,736 120,582
i-Units............................ 1,554,607 1,515,659
General Partner.................... 88,916 84,380
Accumulated other comprehensive
loss............................. (229,704) (155,810)
----------- -----------
3,697,700 3,510,927
----------- -----------
Total Liabilities and Partners'
Capital.......................... $ 9,297,739 $ 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)
Three Months Ended March 31,
----------------------------
2004 2003
------------ --------------
Cash Flows From Operating Activities
Net income.................................. $ 191,754 $ 170,478
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.. 67,531 49,805
Amortization of excess cost of equity
investments......................... 1,394 1,394
Earnings from equity investments.......... (20,469) (24,305)
Distributions from equity investments....... 19,187 17,872
Changes in components of working capital.... 15,850 (37,079)
Other, net.................................. (5,137) (3,456)
---------- -----------
Net Cash Provided by Operating Activities... 270,110 171,244
---------- -----------
Cash Flows From Investing Activities
Acquisitions of assets...................... (50,281) (2,098)
Additions to property, plant and equip. for
expansion and maintenance projects........ (149,718) (145,831)
Sale of investments, property, plant and
equipment, net of removal costs............. 3,076 (823)
Acquisitions of investments................. -- (3,500)
Contributions to equity investments......... (445) (9,415)
Other....................................... 757 3,168
---------- -----------
Net Cash Used in Investing Activities....... (196,611) (158,499)
---------- -----------
Cash Flows From Financing Activities
Issuance of debt............................ 1,289,378 955,365
Payment of debt............................. (1,408,260) (813,365)
Debt issue costs............................ (244) (287)
Proceeds from issuance of common units...... 238,051 780
Proceeds from issuance of i-units........... 14,925 --
Contributions from General Partner.......... 2,919 --
Distributions to partners:
Common units.............................. (91,620) (81,232)
Class B units............................. (3,613) (3,321)
General Partner........................... (87,128) (73,641)
Minority interest......................... (2,301) (2,236)
Other, net.................................. (2,074) 985
---------- -----------
Net Cash Used in Financing Activities....... (49,967) (16,952)
---------- -----------
Increase (Decrease) in Cash and Cash
Equivalents................................. 23,532 (4,207)
Cash and Cash Equivalents, beginning of
period................................... 23,329 41,088
---------- -----------
Cash and Cash Equivalents, end of period.... $ 46,861 $ 36,881
========== ===========
Noncash Investing and Financing Activities:
Assets acquired by the assumption of
liabilities............................. $ 2,812 $ --
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 three 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
---------------------------------------------------
(in millions)
---------------------------------------------------
Property Deferred
Purchase Current Plant & Charges Minority
Ref. Date Acquisition Price Assets Equipment & Other Interest
----- ----- ------------------------------------ ----------- -------- --------- --------- --------
(1) 12/03 ConocoPhillips Products Terminals.. $ 15.2 $ - $ 14.2 $ 1.0 $ -
(2) 12/03 Tampa, Florida Bulk Terminals...... 29.4 - 29.4 - -
(3) 3/04 ExxonMobil Products Terminals...... $ 50.8 $ - $ 50.8 $ - $ -
(1) 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 $15.2 million,
consisting of approximately $14.1 million in cash and $1.1 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 broadens 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. Our allocation of the purchase price to
assets acquired and liabilities assumed is preliminary, pending final purchase
price adjustments that we expect to make in the second quarter of 2004.
(2) Tampa, Florida Bulk Terminals
In December 2003, we acquired two bulk terminal facilities in Tampa, Florida
for an aggregate consideration of approximately $29.4 million, consisting of
$25.9 million in cash (including closing and related costs of approximately $1.0
million) and $3.5 million in assumed liabilities. As of our acquisition date, we
expected to invest an additional $16.9 million in the facilities. The principal
purchased asset was a marine terminal acquired from a subsidiary of IMC Global,
Inc. We also entered into a long-term agreement with IMC to enable it to 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
includes assets from 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. The acquired operations are included as part
of our Terminals business segment and complement our existing business in the
Tampa area by generating additional fee-based income. Our allocation of the
purchase price to assets acquired and liabilities assumed is preliminary,
pending any adjustments that may be necessary to the amount of assumed property
tax liabilities. We expect to make our final purchase price adjustments in the
second quarter of 2004.
(3) 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 $50.8 million, consisting of approximately
$48.1 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 has
entered into a long-term contract to store products in the terminals. The
acquisition enhances our terminal operations in the Southeast and complements
our December 2003 acquisition of
7
seven products terminals from ConocoPhillips Company and Phillips Pipe Line
Company. The acquired operations will be included as part of our Products
Pipelines business segment. Our allocation of the purchase price to assets
acquired and liabilities assumed is preliminary, pending final purchase price
adjustments that we expect to make in the second quarter of 2004.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement
information for the three months ended March 31, 2004 and 2003, assumes that all
of the 2004 and 2003 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 completed the 2004 and 2003 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
Three Months Ended March 31,
----------------------------
2004 2003
---- ----
(Unaudited)
Revenues..................................... $1,825,288 $1,823,254
Operating Income............................. 227,456 214,716
Income Before Cumulative Effect of a
Change in Accounting Principle............. 193,954 182,274
Net Income................................... $ 193,954 $ 185,739
Basic and Diluted Limited Partners' Net
Income per unit: Income Before Cumulative
Effect of a Change in Accounting Principle $ 0.53 $ 0.58
Net Income................................. $ 0.53 $ 0.60
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.
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 "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
8
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 "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.
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. The Court of Appeals is expected to
issue its decision in the next several months.
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
9
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.
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 is currently
suspended pending issuance of the phase two initial decision in the Docket No.
OR96-2, et al. proceeding (see below).
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. Issuance of the phase two initial decision is
expected sometime in the second quarter of 2004.
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
10
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 noted above, issuance of an initial decision on
those issues from the presiding administrative law judge is currently pending.
The FERC's phase one order also did not address the "grandfathered" status of
the Watson Station fee, noting that issues regarding Watson Station are pending
before the U.S. Court of Appeals for the District of Columbia Circuit and will
be addressed once that court issues a ruling on those issues. Several of the
participants in the proceeding requested rehearing of the FERC's phase one
order, and several participants, including SFPP, have filed petitions with the
United States Court of Appeals for the District of Columbia Circuit for review
of the FERC's phase one order. Commission and Court action on those petitions is
pending.
Once the administrative law judge issues his non-binding phase two initial
decision, and that decision is briefed by the parties, the FERC will consider
that portion of the proceeding. After reviewing the initial decision, the FERC
could determine that it is necessary to lower SFPP's "ungrandfathered" rates
prospectively and that complaining shippers are entitled to reparations for
prior periods. A FERC order addressing the initial decision is not expected
before early 2005.
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 previously estimated that shippers sought reparations of $154 million and
prospective rate reductions with an aggregate average annual impact of $45
million. The estimated reparations relief sought by shippers has been reduced as
a result of the FERC's decision to reverse the administrative law judge's
decision to "ungrandfather" the rates from the North and Oregon Lines. However,
our previous estimates assumed that any potential rate reductions would be
implemented in January 2004 and reparations and accrued interest thereon would
be paid in January 2005. If we were to maintain these timing assumptions, the
estimated reparations including accrued interest thereon, and prospective annual
rate reductions would have been reduced to approximately $140 million and $44
million, respectively. 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 early in
the second quarter of 2005 and that reparations and accrued interest thereon
will be paid early in the second quarter of 2006. 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.
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.
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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 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.
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 third 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 are
expected to be resolved by the CPUC by the third quarter of 2004.
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
12
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 third 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
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. A prehearing
conference on the rate issues was held on January 16, 2003, where a procedural
schedule was established.
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:
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;
13
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 have 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 are effective as of May 23, 2003, except
that Trailblazer has filed to make the revised credit procedures effective
August 15, 2003.
With respect to the on-going 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, if
approved by the FERC, Trailblazer's rate would be reduced effective January 1,
2004, from about $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, and were included in our
2004 budget.
FERC Order 637
Kinder Morgan Interstate Gas Transmission LLC
On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its
filing to comply with FERC's Orders 637 and 637-A. That filing contained KMIGT's
compliance plan to implement the changes required by the FERC dealing with the
way business is conducted on interstate natural gas pipelines. All interstate
natural gas pipelines were required to make such compliance filings, according
to a schedule established by the FERC. From October 2000 through June 2001,
KMIGT held a series of technical and phone conferences to identify issues,
obtain input, and modify its Order 637 compliance plan, based on comments
received from the FERC staff and other interested parties and shippers. On June
19, 2001, KMIGT received a letter from the FERC encouraging it to file revised
pro-forma tariff sheets, which reflected the latest discussions and input from
parties into its Order 637 compliance plan. KMIGT made such a revised Order 637
compliance filing on July 13, 2001. The July 13, 2001 filing contained little
substantive change from the original pro-forma tariff sheets that KMIGT
originally proposed on June 15, 2000. On October 19, 2001, KMIGT received an
order from the FERC, addressing its July 13, 2001 Order 637 compliance plan. In
the FERC Order addressing KMIGT's July 13, 2001 compliance plan, KMIGT's plan
was accepted, but KMIGT was directed to make several changes to its tariff, and
to not place the revised tariff into effect until the FERC issues a further
order. KMIGT filed its compliance filing to the FERC's October 19, 2001 Order
and filed a request for rehearing/clarification of the FERC's October 19, 2001
Order. Several parties protested KMIGT's November 19, 2001 compliance filing.
KMIGT filed responses to those protests on December 14, 2001.
On May 22, 2003, the FERC issued an Order on Rehearing and Compliance Filing
(May 2003 Order) addressing KMIGT's November 19, 2001 compliance filing and
request for rehearing. The May 2003 Order granted in part and denied in part
KMIGT's request for rehearing, and directed KMIGT to file certain revised tariff
sheets consistent with the May 2003 Order's directives. On June 20, 2003, KMIGT
submitted its compliance filing reflecting revised tariff sheets in accordance
with the May 2003 Order's directives. Consistent with the May 2003 Order,
KMIGT's
14
compliance filing reflected tariff sheets with proposed effective dates of June
1, 2003 and December 1, 2003. Those sheets with a proposed effective date of
December 1, 2003 concern tariff provisions necessitating computer system
modifications.
On November 21, 2003, KMIGT received a Letter Order (November 21 Order) from
the FERC accepting the tariff sheets submitted in the June 20, 2003 compliance
filing. In accordance with the November 21 Order, KMIGT commenced full
implementation of Order No. 637 on December 1, 2003. KMIGT's actual operating
experience under the full requirements of Order No. 637 is limited. However, we
believe that these matters will not have a material adverse effect on our
business, financial position, results of operations or cash flows.
Trailblazer Pipeline Company
On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with
the FERC's Order Nos. 637 and 637-A. Trailblazer's compliance filing reflected
changes in:
o segmentation;
o scheduling for capacity release transactions;
o receipt and delivery point rights;
o treatment of system imbalances;
o operational flow orders;
o penalty revenue crediting; and
o right of first refusal language.
On October 15, 2001, the FERC issued its order on Trailblazer's Order No. 637
compliance filing. The FERC approved Trailblazer's proposed language regarding
operational flow orders and 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 that
must be made within 30 days of the order.
Trailblazer made those modifications in a further compliance filing submitted
to the FERC on May 16, 2003. Certain shippers have filed a limited protest
regarding that compliance filing. The compliance filing is pending FERC action.
Under the FERC's orders, limited aspects of Trailblazer's plan (revenue
crediting) were effective as of May 1, 2003. The entire plan went into
effective on December 1, 2003.
On March 24, 2004, the FERC issued an order directing Trailblazer to make
relatively minor changes to its tariff filing of May 16, 2003. Trailblazer
submitted its further compliance filing on April 8, 2004. That filing is
pending FERC action, but Trailblazer's Order 637 compliance plan remains in
effect as stated in the prior paragraph.
Trailblazer anticipates no adverse impact on its business as a result of the
implementation of Order No. 637.
Standards of Conduct Rulemaking
On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking in
Docket No. RM01-10 in which it proposed new rules governing the interaction
between an interstate natural gas pipeline and its affiliates. If adopted as
proposed, the Notice of Proposed Rulemaking could be read to limit
communications between 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
15
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 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.
On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards
of Conduct to become effective February 9, 2004. Every interstate 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
pipeline's interaction with many more affiliates (referred to as "energy
affiliates"), including intrastate/Hinshaw 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 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 off-system sales, to be excluded from the
rule's definition of energy affiliate. We expect the one-time costs of
compliance with the Order, assuming the request to exempt intrastate pipeline
affiliates is granted, to range from $600,000 to $700,000, to be shared between
us and KMI.
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 an LDC 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 producers. The FERC also declined to
exempt 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 separate exemption requests by our interstate pipelines as to
their intrastate affiliates remains pending. The FERC also clarified further the
personnel and functions which can be shared by interstate 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
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.
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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. The first quarterly reports for major public utilities, licensees, and
natural gas companies will be due on July 9, 2004. The first quarterly reports
for non-major public utilities, licensees, natural gas companies, and all oil
pipeline companies will be due on July 23, 2004. After the transition period,
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.
Southern Pacific Transportation Company Easements
SFPP, L.P. and Southern Pacific Transportation Company are engaged in a
judicial reference proceeding to determine the extent, if any, to which the
rent payable by SFPP for the use of pipeline easements on rights-of-way held
by SPTC should be adjusted pursuant to existing contractual arrangements
(Southern Pacific Transportation Company vs. Santa Fe Pacific Corporation, SFP
Properties, Inc., Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al.,
Superior Court of the State of California for the County of San Francisco,
filed August 31, 1994). In the second quarter of 2003, the trial court set
the rent at approximately $5.0 million per year as of January 1, 1994. SPTC
has appealed the matter to the California Court of Appeals.
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
17
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.
Shell CO2 Company, Ltd., predecessor in interest to Kinder Morgan CO2 Company,
L.P., is among the named 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 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 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. Plaintiffs seek actual damages, punitive
damages, an accounting, and declaratory relief. The trial court granted a series
of summary judgment motions filed by defendants on all of plaintiffs' 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.
RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et
al.
Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District. On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served
with the First Supplemental Petition filed by RSM Production Corporation on
behalf of the County of Zapata, State of Texas and Zapata County Independent
School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in
addition to 15 other defendants, including two other Kinder Morgan affiliates.
Certain entities we acquired in the Kinder Morgan Tejas acquisition are also
defendants in this matter. The Petition alleges that these taxing units relied
on the reported volume and analyzed heating content of natural gas produced from
the wells located within the appropriate taxing jurisdiction in order to
properly assess the value of mineral interests in place. The suit further
alleges that the defendants undermeasured the volume and heating content of that
natural gas produced from privately owned wells in Zapata County, Texas. The
Petition further alleges that the County and School District were deprived of ad
valorem tax revenues as a result of the alleged undermeasurement of the natural
gas by the defendants. On December 15, 2001, the defendants filed motions to
transfer venue on jurisdictional grounds. 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
Claim Act and involves allegations of mismeasurement of natural gas produced
from federal and Indian lands. The Department of Justice has decided not to
intervene in support of the action. The complaint is part of a larger series of
similar complaints filed by Mr. Grynberg against 77 natural gas pipelines
(approximately 330 other defendants). Certain entities we acquired in the Kinder
Morgan Tejas acquisition are also defendants in this matter. An earlier single
action making substantially similar allegations against the pipeline industry
was dismissed by Judge Hogan of the U.S. District Court for the District of
Columbia on grounds of improper joinder and lack of jurisdiction. As a result,
Mr. Grynberg filed individual complaints in various courts throughout the
country. In 1999, these cases were consolidated by the Judicial Panel for
Multidistrict Litigation, and transferred to the District of Wyoming. The
multidistrict litigation matter is called In Re Natural Gas Royalties Qui Tam
Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument
on the motion to dismiss occurred on March 17, 2000. On July 20, 2000, the
United States of America filed a motion to dismiss those claims by Grynberg that
deal with the manner in which defendants valued gas produced from federal
leases, referred to as valuation claims. Judge Downes denied the defendant's
motion to dismiss on May 18, 2001. The United States' motion to dismiss most of
plaintiff's valuation claims has been granted by the court. Grynberg has
appealed that dismissal to the 10th Circuit, which has requested briefing
regarding its jurisdiction over that appeal. Discovery is now underway to
determine issues related to the Court's subject matter jurisdiction, arising out
of the False Claims Act. On May 7, 2003, Grynberg sought leave to file a Third
Amended Complaint, which adds allegations of
18
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.
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.
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
19
substantially below market, which in turn sells such natural gas to commercial
and industrial consumers and gas marketers at market price. The Complaint
purports to assert claims for fraud, violations of the Texas Deceptive Trade
Practices Act, and violations of the Texas Utility Code against some or all of
the Defendants, and civil conspiracy against all of the defendants, and seeks
relief in the form of, inter alia, actual, exemplary and statutory damages,
civil penalties, interest, attorneys' fees and a constructive trust ab initio on
any and all sums which allegedly represent overcharges by Reliant and Reliant
Energy Resources Corp.
On November 18, 2002, the Kinder Morgan defendants filed a Motion to Transfer
Venue and, Subject Thereto, Original Answer to the First Amended Complaint. The
parties are currently engaged in preliminary discovery. Based on the information
available to date and our preliminary investigation, the Kinder Morgan
defendants believe that the claims against them are without merit and intend to
defend against them vigorously.
Marie Snyder, et al v. City of Fallon, United States Department of the Navy,
Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas
Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District
Court, District of Nevada)("Snyder"); 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 9th Circuit. On November 17, 2003, the 9th Circuit dismissed the
appeal, upholding the District Court's dismissal of the case.
20
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, which Motion
is currently set for a hearing on April 30, 2004.
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.
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.
21
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 third 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 are
currently involved in discovery.
Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party
in interest for Enron Helium Company, a division of Enron Corp., Enron
Liquids Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership,
Kinder Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252
(189th Judicial District Court, Harris County, Texas)
On September 1, 2000, Plaintiff Exxon Mobil Corporation filed its Original
Petition and Application for Declaratory Relief against Kinder Morgan
Operating L.P. "A," Enron Liquids Pipeline Operating Limited Partnership
n/k/a Kinder Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a
Kinder Morgan G.P., Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton
Processing, Inc., and Enron Helium Company. Plaintiff added Enron Corp. as
party in interest for Enron Helium Company in its First Amended Petition and
added Kinder Morgan, Inc. as a Defendant. The claims against Enron Corp.
were severed into a separate cause of action. Plaintiff's claims are based
on a Gas Processing Agreement entered into on September 23, 1987 between
Mobil Oil Corp. and Enron Gas Processing Company relating to gas produced in
the Hugoton Field in Kansas and processed at the Bushton Plant, a natural gas
processing facility located in Kansas. Plaintiff also asserts claims
relating to the Helium Extraction Agreement entered between Enron Helium
Company (a division of Enron Corp.) and Mobil Oil Corporation dated March 14,
1988. Plaintiff alleges that Defendants failed to deliver propane and to
allocate plant products to Plaintiff as required by the Gas Processing
Agreement and originally sought damages of approximately $5.9 million.
22
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 parties have completed
discovery and the matter is scheduled for trial on June 21, 2004. Based on the
information available to date in our investigation, the Kinder Morgan Defendants
believe that the claims against them are without merit and intend to defend
against them vigorously.
Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions, that, to the extent an assessment of the
matter is possible, we have established an adequate reserve to cover potential
liability, and that these matters will not have a material adverse effect on our
business, financial position, results of operations or cash flows.
Environmental Matters
We are subject to environmental cleanup and enforcement actions from time to
time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) generally imposes joint and several
liability for cleanup and enforcement costs on current or predecessor owners and
operators of a site, without regard to fault or the legality of the original
conduct. Our operations are also subject to federal, state and local laws and
regulations relating to protection of the environment. Although we believe our
operations are in substantial compliance with applicable environmental
regulations, risks of additional costs and liabilities are inherent in pipeline,
terminal and carbon dioxide field and oil field operations, and there can be no
assurance that we will not incur significant costs and liabilities. Moreover, it
is possible that other developments, such as increasingly stringent
environmental laws, regulations and enforcement policies thereunder, and claims
for damages to property or persons resulting from our operations, could result
in substantial costs and liabilities to us.
We are currently involved in the following governmental proceedings related to
compliance with environmental regulations associated with our assets and have
established a reserve to address the costs associated with the cleanup:
o one cleanup ordered by the United States Environmental Protection Agency
related to ground water contamination in the vicinity of SFPP's storage
facilities and truck loading terminal at Sparks, Nevada;
o several ground water hydrocarbon remediation efforts under administrative
orders issued by the California Regional Water Quality Control Board and two
other state agencies;
o groundwater and soil remediation efforts under administrative orders issued
by various regulatory agencies on those assets purchased from GATX Corporation,
comprising Kinder Morgan Liquids Terminals LLC, CALNEV Pipe Line LLC and Central
Florida Pipeline LLC; and
o a ground water remediation effort taking place between Chevron, Plantation
Pipe Line Company and the Alabama Department of Environmental Management.
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
23
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 March 31, 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.
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.
Preliminary estimates indicate that the size of the spill was up to 60,000
gallons. Upon discovery of the spill and notification to regulatory agencies, a
unified response was implemented with the U.S. Coast Guard, the California
Department of Fish and Game, the Office of Spill Prevention and Response and us.
The damaged section of the pipeline has been removed and replaced, and the
pipeline resumed operations on May 2, 2004. We are in the process of
remediating the spill, and various governmental agencies are investigating the
matter.
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 March 31, 2004, we have recorded a total reserve for
environmental claims in the amount of $39.6 million. However, we were not able
to reasonably estimate when the eventual settlements of these claims will occur.
Other
We are a defendant in various lawsuits arising from the day-to-day operations
of our businesses. Although no assurance can be given, we believe, based on our
experiences to date, that the ultimate resolution of such items will not have a
material adverse impact on our business, financial position, 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.
24
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 of the
related assets. The liabilities are eventually extinguished when the asset is
taken out of service. Specifically, upon adoption of this Statement, an entity
must recognize the following items in its balance sheet:
o a liability for any existing asset retirement obligations adjusted for
cumulative accretion to the date of adoption;
o an asset retirement cost capitalized as an increase to the carrying
amount of the associated long-lived asset; and
o accumulated depreciation on that capitalized cost.
Amounts resulting from initial application of this Statement 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 March 31, 2004, we have recognized asset retirement
obligations in the aggregate amount of $33.3 million relating to these
requirements at existing sites within our CO2 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 March 31, 2004, we have recognized asset
retirement obligations in the aggregate amount of $2.7 million relating to the
businesses within our Natural Gas Pipelines segment.
We have included $0.8 million of our total $36.0 million asset retirement
obligations as of March 31, 2004 with "Accrued other current liabilities" in our
accompanying consolidated balance sheet. The remaining $35.2 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 three months ended March 31, 2004
and 2003 is as follows (in thousands):
25
Three Months Ended March 31,
----------------------------
2004 2003
----------- ----------
Balance at beginning of period............. $ 35,708 $ -
Initial ARO balance upon adoption.......... - 14,125
Liabilities incurred....................... - -
Liabilities adjusted/(settled)............. (230) (202)
Accretion expense.......................... 519 171
Revisions in estimated cash flows.......... - -
----------- ----------
Balance at end of period................... $ 35,997 $ 14,094
=========== ==========
5. Distributions
On February 13, 2004, we paid a cash distribution of $0.68 per unit to our
common unitholders and to our Class B unitholders for the quarterly period ended
December 31, 2003. KMR, our sole i-unitholder, received 778,309 additional
i-units based on the $0.68 cash distribution per common unit. The distributions
were declared on January 21, 2004, payable to unitholders of record as of
January 30, 2004.
On April 21, 2004, we declared a cash distribution of $0.69 per unit for the
quarterly period ended March 31, 2004. The distribution will be paid on or
before May 14, 2004, to unitholders of record as of April 30, 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 $0.69 distribution
per common unit. The number of i-units distributed will be 872,958. For each
outstanding i-unit that KMR holds, a fraction of an i-unit (0.017412) will be
issued. The fraction was determined by dividing:
o $0.69, the cash amount distributed per common unit
by
o $39.627, the average of KMR's limited liability shares' closing market
prices from April 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.
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):
March 31, December 31,
2004 2003
--------- ------------
Goodwill
Gross carrying amount...... $ 743,652 $ 743,652
Accumulated amortization... (14,142) (14,142)
---------- ------------
Net carrying amount........ 729,510 729,510
---------- ------------
Lease value
Gross carrying amount...... 6,592 6,592
Accumulated amortization... (924) (888)
---------- ------------
Net carrying amount........ 5,668 5,704
---------- ------------
Contracts and other
Gross carrying amount...... 9,498 7,801
Accumulated amortization... (428) (303)
---------- ------------
Net carrying amount........ 9,070 7,498
---------- ------------
Total intangibles, net..... $ 744,248 $ 742,712
========== ============
26
Changes in the carrying amount of goodwill for the three months ended March
31, 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
Goodwill acquired - - - - -
Impairment losses - - - - -
---------- ---------- ---------- ---------- ----------
Balance as of March 31, 2004 $ 263,182 $ 253,358 $ 46,101 $ 166,869 $ 729,510
========== ========== ========== ========== ==========
Amortization expense on intangibles consists of the following (in thousands):
Three Months Ended March 31,
----------------------------
2004 2003
--------- ---------
Lease value............. $ 36 $ 35
Contracts and other..... 125 15
--------- ---------
Total amortization...... $ 161 $ 50
========= =========
As of March 31, 2004, our weighted average amortization period for our
intangible assets is approximately 25.34 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 March 31, 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 March 31, 2004 was $511.6 million. The
balance primarily consisted of $307.4 million of commercial paper borrowings and
$200 million of 8.0% senior notes due March 15, 2005. As of March 31, 2004, we
intend and have the ability to refinance $378.1 million of our short-term debt
on a long-term basis under our unsecured long-term credit facility. Accordingly,
such amount has been classified as long-term debt in our accompanying
consolidated balance sheet.
The weighted average interest rate on all of our borrowings was approximately
4.385% during the first quarter of 2004 and 4.730% during the first quarter of
2003.
Credit Facilities
As of March 31, 2004, we had two credit facilities:
o a $570 million unsecured 364-day credit facility due October 12, 2004; and
o a $480 million unsecured three-year credit facility due October 15, 2005.
Our credit facilities are with a syndicate of financial institutions. Wachovia
Bank, National Association is the administrative agent under both credit
facilities. There were no borrowings under either credit facility as of December
31, 2003 or as of March 31, 2004.
The amount available for borrowing under our credit facilities as of March 31,
2004 is reduced by:
27
o a $50 million letter of credit entered into on January 14, 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 $28 million letter of credit entered into on December 23, 2002 that
supports Nassau County, Florida Ocean Highway and Port Authority tax exempt
bonds (associated with the operations of our bulk terminal facility located
at Fernandina Beach, Florida);
o a $23.7 million letter of credit that supports Kinder Morgan Operating
L.P. "B"'s tax-exempt bonds;
o a $0.2 million letter of credit entered into on June 4, 2002 that supports a
workers' compensation insurance policy; and
o our outstanding commercial paper borrowings.
Interest Rate Swaps
In order to maintain a cost effective capital structure, it is our policy to
borrow funds using a mix of fixed rate debt and variable rate debt. As of March
31, 2004, we have entered into 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. The $2.1
billion notional principal amount of our interest rate swap agreements has not
changed since December 31, 2003.
These swaps meet the conditions required to assume no ineffectiveness under
SFAS No. 133 and, therefore, we have accounted for them using the "shortcut"
method prescribed for fair value hedges. Accordingly, we adjust the carrying
value of each swap to its fair value each quarter, with an offsetting entry to
adjust the carrying value of the debt securities whose fair value is being
hedged. For more information on our interest rate swaps, see Note 10.
Commercial Paper Program
As of both December 31, 2003 and March 31, 2004, our commercial paper program
provided for the issuance of up to $1.05 billion of commercial paper. As of
March 31, 2004, we had $307.4 million of commercial paper outstanding with an
average interest rate of 1.1191%. Borrowings under our commercial paper program
reduce the borrowings allowed under our credit facilities.
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 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.
28
Due to our indirect ownership of Cortez Pipeline Company through Kinder Morgan
CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez Capital
Corporation. Shell Oil Company shares our guaranty obligations jointly and
severally through December 31, 2006 for Cortez Capital Corporation's debt
programs in place as of April 1, 2000.
As of March 31, 2004, the debt facilities of Cortez Capital Corporation
consisted of:
o $95 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 March 31, 2004, Cortez Capital Corporation had $124.6 million of
commercial paper outstanding with an interest rate of 1.075%, the average
interest rate on the Series D notes was 7.04% and there were no borrowings under
the credit facility.
Plantation Pipeline Company Debt
On April 30, 1997, Plantation Pipeline Company entered into a $10 million,
ten-year floating-rate term credit agreement. We, as an owner of Plantation
Pipeline Company, severally guarantee this debt on a pro rata basis equivalent
to our respective 51% ownership interest. During 1999, this agreement was
amended to reduce the maturity date by three years. The $10 million was
outstanding as of March 31, 2004, and in April 2004, we extended the maturity to
July 2004.
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 is outstanding as of March 31, 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.
Certain Relationships and Related Transactions
KMI Asset Contributions
In conjunction with our acquisition of Natural Gas Pipelines assets from KMI
on December 31, 1999 and 2000, KMI became a guarantor of approximately $522.7
million of our debt. This amount has not changed as of December 31, 2003 and
March 31, 2004. KMI would be obligated to perform under this guarantee only if
we and/or
29
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 March 31, 2004 and December 31, 2003, our partners' capital consisted
of the following limited partner units:
March 31, December 31,
2004 2003
----------- -------------
Common units.................. 140,039,908 134,729,258
Class B units................. 5,313,400 5,313,400
i-units....................... 50,135,438 48,996,465
----------- -------------
Total limited partner units.. 195,488,746 189,039,123
=========== =============
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 March 31, 2004, our common unit totals consisted of 127,084,173 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 March 31, 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, an additional 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
30
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 778,309 i-units
on February 13, 2004. These additional i-units distributed were based on the
$0.68 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 $0.68 per unit paid on February 13, 2004 for
the fourth quarter of 2003 required an incentive distribution to our general
partner of $85.8 million. Our distribution of $0.625 per unit paid on February
14, 2003 for the fourth quarter of 2002 required an incentive distribution to
our general partner of $72.5 million. The increased incentive distribution to
our general partner paid for the fourth quarter of 2003 over the distribution
paid for the fourth quarter of 2003 reflects the increase in the amount
distributed per unit as well as the issuance of additional units.
Our declared distribution for the first quarter of 2004 of $0.69 per unit will
result in an incentive distribution to our general partner of approximately
$90.7 million. This compares to our distribution of $0.64 per unit and incentive
distribution to our general partner of approximately $75.5 million for the first
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 ended
March 31, 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 March 31,
----------------------------
2004 2003
----------- ----------
Net income.......................................... $ 191,754 $ 170,478
Change in fair value of derivatives used for hedging
purposes............................................ (100,010) (53,870)
Reclassification of change in fair value of
derivatives to net income........................... 26,116 50,431
----------- ----------
Comprehensive income................................ $ 117,860 $ 167,039
=========== ==========
10. Risk Management
Hedging Activities
Certain of our business activities expose us to risks associated with changes
in the market price of natural gas, natural gas liquids, crude oil and carbon
dioxide. Through KMI, we use energy financial instruments to reduce our risk of
changes in the prices of natural gas, natural gas liquids and crude oil markets
(and carbon dioxide to the extent contracts are tied to crude oil prices) as
discussed below. The fair value of these risk management instruments reflects
the estimated amounts that we would receive or pay to terminate the contracts at
the reporting date, thereby taking into account the current unrealized gains or
losses on open contracts. We have available market quotes for substantially all
of the financial instruments that we use, 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 only as a hedging mechanism against price volatility associated with:
31
o pre-existing or anticipated physical natural gas, natural gas liquids and
crude oil sales;
o pre-existing or anticipated physical carbon dioxide sales that have
pricing tied to crude oil prices;
o natural gas purchases; and
o system use and storage.
Our risk management activities are only used in order to protect our profit
margins and our risk management policies prohibit us from engaging in
speculative trading. Commodity-related activities of our risk management group
are monitored by our Risk Management Committee, which is charged with the review
and enforcement of our management's risk management policy.
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. As of
December 31, 2003, no financial instruments were used to limit the effects of
foreign exchange rate fluctuations on our financial results.
Our derivatives that hedge our commodity price risks involve our normal
business activities, which include the sale of natural gas, natural gas liquids,
oil and carbon dioxide, and these derivatives have been designated 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. 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 is reported in earnings immediately.
The gains and losses included in "Accumulated other comprehensive loss" in the
accompanying consolidated balance sheets are reclassified into earnings as the
hedged sales and purchases take place. Approximately $103.6 million of the
Accumulated other comprehensive loss balance of $229.7 million representing
unrecognized net losses on derivative activities as of March 31, 2004 is
expected to be reclassified into earnings during the next twelve months. During
the three months ended March 31, 2004, we reclassified $26.1 million of
Accumulated other comprehensive income into earnings. This reclassification
reduced the balance of $155.8 million representing unrecognized net losses on
derivative activities as of December 31, 2003.
During the three months ended March 31, 2004, no gains or losses were
reclassified into earnings as a result of the discontinuance of cash flow hedges
due to a determination that the forecasted transactions will no longer occur by
the end of the originally specified time period.
We recognized no gain or loss during the first quarter of 2004 as a result of
ineffective hedges. During the first quarter of 2003, we recognized a gain of
$0.2 million as a result of ineffective hedges, and this amount was reported
within the caption "Gas purchases and other costs of sales" in our accompanying
Consolidated Statement of Income. For each of the three months ended March 31,
2004 and 2003, we did not exclude any component of the derivative instruments'
gain or loss from the assessment of hedge effectiveness.
The differences between the current market value and the original physical
contracts value associated with our hedging activities are 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
consolidated balance sheets as of March 31, 2004 and December 31, 2003 (in
thousands):
32
March 31, December 31,
2004 2003
------------ ---------------
Derivatives-net asset/(liability)
Other current assets............... $ 9,908 $ 18,157
Deferred charges and other assets.. 9,695 2,722
Accrued other liabilities.......... (119,881) (90,426)
Other long-term liabilities and
deferred credits.................. $ (143,154) $ (101,463)
On January 14, 2004, we entered into a $50 million letter of credit that
supports our hedging of commodity price risks involved from the sale of natural
gas, natural gas liquids, oil and carbon dioxide.
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 March 31, 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
March 31, 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 March 31, 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 March 31, 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 2033.
The swap agreements related to our 7.40% senior notes contain mutual cash-out
provisions at the then-current economic value every seven years. The swap
agreements related to our 7.125% senior notes contain cash-out provisions at the
then-current economic value at March 15, 2009. The swap agreements related to
our 7.75% senior
33
notes and our 7.30% senior notes contain mutual cash-out provisions at the
then-current economic value every five years.
These interest rate swaps have been designated as fair value hedges as
defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge a
recognized asset or liability's exposure to changes in their fair value as fair
value hedges and the gain or loss on fair value hedges are to be recognized in
earnings in the period of change together with the offsetting loss or gain on
the hedged item attributable to the risk being hedged. The effect of that
accounting is to reflect in earnings the extent to which the hedge is not
effective in achieving offsetting changes in fair value.
As of March 31, 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. As of March 31, 2004, we
recognized an asset of $179.0 million and a liability of $6.1 million for the
$172.9 million net fair value of our swap agreements, and we included these
amounts with "Deferred charges and other assets" and "Other long-term
liabilities and deferred credits" on our accompanying balance sheet. The
offsetting entry to adjust the carrying value of the debt securities whose fair
value was being hedged was recognized as "Market value of interest rate swaps"
on our accompanying balance sheet. As of December 31, 2003, we recognized an
asset of $129.6 million and a liability of $8.1 million for the $121.5 million
net fair value of our swap agreements, and we included these amounts with
"Deferred charges and other assets" and "Other long-term liabilities and
deferred credits" on our accompanying balance sheet. As described above, the
offsetting entry to adjust the carrying value of the debt securities whose fair
value was being hedged was recognized as "Market value of interest rate swaps"
on our accompanying balance sheet.
We are exposed to credit related losses in the event of nonperformance by
counterparties to these interest rate swap agreements. While we enter into
derivative transactions primarily with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that from
time to time losses will result from counterparty credit risk.
11. Reportable Segments
We divide our operations into four reportable business segments:
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.
34
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 March 31,
----------------------------
2004 2003
------------ -----------
Revenues
Products Pipelines...................... $ 154,856 $ 144,417
Natural Gas Pipelines................... 1,437,908 1,480,954
CO2..................................... 105,586 48,456
Terminals............................... 123,906 115,011
---------- ----------
Total consolidated revenues............. $1,822,256 $1,788,838
========== ==========
Operating expenses(a)
Products Pipelines........................ $ 42,878 $ 41,186
Natural Gas Pipelines..................... 1,339,960 1,395,534
CO2....................................... 38,385 16,682
Terminals................................. 60,106 54,438
---------- ----------
Total consolidated operating expenses..... $1,481,329 $1,507,840
========== ==========
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
Depreciation, depletion and amortization
Products Pipelines........................ $ 17,416 $ 16,560
Natural Gas Pipelines..................... 12,842 12,624
CO2....................................... 26,988 11,593
Terminals................................. 10,285 9,028
---------- ----------
Total consol. depreciation, depletion and
amortiz.................................. $ 67,531 $ 49,805
========== ==========
Earnings from equity investments
Products Pipelines........................ $ 5,019 $ 8,043
Natural Gas Pipelines..................... 4,967 6,224
CO2....................................... 10,479 10,006
Terminals................................. 4 32
---------- ----------
Total consolidated equity earnings........ $ 20,469 $ 24,305
========== ==========
Amortization of excess cost of equity
investments
Products Pipelines........................ $ 821 $ 821
Natural Gas Pipelines..................... 69 69
CO2....................................... 504 504
Terminals................................. -- --
---------- ----------
Total consol. amortization of excess
cost of invests.......................... $ 1,394 $ 1,394
========== ==========
Other, net-income (expense)
Products Pipelines....................... $ (362) $ 225
Natural Gas Pipelines.................... 1,130 23
CO2...................................... 9 17
Terminals................................ (34) 12
---------- ----------
Total consolidated Other, net-income
(expense)............................... $ 743 $ 277
========== ==========
Income tax benefit (expense)
Products Pipelines....................... $ (2,381) $ (2,825)
Natural Gas Pipelines.................... (940) (108)
CO2...................................... 14 --
Terminals................................ (597) (1,255)
---------- ----------
Total consolidated income tax benefit
(expense)............................... $ (3,904) $ (4,188)
========== ==========
35
Three Months Ended March 31,
----------------------------
2004 2003
------------ -----------
Segment earnings
Products Pipelines....................... $ 96,017 $ 91,293
Natural Gas Pipelines.................... 90,194 78,866
CO2...................................... 50,211 29,700
Terminals................................ 52,888 50,334
---------- ----------
Total segment earnings................... 289,310 250,193
Interest and corporate administrative
expenses................................ (97,556) (79,715)
---------- ----------
Total consolidated net income............ $ 191,754 $ 170,478
========== ==========
Segment earnings before depreciation,
depletion, amortization and amortization
of excess cost of equity investments
Products Pipelines....................... $ 114,254 $ 108,674
Natural Gas Pipelines.................... 103,105 91,561
CO2...................................... 77,703 41,966
Terminals................................ 63,173 59,362
---------- ----------
Total segment earnings before DD&A(a).... 358,235 301,563
Consolidated depreciation
and amortization(b)..................... (67,531) (49,976)
Consolidated amortization of excess
cost of invests......................... (1,394) (1,394)
Interest and corporate administrative
expenses(c)............................. (97,556) (79,715)
---------- ----------
Total consolidated net income............ $ 191,754 $ 170,478
========== ==========
(a) Includes revenues, earnings from equity investments, income taxes and
other, net, less operating expenses.
(b) Amount for 2003 includes $171 of non-cash asset retirement obligation
accretion expense, included within operations and maintenance expense in
the accompanying consolidated statement of income. Amounts of $169 and $2
of such expense is included in the depreciation, depletion and
amortization totals in our CO2 and Natural Gas Pipelines business
segments, respectively.
(c) Includes interest and debt expense, general and administrative expenses,
minority interest expense and cumulative effect adjustment from a change
in accounting principle (2003 only).
March 31, December 31,
----------------------------
2004 2003
------------ -----------
Assets
Products Pipelines..................... $3,248,817 $3,198,107
Natural Gas Pipelines.................. 3,192,229 3,253,792
CO2.................................... 1,253,420 1,177,645
Terminals.............................. 1,384,938 1,368,279
---------- ----------
Total segment assets................... 9,079,404 8,997,823
Corporate assets(a).................... 218,335 141,359
---------- ----------
Total consolidated assets.............. $9,297,739 $9,139,182
========== ==========
(a) Includes cash, cash equivalents and certain unallocable deferred charges.
12. Pensions and Other Post-retirement Benefits
In connection with our acquisition 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):
36
Other Post-retirement Benefits
Three Months Ended March 31,
------------------------------
2004 2003
-------- --------
Net periodic benefit cost $ 28 $ 10
Service cost...........................
Interest cost.......................... 97 202
Expected return on plan assets......... -- --
Amortization of prior service cost..... (31) (155)
Actuarial gain......................... (244) --
------- -------
Net periodic benefit cost.............. $ (150) $ 57
======= =======
Our net periodic benefit cost for the first quarter of 2004 was a credit of
$150,000. This was largely due to the amortization of an actuarial gain in the
amount of $244,000, 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 March 31, 2004, we estimate our overall net periodic postretirement
benefit cost to be an annual credit of approximately $601,000, or $150,000 per
quarter. These numbers could change in future quarters of 2004 if there is a
significant event, such as a plan amendment or a plan curtailment, during the
year that requires 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 $300,000 to our
post-retirement benefit plans in 2004. As of March 31, 2004, approximately
$75,000 of contributions have been made. We presently anticipate contributing an
additional $225,000 to our post-retirement benefit plans in 2004 for a total of
$300,000.
13. 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
37
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
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. We do not expect
this Interpretation to have any immediate effect on our consolidated financial
statements.
38
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 the results of operations for each segment of our business, followed by
a description of our financial condition. The discussion and analysis is based
on our Consolidated Financial Statements. These Statements are included
elsewhere in this report and were prepared in accordance with accounting
principles generally accepted in the United States of America. It is often
useful to read the discussion and analysis in conjunction with Note 11 to our
Consolidated Financial Statements, entitled "Reportable Segments."
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. 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 quarter of 2004.
Results of Operations
First Quarter 2004 Compared With First Quarter 2003
Three Months Ended March 31,
----------------------------
2004 2003
------------ -----------
(In thousands)
Earnings before depreciation, depletion
and amortization expense and amortization
of excess cost of equity investments
Products Pipelines........................ $ 114,254 $ 108,674
Natural Gas Pipelines..................... 103,105 91,561
CO2....................................... 77,703 41,966
Terminals................................. 63,173 59,362
---------- ----------
Segment earnings before depreciation,
depletion and amortization expense
and amortization of excess cost of
equity investments(a)..................... 358,235 301,563
Total consolidated depreciation,
depletion and amortization expense(b).... (67,531) (49,976)
Total consolidated amortization of
excess cost of equity investments........ (1,394) (1,394)
Interest and corporate administrative
expenses(c).............................. (97,556) (79,715)
---------- ----------
Net income................................. $ 191,754 $ 170,478
========== ==========
- ----------
(a) Includes revenues, earnings from equity investments, income taxes and other,
net, less operating expenses.
(b) Amount for 2003 includes $171 of non-cash asset retirement obligation
accretion expense, included within operations and maintenance expense in the
accompanying consolidated statement of income. Amounts of $169 and $2 of
such expense is included in the depreciation, depletion and amortization
totals in our CO2 and Natural Gas Pipelines business segments, respectively.
(c) Includes interest and debt expense, general and administrative expenses,
minority interest expense and cumulative effect adjustment from a change in
accounting principle (2003 only).
39
Driven by increases in oil production, petroleum products and natural gas
volumes, higher deliveries of carbon dioxide used to support crude oil
production, terminal expansions and growth, and contributions from acquisitions
made since the end of the first quarter of 2003, our consolidated net income for
the first quarter of 2004 was a record $191.8 million ($0.52 per diluted unit),
up 12% from the $170.5 million ($0.52 per diluted unit) in consolidated net
income for the first quarter of 2003. Additionally, our 2003 first quarter
results benefited from a cumulative effect adjustment of $3.5 million related to
a change in accounting for asset retirement obligations pursuant to our adoption
of Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations" on January 1, 2003. Before the cumulative effect
adjustment, net income for the quarter totaled $167.0 million ($0.50 per diluted
unit). Revenues earned in the first quarter of 2004 rose $33.5 million (2%) to
$1,822.3 million, compared to revenues of $1,788.8 million in the first quarter
of 2003.
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 net additions to
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 the first three months of 2004, all four of our reportable
business segments reported period-to-period increases in earnings before
depreciation, depletion and amortization, compared to 2003.
The quarter-to-quarter increase in our earnings before depreciation,
depletion and amortization was primarily due to higher earnings from our CO2 and
Natural Gas Pipelines business segments. Our CO2 segment benefited from both
increased activity in oil field operations and our acquisition of additional
working interests in oil producing properties since March 31, 2003. These
acquisitions included the following:
o effective June 1, 2003, we acquired MKM Partners, L.P.'s 12.75% ownership
interest in the SACROC oil field unit for $23.3 million in cash and the
assumption of $1.9 million of liabilities. This transaction increased our
ownership interest in the SACROC unit to approximately 97%; and
o effective November 1, 2003, we acquired certain assets in the Permian Basin
of West Texas from a subsidiary of Marathon Oil Corporation for $231.0
million in cash and the assumption of $28.0 million of liabilities. The
assets acquired included Marathon's approximate 42.5% interest in the
Yates oil field unit, the crude oil gathering system surrounding the Yates
field and Marathon's 65% ownership interest in the Pecos Carbon Dioxide
Pipeline Company. This transaction increased our ownership interest in the
Yates unit to nearly 50% and allowed us to become operator of the field.
Our Natural Gas Pipelines segment benefited from higher margins from natural
gas sales activities, mainly due to optimizing natural gas storage spreads and
segmenting certain services that we provide producers. We also realized higher
natural gas transportation revenues, and we benefited from the inclusion of a
full three months of operations from our Mier-Monterrey, Mexico Pipeline, which
began operations in March 2003.
Also, we declared a record cash distribution of $0.69 per unit for the first
quarter of 2004 (an annualized rate of $2.76). This distribution is 8% higher
than the $0.64 per unit distribution we made for the first quarter of 2003, and
1% higher than the $0.68 per unit distribution we made for the fourth quarter of
2003. We expect to declare cash distributions of at least $2.84 per unit for
2004 and to increase our annualized cash distribution per unit to $2.90 to $2.94
by December 31, 2004; however, no assurance can be given that we will be able to
achieve these levels of distribution.
40
Products Pipelines
Three Months Ended March 31,
----------------------------
2004 2003
------------ -----------
(In thousands, except
operating statistics)
Revenues................................. $ 154,856 $ 144,417
Operating expenses(a).................... (42,878) (41,186)
Earnings from equity investments......... 5,019 8,043
Other, net............................... (362) 225
Income taxes............................. (2,381) (2,825)
---------- ----------
Earnings before depreciation,
depletion and amortization expense
and amortization of excess cost of
equity investments..................... 114,254 108,674
Depreciation, depletion and
amortization expense.................... (17,416) (16,560)
Amortization of excess cost of
equity investments...................... (821) (821)
---------- ----------
Segment earnings........................ $ 96,017 $ 91,293
========== ==========
Refined product volumes (MMBbl).......... 176.6 166.6
Natural gas liquids (MMBbl).............. 11.5 12.8
---------- ----------
Total delivery volumes (MMBbl)(b) 188.1 179.4
========== ==========
- ----------
(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 $114.3 million on revenues of $154.9 million in
the first quarter of 2004. This compared to earnings before depreciation,
depletion and amortization of $108.7 million on revenues of $144.4 million in
the first quarter of 2003.
The segment's overall $5.6 million (5%) increase in earnings before
depreciation, depletion and amortization in the first three months of 2004
compared to the same year-ago period included a $4.8 million (9%) increase from
our Pacific operations, a $2.4 million (51%) increase from our 44.8% ownership
interest in the Cochin pipeline system, a $1.4 million increase from our
recently acquired Southeast terminal operations, a $0.4 million (6%) increase
from our Central Florida Pipeline system, and a $0.3 million (6%) increase from
our petroleum product transmix operations. Generally, these increases resulted
from higher revenues, driven by both a 6% increase in refined petroleum product
delivery volumes and higher terminal fees resulting from the 2003 transition in
California from MTBE-blended gasoline to ethanol-blended gasoline.
Combined, the segment benefited from quarter-to-quarter increases of 5% in
gasoline delivery volumes and almost 7% in diesel fuel volumes, both despite
higher prices, and an 8% increase in jet fuel delivery volumes, due to increased
domestic military activity and higher commercial jet fuel demand at most of the
airports we serve. Due to the fact that ethanol cannot be transported via
pipeline but instead must be blended at terminals, we benefited from increases
in the fees that we earn from ethanol-related services at many of our West Coast
terminal operations. As of December 31, 2003, we had ethanol blending facilities
in place at all of our California terminals necessary to serve all of our
customers and the fees generated from these facilities positively contributed to
our earnings in the first quarter of 2004.
The $1.4 million in earnings before depreciation, depletion and amortization
that was realized in the first quarter of 2004 by our Southeast terminals
related to the operations of fourteen refined products terminals located in the
southeastern United States that we acquired in December 2003 and March 2004.
Combined, these terminals have a total capacity of approximately 4.35 million
barrels for gasoline, diesel fuel and jet fuel. For the first quarter of 2004,
the Southeast terminals reported revenues of $2.3 million and operating expenses
of $0.9 million. For more information on our acquisitions, see Note 2 to our
Consolidated Financial Statements included elsewhere in this report.
The overall increase in earnings before depreciation, depletion and
amortization in the first three months of 2004, compared to the first three
months of 2003, was partly offset by a $1.9 million (21%) decrease from our
North System natural gas liquids pipeline, primarily due to lower revenues
resulting from a decline in throughput delivery
41
volumes resulting from lower propane volumes. In April 2004, we filed a plan
with the Federal Energy Regulatory Commission to produce a line-fill service,
which we expect to mitigate the supply problems we experienced in the first
quarter of 2004. Earnings from our approximate 51% ownership interest in
Plantation Pipe Line Company, which we account for under the equity method of
accounting, decreased $1.6 million (17%) in the first quarter of 2004, compared
to the first quarter of 2003. The decrease was mainly due to higher litigation
settlement expenses, incurred by Plantation in the first quarter of 2004,
related to the resolution of a past environmental issue. We expect to recover
these settlement expenses under our insurance policies.
Revenues for the segment increased $10.5 million (7%) in the first quarter of
2004 compared to the first quarter of 2003. In addition to the $2.3 million
increase from our Southeast terminals, discussed above, significant
quarter-to-quarter increases in revenues included a $5.7 million (8%) increase
from our Pacific operations, a $3.5 million (46%) increase from Cochin, a $0.5
million (6%) increase from our Central Florida Pipeline, a $0.3 million (4%)
increase from our transmix operations, and a $0.3 million (2%) increase from our
CALNEV Pipeline. The higher revenues from our Pacific operations included an
increase of $2.9 million related to ethanol blending services, gathering, and
product terminal revenues, and an increase of $2.8 million related to higher
refined petroleum product deliveries, due to a 5% increase in mainline delivery
volumes. The quarter-to-quarter increase in our proportionate share of revenues
from the Cochin pipeline system was largely due to a 27% increase in product
delivery volumes in the first quarter of 2004 compared to the first quarter of
2003. In last year's first quarter, western Canada experienced a decrease in
propane production due to lower profit margins on the production of natural gas
liquids caused by high natural gas prices, resulting in decreased delivery
volumes. The increase in Central Florida Pipeline's revenues related to an
almost 5% increase in refined product delivery volumes, primarily due to strong
demand for gasoline and jet fuel. The increase in revenues from our transmix
operations was largely due to an almost 5% increase in processing volumes, as
both our Dorsey Junction, Maryland and Richmond, Virginia facilities processed
higher volumes of transmix in the first quarter of 2004, compared to the first
quarter of 2003. Finally, the 2% quarter-to-quarter increase in revenues from
our CALNEV Pipeline was due to an over 9% increase in refined product delivery
volumes, mainly the result of higher deliveries to our Las Vegas, Nevada
products terminal and McCarran International Airport, located in Las Vegas.
The overall quarter-to-quarter increase in segment revenues was partially
offset by a $2.6 million (19%) decrease in revenues from our North System. The
decline in our North System's revenues was primarily due to a 17% drop in
throughput delivery volumes, as mentioned above, primarily due to a lack of
propane supplies caused by shippers reducing line-fill and storage volumes on
the North System to lower amounts at the close of winter, as compared to last
year.
The segment's operating expenses remained relatively flat in the first
quarter of 2004, compared to the first quarter of 2003. The $1.7 million (4%)
increase in first quarter 2004 over first quarter 2003 was primarily due to
higher fuel and power expenses incurred by our Pacific operations and higher
operating and maintenance expenses incurred by our West Coast terminals. The
increase in fuel and power expenses was mainly due to higher delivery volumes.
The increase in operating and maintenance expenses was due to higher payments
for outside services, warehouse supplies, and terminal maintenance.
Earnings from equity investments consisted primarily of earnings related to
our ownership interest in Plantation Pipe Line Company. The $3.0 million (38%)
decrease in equity earnings in the first quarter of 2004 versus the first
quarter of 2003 was mainly due to a $3.2 million expense recorded in 2004 for
our share of an environmental litigation settlement reached between Plantation
and various plaintiffs. We expect to recover the effect of this settlement under
our insurance policies. The decrease in equity earnings resulting from higher
litigation settlement costs was partially offset by an increase in equity
earnings associated with higher revenues earned by Plantation. In the first
quarter of 2004, Plantation benefited from a 6% increase in product delivery
volumes, compared to the first quarter of 2003. The increase was mainly due to
various refinery problems that affected product supplies in the first quarter of
2003.
Other income items decreased $0.6 million in the first quarter of 2004 versus
the first quarter of 2003, mainly due to the recognition of slightly higher
losses realized from sales of property, plant and equipment by our Pacific
operations. The $0.4 million (16%) quarter-to-quarter decrease in income tax
expenses represents the difference between a $1.1 million decrease due to
overall lower earnings from Plantation and a $0.7 million increase due to
overall higher earnings from Cochin.
42
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, were $18.2 million in the first
quarter of 2004 and $17.4 million in the first quarter of 2003. The $0.8 million
(5%) increase was mainly due to higher property and plant depreciation expenses
from our Pacific operations and CALNEV Pipeline, as well as incremental
depreciation charges incurred on our recently acquired Southeast terminals. The
increases to Pacific and CALNEV were related to the capital spending we have
made since the end of the first quarter of 2003 in order to strengthen and
enhance our business operations on the West Coast.
Natural Gas Pipelines
Three Months Ended March 31,
----------------------------
2004 2003
------------ -----------
(In thousands, except
operating statistics)
Revenues................................. $1,437,908 $1,480,954
Operating expenses(a).................... (1,339,960) (1,395,532)
Earnings from equity investments......... 4,967 6,224
Other, net............................... 1,130 23
Income taxes............................. (940) (108)
---------- ----------
Earnings before depreciation,
depletion and amortization
expense and amortization of
excess cost of equity investments...... 103,105 91,561
Depreciation, depletion and
amortization expense.................... (12,842) (12,626)
Amortization of excess cost of
equity investments....................... (69) (69)
---------- ----------
Segment earnings........................ $ 90,194 $ 78,866
========== ==========
Natural gas transport volumes (Bcf)(b)... 272.6 260.4
========== ==========
Natural gas sales volumes (Bcf)(c)....... 245.1 207.2
========== ==========
- ----------
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes. Amount for 2003 excludes $2 of non-cash asset retirement obligation
accretion expense, included within operations and maintenance expense in the
accompanying consolidated statement of income but included in the segment's
depreciation, depletion and amortization expense below.
(b) Includes Kinder Morgan Interstate Gas Transmission, Texas Intrastate group
and Trailblazer pipeline volumes.
(c) Includes Texas Intrastate group volumes.
Our Natural Gas Pipelines segment reported earnings before depreciation,
depletion and amortization of $103.1 million on revenues of $1,437.9 million in
the first quarter of 2004. This compared to earnings before depreciation,
depletion and amortization of $91.6 million on revenues of $1,481.0 million in
the first quarter of 2003.
The segment's $11.5 million (13%) increase in earnings before depreciation,
depletion and amortization in the first three months of 2004 compared to same
period of 2003 was largely attributable to 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.
Earnings before depreciation, depletion and amortization from our Texas
intrastate natural gas pipeline group increased $17.4 million (40%) in the first
quarter of 2004, compared to the first quarter of 2003. Included in this total
was an increase of $13.8 million in earnings before depreciation, depletion and
amortization from the combined operations of Kinder Morgan Tejas and Kinder
Morgan Texas Pipeline. The increase was driven by improved performance in the
overall natural gas sales business, largely the result of margin enhancements,
segmenting services, and an approximate 18% quarter-to-quarter growth in natural
gas sales volumes. We also benefited from full contract demand levels under the
long-term transportation and sales contracts with BP Energy of North America,
and operational efficiencies, which reduced the amount of gas lost during normal
operations.
Earnings before depreciation, depletion and amortization were also favorably
impacted by higher gas transportation revenues from our North Texas Pipeline and
by the inclusion of a full quarter of contributions from our Mier-Monterrey
Pipeline, which began service in March 2003. The North Texas Pipeline
contributed $1.9
43
million of incremental earnings before depreciation, depletion and amortization,
chiefly due to gas transmission fees earned for providing gas to an electric
generating facility in north Texas, which started full service in August 2003.
The inclusion of a full three months of operations in 2004 for our
Mier-Monterrey Pipeline accounted for incremental earnings before depreciation,
depletion and amortization of $1.7 million, compared to first quarter 2003.
The segment's overall increase in earnings before depreciation, depletion and
amortization was offset by a $5.2 million (14%) decrease in earnings from our
two Rocky Mountain natural gas pipeline systems (Kinder Morgan Interstate Gas
Transmission and Trailblazer Pipeline Company) and a $1.4 million (28%) decrease
in earnings from our 49% equity investment in the Red Cedar Gas Gathering
Company. The decrease in earnings before depreciation, depletion and
amortization from our Rocky Mountain pipelines was due to lower natural gas
transportation revenues on our Trailblazer pipeline system, resulting from a
rate case settlement which was anticipated in our 2004 budget, and lower natural
gas operational sales and transportation revenues on our Kinder Morgan
Interstate Gas Transmission system.
Total segment revenues decreased $43.1 million (3%) in the first quarter of
2004 compared to the first quarter of 2003. The overall drop in revenues
includes a $52.4 million (4%) decrease in natural gas sales revenues from our
Texas intrastate pipeline group, resulting from a 23% decrease in the average
price received from sales of natural gas, but partially offset by an 18%
increase in the intrastate group's gas sales volume. Both Kinder Morgan Tejas
and Kinder Morgan Texas Pipeline purchase and sell significant volumes of
natural gas, which is transported through their pipeline systems, and,
accordingly, the combined pipeline systems reported a $57.6 million (4%)
decrease in purchased gas costs, also due to the lower gas prices in the first
quarter of 2004 compared to the first quarter of 2003. Our intrastate group's
revenues earned from services, product sales and other sources increased $15.4
million in the first quarter of 2004, compared to the first quarter of 2003. The
increase was due to higher fees for gas transmission (including revenues from
our North Texas Pipeline), blending and other services, and to $3.2 million in
incremental revenues from the Mier-Monterrey Pipeline. Revenues from our Rocky
Mountain pipeline systems decreased $4.5 million (8%) in the first quarter of
2004, compared to the same quarter last year. As described above, the decrease
was due to lower natural gas transportation revenues from our Trailblazer
pipeline system and lower operational sales and transportation revenues from our
Kinder Morgan Interstate Gas Transmission system. Quarter-to-quarter average
tariff rates decreased over 9% on our Trailblazer Pipeline, mainly due to lower
rates that became effective January 1, 2004, following a rate case settlement.
The quarter-to-quarter decrease in both natural gas operational sales and
transportation revenues from our Kinder Morgan Interstate system was primarily
due to lower volumes, mainly due to lower demand.
The $55.6 million (4%) overall decrease in segment operating expenses reflects
the $57.6 million decrease in the intrastate group's gas purchase costs,
described above. The decrease was partially offset by a $2.0 million increase
that was mainly the result of higher fuel recovery costs, higher maintenance
expenses related to pipeline cleaning, and higher taxes, other than income
taxes, related to higher property tax accruals for the 2004 tax year. The $1.3
million (20%) decrease in earnings from equity investments in the first quarter
of 2004, compared to the first quarter of 2003, related to lower earnings from
our investment in Red Cedar. Red Cedar reported lower earnings in the first
quarter of 2004 largely due to higher sales of excess fuel gas during the first
quarter of 2003.
The $1.1 million increase in other income items was the result of higher gains
on miscellaneous property and equipment disposals, taken in the first quarter of
2004 by our Texas intrastate pipeline group. The $0.8 million increase in income
tax expenses in the first quarter of 2004, compared to the first quarter of
2003, primarily relates to the additional tax expense associated with the
inclusion of a full quarter of operations from our Mier-Monterrey Mexico
Pipeline.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, were up a slight $0.2 million (2%)
in the first quarter of 2004 compared to the first quarter of 2003. Normal
increases in depreciation charges related to additional capital investments made
since the end of the first quarter of 2003 were largely offset by favorable
changes in the estimated remaining useful lives of certain assets on our
Trailblazer Pipeline Company.
44
CO2
Three Months Ended March 31,
----------------------------
2004 2003
------------ -----------
(In thousands, except
operating statistics)
Revenues................................. $ 105,586 $ 48,456
Operating expenses(a).................... (38,385) (16,513)
Earnings from equity investments......... 10,479 10,006
Other, net............................... 9 17
Income taxes............................. 14 --
---------- ----------
Earnings before depreciation,
depletion and amortization
expense and amortization of
excess cost of equity investments...... 77,703 41,966
Depreciation, depletion and
amortization expense.................... (26,988) (11,762)
Amortization of excess cost of
equity investments...................... (504) (504)
---------- ----------
Segment earnings........................ $ 50,211 $ 29,700
========== ==========
Carbon dioxide volumes transported
(Bcf)(b)................................ 182.5 102.3
========== ==========
SACROC Oil production (MBbl/d)(c)........ 26.1 17.0
========== ==========
Yates Oil production (MBbl/d)(c)......... 17.8 18.1
========== ==========
Realized Weighted Average Oil
Price per Bbl........................... $ 25.37 $ 24.87
========== ==========
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and power
expenses and taxes, other than income taxes. Amount for 2003 excludes $169
of non-cash asset retirement obligation accretion expense, included within
operations and maintenance expense in the accompanying consolidated
statement of income but included in the segment's depreciation, depletion
and amortization expense below.
(b) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos
pipeline volumes.
(c) Represents 100% production from the field.
In the first quarter of 2004, our CO2 segment reported earnings before
depreciation, depletion and amortization of $77.7 million on revenues of $105.6
million. This compared to earnings before depreciation, depletion and
amortization of $42.0 million on revenues of $48.5 million in the first quarter
of 2003.
A significant portion of the segment's $35.7 million (85%) increase in
earnings before depreciation, depletion and amortization, $57.1 million (118%)
increase in revenues, and $21.9 million (132%) increase in operating expenses
was due to increased oil production at SACROC, higher carbon dioxide delivery
volumes and increased ownership interests in oil reserves. We increased our
ownership of oil reserves since the end of the first quarter of 2003 by
acquiring additional interests in the SACROC and Yates oil field units, as
referred to above. We also benefited from capital expansion projects completed
at SACROC since the end of the first quarter of 2003.
The SACROC oil field reported a particularly strong first quarter, with daily
oil production volumes up 54% in the first quarter of 2004, compared to the
first quarter of 2003. We also benefited from an approximate 2% increase in our
realized weighted average price of oil per barrel (from $24.87 in the first
quarter of 2003 to $25.37 per barrel in the first quarter of 2004). As a result
of our oil reserve ownership interests, we are exposed to commodity price risk,
but the risk is mitigated by our 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.
Revenues increased due to higher carbon dioxide delivery volumes throughout
the Permian Basin since the end of the first quarter of 2003, as well as to
higher crude oil production and higher revenues from gasoline plant product
sales. Combined deliveries on our Central Basin Pipeline, our majority-owned
Canyon Reef Carriers and Pecos Pipelines, our 50% owned Cortez Pipeline and our
Centerline Pipeline increased 80.2 billion cubic feet (78%) in the first quarter
of 2004, compared to the first quarter of 2003. The increase in carbon dioxide
delivery volumes driven by the continued expansion at SACROC and the initiation
of carbon dioxide flooding at the Yates oil field resulted in record production
at our approximately 45% owned McElmo Dome. The Centerline Pipeline, which began
operations in May 2003, consists of approximately 113 miles of 16-inch diameter
pipe located in the Permian Basin between Denver City, Texas and Snyder, Texas.
It transported 24.9 billion cubic feet of carbon dioxide during the first
quarter of 2004, primarily to the SACROC oil field; however, we do not recognize
profits on carbon dioxide
45
sales to ourselves. Revenues from gasoline plant products sales also increased
in the first quarter of 2004, when compared to the first quarter of 2003. The
increase was due to both higher oil and gas production volumes and higher
product prices. Revenues from oil gathering increased as well, due to our
November 2003 acquisition of the crude oil gathering system surrounding the
Yates oil field. Combined, our acquisition of additional working interests and
assets in the SACROC and Yates oil field units, as referred to above,
contributed incremental revenues of approximately $29.2 million in the first
quarter of 2004.
The period-to-period increases in operating expenses related to higher
operating and maintenance expenses, higher fuel and power costs, and higher
production taxes, all as a result of the increase in oil production volumes. The
slight $0.5 million (5%) increase in earnings from equity investments in the
first quarter of 2004 compared to the first quarter of 2003 reflects the net of
a $3.4 million (49%) increase in equity earnings from our 50% investment in
Cortez Pipeline Company, partially offset by a $2.9 million decrease in equity
earnings from our previous 15% interest in MKM Partners, L.P. The increase in
earnings from our equity interest in Cortez was mainly due to a 40%
quarter-to-quarter increase in carbon dioxide delivery volumes. We had no equity
earnings from MKM Partners, L.P. during the first quarter in 2004 due to the
fact that MKM Partners was dissolved effective June 30, 2003, following our
acquisition of its 12.75% ownership interest in the SACROC oil field.
Non-cash depreciation, depletion and amortization charges were up $15.2
million (124%) in the first three months of 2004 compared to same period of
2003, primarily due to higher production, higher unit-of-production depletion
rates and the acquisition of our additional interest in the Yates oil field.
Terminals
Three Months Ended March 31,
----------------------------
2004 2003
------------ -----------
(In thousands, except
operating statistics)
Revenues................................. $ 123,906 $ 115,011
Operating expenses(a).................... (60,106) (54,438)
Earnings from equity investments......... 4 32
Other, net............................... (34) 12
Income taxes............................. (597) (1,255)
---------- ----------
Earnings before depreciation,
depletion and amortization
expense and amortization of
excess cost of equity investments...... 63,173 59,362
Depreciation, depletion and
amortization expense.................... (10,285) (9,028)
Amortization of excess cost of
equity investments...................... -- --
---------- ----------
Segment earnings........................ $ 52,888 $ 50,334
========== ==========
Bulk transload tonnage (MMtons)(b)....... 14.8 14.5
========== ==========
Liquids leaseable capacity (MMBbl)....... 36.1 35.6
========== ==========
Liquids utilization %.................... 96.0% 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, dry-bulk materials
and petrochemical-related liquids terminal facilities. These operations include
transloading and storing dry bulk and liquid products, terminal engineering and
design, and marine and other in-plant services. Our terminals segment reported
earnings before depreciation, depletion and amortization of $63.2 million on
revenues of $123.9 million in the first quarter of 2004, compared to earnings
before depreciation, depletion and amortization of $59.4 million on revenues of
$115.0 million in the first quarter of 2003.
Half of the $3.8 million (6%) period-to-period increase in earnings before
depreciation, depletion and amortization was attributable to bulk terminal
businesses and half was attributable to liquids terminal businesses. The $1.9
million (8%) increase in our bulk terminals' earnings before depreciation,
depletion and amortization was primarily due to internal growth and to
incremental earnings from the two bulk terminal businesses in Tampa,
46
Florida, that we acquired in December 2003. The internal growth was driven by a
$4.8 million (8%) increase in revenues from all bulk terminal operations owned
during both quarters. In total, the segment benefited from a 2% increase in
total bulk tonnage transloaded during the first quarter of 2004, compared to the
first quarter of 2003. The increase from the December 2003 acquisition primarily
related to the operations of a marine terminal and an inland bulk storage
warehouse facility that we purchased and collectively refer to as the Kinder
Morgan Tampaplex terminal. The terminal 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. For the first quarter of 2004, Kinder
Morgan Tampaplex reported earnings before depreciation, depletion and
amortization of $1.6 million, revenues of $2.3 million and operating expenses of
$0.7 million.
The $1.9 million (5%) increase in our liquids terminals' earnings before
depreciation, depletion and amortization was primarily due to a $1.8 million
(3%) increase in revenues, driven by higher throughput volumes and additional
service contracts at our liquids terminal facility located in Carteret, New
Jersey on the New York Harbor, and at our Pasadena and Galena Park, Texas
facilities, located along the Houston Ship Channel.
The total $8.9 million (8%) increase in revenues in the first quarter of 2004,
compared to the first quarter of 2003, includes increases of $3.9 million from
our Carteret, Pasadena and Galena Park liquids terminal facilities, $2.7 million
from our 66 2/3% ownership interest in the International Marine Terminals
Partnership, and $2.3 million from Kinder Morgan Tampaplex, discussed above. The
increase in revenues at Carteret related to both capital expansion projects
completed since March 2003 and increased imports in the Northeast. The increases
in revenues at Pasadena and Galena Park were due to higher transfer volumes
resulting from expansion projects, additional liquids storage contracts,
escalations in annual contract provisions, and higher refinery production in the
Gulf Coast. Expansion projects completed since the end of the first quarter of
2003, which included the construction of additional petroleum products storage
tanks, increased our total liquids leaseable capacity by 500,000 barrels (1%),
and we have been able to maintain the same high liquids utilization capacity
rate of 96% in the first quarter of 2004, compared to the first quarter of 2003.
The increase in revenues from IMT, which operates a bulk commodity transfer
facility located in Port Sulphur, Louisiana, was driven by a 65% increase in
bulk tonnage transfer volume, primarily coal and iron ore, and by higher dockage
revenues.
The $5.7 million (10%) increase in operating expenses in the first quarter
of 2004 compared to the same prior year period was primarily due to higher
operating and maintenance expenses associated with our bulk terminal operations.
Operating and maintenance expenses for all bulk terminal operations increased
$4.3 million in the first quarter of 2004, compared to the first quarter of
2003, largely related to the increase in dry-bulk tonnage transfer volumes. The
increase includes higher expenses at IMT in the amount of $1.5 million, the
result of higher crane rental fees, marine docking expenses, and payroll
expenses, and incremental expenses incurred by the newly acquired Kinder Morgan
Tampaplex terminal in the amount of $0.7 million. Additional increases to
segment operating expenses for the first quarter of 2004 compared to first
quarter 2003, include a $1.1 million increase in fuel and power costs, related
to incremental heating oil purchases and higher natural gas rates in 2004, and a
$0.4 million increase in operating and maintenance expenses for all liquids
terminals operations, related to higher payroll expenses and higher overall
terminal volumes.
Income tax expenses totaled $0.6 million in the first quarter of 2004, versus
$1.3 million in the first quarter of 2003. The $0.7 million (54%)
quarter-to-quarter decrease in income tax expenses was due to lower overall
taxable income. For both quarters, the segment's taxable income primarily
consisted of the taxable income of two tax-paying entities: Kinder Morgan Bulk
Terminals, Inc. and Delta Terminal Services LLC.
Non-cash depreciation, depletion and amortization charges were $10.3 million
in the first quarter of 2004 and $9.0 million in the first quarter of 2003. The
$1.3 million (14%) increase in the first quarter of 2004 versus the first
quarter of 2003 reflects higher depreciation charges on property, plant and
equipment utilized in both our bulk terminal and liquids terminal operations.
The higher depreciation charges resulted from the additional capital spending we
have made since the end of the first quarter of 2003, including additional
transfers of completed project costs into depreciable plant.
47
Other
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. Combined, these
items totaled $97.6 million in the first quarter of 2004 and $79.7 million in
the first quarter of 2003. The amount in the first quarter of 2003 includes an
offset of $3.5 million resulting from the cumulative effect adjustment related
to our change in accounting for asset retirement obligations.
Our general and administrative expenses include such items as salaries and
employee-related expenses, payroll taxes, legal fees, insurance and office
supplies and rentals, and together, these items totaled $48.3 million in the
first quarter of 2004, compared to $36.0 million in the same prior year period.
The $12.3 million (34%) increase in general and administrative expenses in the
first quarter of 2004 compared to the first quarter of 2003 was primarily due to
higher employee bonus and benefit expenses, timing differences in the
recognition of employee bonus expenses, and higher overall corporate and
worker-related insurance expenses.
Our total interest expense, net of interest income, was $47.2 million in the
first quarter of 2004, versus $44.9 million in the first quarter of 2003. The
$2.3 million (5%) period-to-period increase in net interest expense was due to
higher average borrowings during the first quarter of 2004, compared to the
first quarter of 2003. The increase in average borrowings was primarily due to
incremental borrowings made in connection with acquisition expenditures made
since the end of the first quarter of 2003. These acquisitions included the
additional oil reserve ownership interest and the carbon dioxide assets that we
acquired from a subsidiary of Marathon Oil Corporation effective November 1,
2003, and the seven refined petroleum products terminals that we acquired from
Exxon Mobil Corporation effective March 9, 2004. The overall increase in net
interest expense was partially offset by slightly lower average borrowing rates
during the first quarter of 2004 relative to the first quarter of 2003. For more
information on our acquisitions, see Note 2 to our Consolidated Financial
Statements included elsewhere in this report, and "Financial Condition -
Investing Activities," discussed below.
Minority interest, which includes the 1.0101% general partner interest in our
five operating limited partnerships, remained relatively flat in the first
quarter of each year, totaling $2.1 million in the first quarter of 2004 and
$2.3 million in the first quarter of 2003. The slight $0.2 million (9%) decrease
in the first quarter of 2004 from the first quarter of 2003 resulted mainly from
our November 1, 2003 acquisition of the remaining approximate 32% ownership
interest in MidTex Gas Storage Company, LLP that we did not already own, thereby
eliminating the minority interest related to MidTex.
Financial Condition
The following table illustrates the sources of our invested capital. Since
December 31, 2003, we have strengthened our balance sheet as we have reduced our
debt to total capitalization ratio by about 2% (from 54.7% at December 31, 2003
to 52.6% at March 31, 2004). In addition to our results of operations, these
balances are affected by our financing activities as discussed below (dollars in
thousands):
March 31, December 31,
--------- ------------
2004 2003
--------- ------------
Long-term debt, excluding market
value of interest rate swaps.............. $4,066,860 $4,316,678
Minority interest.......................... 42,009 40,064
Partners' capital.......................... 3,697,700 3,510,927
---------- ----------
Total capitalization...................... 7,806,569 7,867,669
Short-term debt, less cash and
cash equivalents.......................... 86,622 (21,081)
---------- ----------
Total invested capital.................... $7,893,191 $7,846,588
========== ==========
Capitalization:
Long-term debt, excluding market
value of interest rate swaps............ 52.1% 54.9%
Minority interest........................ 0.5% 0.5%
Partners' capital........................ 47.4% 44.6%
---------- ----------
100.0% 100.0%
========== ==========
48
March 31, December 31,
--------- ------------
2004 2003
---------- ----------
Invested Capital:
Total debt, less cash and cash equivalents
and excluding market value of interest
rate swaps............................... 52.6% 54.7%
Partners' capital and minority interest... 47.4% 45.3%
---------- ----------
100.0% 100.0%
========== ==========
Our primary cash requirements, in addition to normal operating expenses, are
debt service, sustaining capital expenditures, expansion capital expenditures
and quarterly distributions to our common unitholders, Class B unitholders and
general partner. In addition to utilizing cash generated from operations, we
could meet our cash requirements (other than distributions to our common
unitholders, Class B unitholders and general partner) through borrowings under
our credit facilities, issuing short-term commercial paper, long-term notes or
additional common units or issuing additional i-units to KMR. In general, we
expect to fund:
o cash distributions and sustaining capital expenditures with existing cash
and cash flows from operating activities;
o expansion capital expenditures and working capital deficits with cash
retained (as a result of 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.
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 March 31, 2004, our budgeted expenditures for the remaining nine months
of 2004 for sustaining capital spending were approximately $95.8 million. 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 $270.1 million for the three
months ended March 31, 2004, versus $171.2 million in the comparable period of
2003. The period-to-period increase of $98.9 million (58%) in cash flow from
operations resulted chiefly from a $52.9 million increase in cash inflows
relative to net changes in working capital items and a $46.4 million increase in
cash from overall higher partnership income, net of non-cash items including
depreciation charges and undistributed earnings from equity investments.
49
The increase in funds generated by working capital was mainly due to higher
settlements of related party payables during the first three months of 2003,
primarily associated with reimbursements to KMI for costs related to the
construction of our Mier-Monterrey Pipeline and for general and administrative
services. The increase in funds from overall higher partnership income in the
first quarter of 2004 compared to the first quarter of 2003 reflects the
additional contributions we received from our predominantly fee-based business
portfolio of assets.
Investing Activities
Net cash used in investing activities was $196.6 million for the three month
period ended March 31, 2004, compared to $158.5 million in the comparable 2003
period. The $38.1 million (24%) increase in cash used in investing activities
was primarily attributable to higher expenditures made for strategic
acquisitions in the first three months of 2004. For the three months ended March
31, 2004, our acquisition outlays totaled $50.3 million, including $48.1 million
for the acquisition of seven refined petroleum products terminals in the
southeastern United States from Exxon Mobil Corporation. For the three months
ended March 31, 2003, our acquisitions of assets and investments totaled $5.6
million, including $3.5 million used to acquire the remaining 50% ownership
interest in ICPT, L.L.C., a small liquids pipeline limited liability company
associated with our St. Gabriel liquids terminal business. For more information
on our acquisitions, see Note 2 to the Consolidated Financial Statements
included elsewhere in this report.
We also used more funds for capital additions and internal expansion projects
during the first quarter of 2004 compared to the first quarter of 2003.
Including expansion and maintenance projects, our capital expenditures were
$149.7 million in the first three months of 2004 versus $145.8 million in the
same year-ago period. The $3.9 million (3%) increase was mainly due to higher
capital investment in our Products Pipelines and CO2 business segments. Our
sustaining capital expenditures were $20.2 million for the first three months of
2004 compared to $17.1 million for the first three months of 2003.
We continue to expand and grow our existing businesses and have current
projects in place that will significantly add throughput capacity to our refined
products pipelines and increase our carbon dioxide flooding operations. We have
begun the previously announced expansion of our Pacific operations' East Line
pipeline. When completed, the expansion will increase capacity on our El Paso,
Texas to Tucson, Arizona pipeline by approximately 56%, and on our Tucson to
Phoenix, Arizona pipeline by approximately 80%. As of March 31, 2004, we have
invested approximately $13.6 million to complete the replacement of a 12-mile
segment of 8-inch diameter pipeline within the city of Tucson, with a 12-inch
diameter line. The East Line expansion project is expected to cost approximately
$200 million, and the start-up for the expansion is expected to be sometime in
the fourth quarter of 2005 or the first quarter of 2006.
The overall period-to-period increase in funds used in investing activities
includes a $9.0 million decrease in contributions to equity investments in the
first quarter of 2004, compared to the first quarter of 2003. The decrease
relates to an $8.4 million contribution to Plantation Pipe Line Company in the
first quarter of 2003. The contribution was made for our share of an
environmental-related litigation settlement reached between Plantation and
various plaintiffs.
Financing Activities
Net cash used in financing activities amounted to $50.0 million for the three
months ended March 31, 2004 and $17.0 million for the same prior-year period.
The $33.0 million (194%) increase in the first quarter of 2004 over the
comparable 2003 period was the result of a $260.9 million decrease in cash flows
from overall debt financing activities, a $24.3 million decrease in cash flows
resulting from higher distributions to our partners, and a $252.2 million
increase in cash flows from additional partnership equity issuances.
The increase from financing activities, consisting of both issuance and
payments of debt, was due to the higher acquisition and capital investment
expenditures that we made during the first quarter of 2004, as described above
in our discussion of Investing Activities. Distributions to partners, consisting
of all limited partners, our general partner and minority interests, totaled
$184.7 million in the first three months of 2004 compared to $160.4 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.
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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 partnership equity issuance
primarily relates to the cash received from our February 2004 issuance of common
units and our March 2004 issuance of i-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. After 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. After fees, we received net proceeds of $14.9 million for the
issuance of these i-units. We used the proceeds from each of these issuances to
reduce the borrowings under our commercial paper program.
On February 13, 2004, we paid a quarterly distribution of $0.68 per unit for
the fourth quarter of 2003, 9% greater than the $0.625 per unit distribution
paid for the fourth quarter of 2002. We paid this distribution in cash to our
common unitholders and to our Class B unitholders. KMR, our sole i-unitholder,
received 778,309 additional i-units based on the $0.68 cash distribution per
common unit. For each outstanding i-unit that KMR held, a fraction (0.015885) of
an i-unit was issued. The fraction was determined by dividing $0.68, the cash
amount distributed per common unit by $42.807, the average of KMR's shares'
closing market prices from January 13-27, 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 April 21, 2004, we declared a cash distribution for the quarterly period
ended March 31, 2004, of $0.69 per unit. The distribution will be paid on or
before May 14, 2004, to unitholders of record as of April 30, 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 $0.69 distribution per common unit. The number of i-units
distributed will be 872,958. For each outstanding i-unit that KMR holds, a
fraction of an i-unit (0.017412) will be issued. The fraction was determined by
dividing $0.69, the cash amount distributed per common unit by $39.627, the
average of KMR's shares' closing market prices from April 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.
We believe that future operating results will continue to support similar
levels of quarterly cash and i-unit distributions; however, no assurance can be
given that future distributions will continue at such levels.
Partnership Distributions
Our partnership agreement requires that we distribute 100% of available cash,
as defined in our partnership agreement, to our partners within 45 days
following the end of each calendar quarter in accordance with their respective
percentage interests. Available cash consists generally of all of our cash
receipts, including cash received by our operating partnerships, less cash
disbursements and net additions to reserves (including any reserves required
under debt instruments for future principal and interest payments) and amounts
payable to the former general partner of SFPP, L.P. in respect of its remaining
0.5% interest in SFPP.
Our general partner is granted discretion by our partnership agreement, which
discretion has been delegated to KMR, subject to the approval of our general
partner in certain cases, to establish, maintain and adjust reserves for future
operating expenses, debt service, maintenance capital expenditures, rate refunds
and distributions for the next four quarters. These reserves are not restricted
by magnitude, but only by type of future cash requirements with which they can
be associated. When KMR determines our quarterly distributions, it considers
current and expected reserve needs along with current and expected cash flows to
identify the appropriate sustainable distribution level.
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
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event that quarterly distributions to unitholders exceed certain specified
targets.
Available cash for each quarter is distributed:
o first, 98% to the owners of all classes of units pro rata and 2% to our
general partner until the owners of all classes of units have received a
total of $0.15125 per unit in cash or equivalent i-units for such quarter;
o second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the owners
of all classes of units have received a total of $0.17875 per unit in cash
or equivalent i-units for such quarter;
o third, 75% of any available cash then remaining to the owners of all classes
of units pro rata and 25% to our general partner until the owners of all
classes of units have received a total of $0.23375 per unit in cash or
equivalent i-units for such quarter; and
o fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units in
cash and to owners of i-units in the equivalent number of i-units, and 50%
to our general partner.
Incentive distributions are generally defined as all cash distributions paid
to our general partner that are in excess of 2% of the aggregate value of cash
and i-units being distributed. Our general partner's incentive distribution for
the distribution that we declared for the first quarter of 2004 was $90.7
million. Our general partner's incentive distribution for the distribution that
we declared for the first quarter of 2003 was $75.5 million. Our general
partner's incentive distribution that we paid during the first quarter of 2004
to our general partner (for the fourth quarter of 2003) was $85.8 million. Our
general partner's incentive distribution that we paid during the first quarter
of 2003 to our general partner (for the fourth quarter of 2002) was $72.5
million. 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 January 14, 2004, we entered into a $50 million letter of credit that
supports our hedging of commodity price risks involved from the sale of natural
gas, natural gas liquids, oil and carbon dioxide.
There have been no material changes in either certain contractural 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.
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;
52
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;
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; and
o the timing and success of business development efforts.
You should not put undue reliance on any forward-looking statements.
See Items 1 and 2 "Business and Properties--Risk Factors" of our Annual
Report 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
53
those contained in any forward-looking statement. We disclaim any obligation to
update the above list or to announce publicly the result of any revisions to any
of the forward-looking statements to reflect future events or developments. Our
future results also could be adversely impacted by unfavorable results of
litigation and the fruition of contingencies referred to in Note 3 to our
Consolidated Financial Statements included elsewhere in this report.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
There have been no material changes in market risk exposures that would affect
the quantitative and qualitative disclosures presented as of December 31, 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 March 31, 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 March 31,
2004 that has materially affected, or is reasonably likely to materially affect,
our internal control over financial reporting.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 3 to our consolidated financial statements entitled
"Litigation and Other Contingencies," which is incorporated herein by reference.
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of
Equity Securities.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Item 5. Other Information.
None.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits
4.1 -- Certain instruments with respect to long-term debt of the Partnership
and its consolidated subsidiaries which relate to debt that does not
exceed 10% of the total assets of the Partnership and its consolidated
subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of
Regulation S-K, 17 C.F.R. ss.229.601.
11 -- Statement re: computation of per share earnings.
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.
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.
- ---------------------
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(b) Reports on Form 8-K
Current report dated January 21, 2004 on Form 8-K was filed on January 29,
2004, pursuant to Items 7 and 12 of that form. In Item 12, we provided notice
that on January 21, 2004, we issued a press release regarding our financial
results for the quarter and year ended December 31, 2003 and held a webcast
conference call on January 21, 2004 discussing those results. A copy of the
earnings press release and an unedited transcript of the webcast conference
call, prepared by an outside vendor, were filed pursuant to Item 7 as exhibits.
Current report dated March 16, 2004 on Form 8-K was filed on March 18, 2004,
pursuant to Item 7 of that form. We filed the Consolidated Balance Sheet at
December 31, 2003, of Kinder Morgan G.P., Inc., our general partner and a
wholly-owned subsidiary of Kinder Morgan, Inc. as an exhibit pursuant to Item 7
of that form.
Current report dated April 21, 2004 on Form 8-K was filed on April 21, 2004,
pursuant to Items 7 and 12 of that form. In Item 12, we provided notice that on
April 21, 2004, we issued a press release regarding our financial results for
the quarter ended March 31, 2004 and held a webcast conference call discussing
those results. A copy of the earnings press release was filed in Item 7 as an
exhibit pursuant to Item 12.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
KINDER MORGAN ENERGY PARTNERS, L.P.
(A Delaware limited partnership)
By: KINDER MORGAN G.P., INC.,
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: May 6, 2004
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