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 June 30, 2004
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 1-11234
KINDER MORGAN ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0380342
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
500 Dallas Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-369-9000
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X]
No [ ]
The Registrant had 140,041,308 common units outstanding at July 31, 2004.
1
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
PART I. FINANCIAL INFORMATION
Item 1: Financial Statements (Unaudited)................................... 3
Consolidated Statements of Income - Three and Six Months
Ended June 30, 2004 and 2003..................................... 3
Consolidated Balance Sheets - June 30, 2004 and
December 31, 2003................................................ 4
Consolidated Statements of Cash Flows - Six Months Ended
June 30, 2004 and 2003........................................... 5
Notes to Consolidated Financial Statements....................... 6
Item 2: Management's Discussion and Analysis of Financial
Condition and Results of Operations................................ 44
Results of Operations............................................ 44
Financial Condition.............................................. 55
Information Regarding Forward-Looking Statements................. 59
Item 3: Quantitative and Qualitative Disclosures About Market Risk......... 61
Item 4: Controls and Procedures............................................ 61
PART II. OTHER INFORMATION
Item 1: Legal Proceedings.................................................. 62
Item 2: Changes in Securities, Use of Proceeds and Issuer
Purchases of Equity Securities..................................... 62
Item 3: Defaults Upon Senior Securities.................................... 62
Item 4: Submission of Matters to a Vote of Security Holders................ 62
Item 5: Other Information.................................................. 62
Item 6: Exhibits and Reports on Form 8-K................................... 62
Signatures......................................................... 64
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 June 30, Six Months Ended June 30,
--------------------------- --------------------------
2004 2003 2004 2003
------------- ------------- ------------- ---------
Revenues
Natural gas sales............................................ $ 1,449,493 $ 1,239,070 $ 2,775,787 $ 2,617,358
Services..................................................... 380,301 346,888 752,421 681,829
Product sales and other...................................... 127,388 78,489 251,230 154,098
--------- --------- --------- ---------
1,957,182 1,664,447 3,779,438 3,453,285
--------- --------- --------- ---------
Costs and Expenses
Gas purchases and other costs of sales....................... 1,439,326 1,235,375 2,756,635 2,610,789
Operations and maintenance................................... 119,397 100,247 230,589 192,784
Fuel and power............................................... 38,004 23,779 71,512 48,917
Depreciation, depletion and amortization..................... 69,878 53,758 137,409 103,563
General and administrative................................... 39,457 35,685 87,711 71,726
Taxes, other than income taxes............................... 19,756 16,041 39,076 30,792
--------- --------- --------- ---------
1,725,818 1,464,885 3,322,932 3,058,571
--------- --------- --------- ---------
Operating Income............................................... 231,364 199,562 456,506 394,714
Other Income (Expense)
Earnings from equity investments............................. 20,609 22,618 41,078 46,923
Amortization of excess cost of equity investments............ (1,394) (1,394) (2,788) (2,788)
Interest, net................................................ (46,592) (44,896) (93,813) (89,821)
Other, net................................................... (489) 1,508 254 1,785
Minority Interest.............................................. (2,462) (2,125) (4,543) (4,339)
--------- --------- --------- ---------
Income Before Income Taxes and Cumulative Effect of a Change in
Accounting Principle........................................ 201,036 175,273 396,694 346,474
Income Taxes................................................... (5,818) (6,316) (9,722) (10,504)
---------- ---------- ---------- ----------
Income Before Cumulative Effect of a Change in Accounting
Principle....................................................... 195,218 168,957 386,972 335,970
Cumulative effect adjustment from change in accounting for asset
retirement obligations...................................... - - - 3,465
--------- --------- --------- ---------
Net Income..................................................... $ 195,218 $ 168,957 $ 386,972 $ 339,435
========= ========= ========= =========
Calculation of Limited Partners' interest in Net Income:
Income Before Cumulative Effect of a Change in Accounting
Principle....................................................... $ 195,218 $ 168,957 $ 386,972 $ 335,970
Less: General Partner's interest............................... (95,867) (80,530) (187,531) (156,955)
---------- ---------- ---------- ----------
Limited Partners' interest................................... 99,351 88,427 199,441 179,015
Add: Limited Partners' interest in Change in Accounting Principle - - - 3,430
--------- --------- --------- ---------
Limited Partners' interest in Net Income..................... $ 99,351 $ 88,427 $ 199,441 $ 182,445
========= ========= ========= =========
Basic and Diluted Limited Partners' Net Income per Unit:
Income Before Cumulative Effect of a Change in Accounting $ 0.51 $ 0.48 $ 1.03 $ 0.98
Principle.......................................................
Cumulative effect adjustment from change in accounting for asset
retirement obligations...................................... - - - 0.02
--------- --------- --------- ----------
Net Income..................................................... $ 0.51 $ 0.48 $ 1.03 $ 1.00
========= ========= ========= =========
Weighted average number of units used in computation of Limited Partners' Net
Income per unit:
Basic.......................................................... 195,949 183,595 194,231 182,492
========= ========= ========= =========
Diluted........................................................ 196,030 183,706 194,316 182,614
========= ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements.
3
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
June 30, December 31,
2004 2003
------------ ------------
Assets
Current Assets
Cash and cash equivalents......................... $ 33,727 $ 23,329
Accounts and notes receivable, net
Trade........................................... 709,396 562,974
Related parties................................. 21,338 27,587
Inventories
Products........................................ 10,751 7,214
Materials and supplies.......................... 11,318 10,783
Gas imbalances
Trade........................................... 22,087 36,449
Related parties................................. 1,265 9,084
Gas in underground storage........................ 2,521 8,160
Other current assets.............................. 18,145 19,942
------------- -------------
830,548 705,522
------------- -------------
Property, Plant and Equipment, net................... 7,349,639 7,091,558
Investments.......................................... 405,056 404,345
Notes receivable..................................... 2,422 2,422
Goodwill............................................. 726,470 729,510
Other intangibles, net............................... 14,499 13,202
Deferred charges and other assets.................... 162,864 192,623
------------- -------------
Total Assets......................................... $ 9,491,498 $ 9,139,182
============= =============
Liabilities and Partners' Capital
Current Liabilities
Accounts payable
Trade........................................... $ 631,869 $ 477,783
Related parties................................. 2,928 -
Current portion of long-term debt................. 363,710 2,248
Accrued interest.................................. 49,820 52,356
Deferred revenues................................. 8,598 10,752
Gas imbalances.................................... 37,848 49,912
Accrued other current liabilities................. 288,907 211,328
------------- -------------
1,383,680 804,379
------------- -------------
Long-Term Liabilities and Deferred Credits
Long-term debt, outstanding....................... 3,932,614 4,316,678
Market value of interest rate swaps............... 51,979 121,464
------------- -------------
3,984,593 4,438,142
Deferred revenues................................. 17,888 20,975
Deferred income taxes............................. 38,838 38,106
Asset retirement obligations...................... 35,759 34,898
Other long-term liabilities and deferred credits.. 377,544 251,691
------------- -------------
4,454,622 4,783,812
Commitments and Contingencies (Note 3)
Minority Interest.................................... 41,501 40,064
------------- -------------
Partners' Capital
Common Units...................................... 2,138,511 1,946,116
Class B Units..................................... 118,763 120,582
i-Units........................................... 1,580,271 1,515,659
General Partner................................... 92,770 84,380
Accumulated other comprehensive loss.............. (318,620) (155,810)
-------------- --------------
3,611,695 3,510,927
Total Liabilities and Partners' Capital.............. $ 9,491,498 $ 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)
Six Months Ended June 30,
-------------------------
2004 2003
----------- -----------
Cash Flows From Operating Activities
Net income................................................................ $ 386,972 $ 339,435
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................................ 137,409 103,563
Amortization of excess cost of equity investments....................... 2,788 2,788
Earnings from equity investments........................................ (41,078) (46,923)
Distributions from equity investments..................................... 35,005 43,696
Changes in components of working capital.................................. 37,950 (55,600)
FERC rate reparations and refunds......................................... - (44,464)
Other, net................................................................ (3,240) (2,932)
----------- -----------
Net Cash Provided by Operating Activities............................... 555,806 336,098
----------- -----------
Cash Flows From Investing Activities
Acquisitions of assets.................................................... (51,679) (33,739)
Additions to property, plant and equip. for expansion and maintenance
projects.................................................................. (339,525) (273,402)
Sale of investments, property, plant and equipment, net of removal costs.. 1,452 1,258
Contributions to equity investments....................................... (3,875) (11,199)
Other..................................................................... (1,461) 7,088
----------- ----------
Net Cash Used in Investing Activities................................... (395,088) (309,994)
---------- ----------
Cash Flows From Financing Activities
Issuance of debt.......................................................... 2,744,061 2,064,865
Payment of debt........................................................... (2,767,262) (1,937,412)
Debt issue costs.......................................................... (317) (1,059)
Proceeds from issuance of common units.................................... 238,051 174,958
Proceeds from issuance of i-units......................................... 14,925 --
Contributions from General Partner........................................ 3,272 1,533
Distributions to partners:
Common units............................................................ (188,248) (164,454)
Class B units........................................................... (7,279) (6,721)
General Partner......................................................... (179,140) (150,329)
Minority interest....................................................... (4,716) (4,747)
Other, net................................................................ (3,667) 1,089
----------- ----------
Net Cash Used in Financing Activities................................... (150,320) (22,277)
----------- -----------
Increase in Cash and Cash Equivalents..................................... 10,398 3,827
Cash and Cash Equivalents, beginning of period............................ 23,329 41,088
---------- ----------
Cash and Cash Equivalents, end of period.................................. $ 33,727 $ 44,915
========== ==========
Noncash Investing and Financing Activities:
Assets acquired by the assumption of liabilities........................ $ 3,724 $ 1,905
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 six 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) 11/03 Yates Field Unit and Carbon Dioxide Assets $ 259.1 $ 3.6 $ 255.8 $ - $ (0.3)
(2) 12/03 ConocoPhillips Products Terminals......... 15.3 - 14.3 1.0 -
(3) 12/03 Tampa, Florida Bulk Terminals............. 29.7 - 29.7 - -
(4) 3/04 ExxonMobil Products Terminals............. $ 50.8 $ - $ 50.8 $ - $ -
(1) Yates Field Unit and Carbon Dioxide Assets
Effective November 1, 2003, we acquired certain assets in the Permian Basin of
West Texas from a subsidiary of Marathon Oil Corporation. Our purchase price was
approximately $259.1 million, consisting of $230.2 million in cash and the
assumption of $28.9 million of liabilities. The assets acquired consisted of the
following:
o Marathon's approximate 42.5% interest in the Yates oil field unit. We
previously owned a 7.5% ownership interest in the Yates field unit and we
now operate the field;
o Marathon's 100% interest in the crude oil gathering system surrounding the
Yates field unit; and
o Kinder Morgan Carbon Dioxide Transportation Company, formerly Marathon
Carbon Dioxide Transportation Company. Kinder Morgan Carbon Dioxide
Transportation Company owns a 65% ownership interest in the Pecos Carbon
Dioxide Pipeline Company, which owns a 25-mile carbon dioxide pipeline. We
previously owned a 4.27% ownership interest in the Pecos Carbon Dioxide
Pipeline Company and accounted for this investment under the cost method of
accounting. After the acquisition of our additional 65% interest in Pecos,
its financial results are included in our consolidated results and we
recognize the appropriate minority interest.
We recorded our final purchase price adjustments in the first six months of
2004. The adjustments finalized the value of acquired working capital items on
the acquisition date, primarily affecting product inventory balances and
property tax liabilities. We received approximately $0.8 million from Marathon
in the first six months of 2004 resulting from these purchase price adjustments.
The acquisition complemented our existing carbon dioxide assets in the Permian
Basin, increased our working interest in the Yates field to nearly 50% and
allowed us to become the operator of the field. The acquired operations are
included as part of our CO2 business segment.
(2) ConocoPhillips Products Terminals
Effective December 11, 2003, we acquired seven refined petroleum products
terminals in the southeastern United States from ConocoPhillips Company and
Phillips Pipe Line Company. Our purchase price was approximately $15.3 million,
consisting of approximately $14.1 million in cash and $1.2 million in assumed
liabilities. The terminals are located in Charlotte and Selma, North Carolina;
Augusta and Spartanburg, South Carolina; Albany and Doraville, Georgia; and
Birmingham, Alabama. We fully own and operate all of the terminals except for
the Doraville, Georgia facility, which is operated and owned 70% by Citgo. As of
our acquisition date, we expected to invest an additional $1.3 million in the
facilities. Combined, the terminals have 35 storage tanks with total capacity of
approximately 1.15 million barrels for gasoline, diesel fuel and jet fuel. As
part of the transaction, ConocoPhillips entered into a long-term contract to use
the terminals. The contract consists of a five-year terminaling agreement, an
intangible asset which we valued at $1.0 million. The acquisition 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 any minor
purchase price adjustments that we expect to complete in the third quarter of
2004.
7
(3) Tampa, Florida Bulk Terminals
In December 2003, we acquired two bulk terminal facilities in Tampa, Florida
for an aggregate consideration of approximately $29.7 million, consisting of
$26.2 million in cash (including closing and related costs of approximately $1.3
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
facility purchased was a marine terminal acquired from a subsidiary of IMC
Global, Inc. We entered into a long-term agreement with IMC pursuant to which
IMC will be the primary user of the facility, which we will operate and refer to
as the Kinder Morgan Tampaplex terminal. The terminal sits on a 114-acre site,
and serves as a storage and receipt point for imported ammonia, as well as an
export location for dry bulk products, including fertilizer and animal feed. We
closed on the Tampaplex portion of this transaction on December 23, 2003. The
second facility purchased was the former Nitram, Inc. bulk terminal, which we
plan to use as an inland bulk storage warehouse facility for overflow cargoes
from our Port Sutton, Florida import terminal. We closed on the Nitram portion
of this transaction on December 10, 2003. 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 final adjustments that may be necessary to value assumed property tax
liabilities. We expect to make our final purchase price adjustments in the third
quarter of 2004.
(4) ExxonMobil Products Terminals
Effective March 9, 2004, we acquired seven refined petroleum products
terminals in the southeastern United States from Exxon Mobil Corporation. Our
purchase price was approximately $50.8 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 at the terminals. The
acquisition enhances our terminal operations in the Southeast and complements
our December 2003 acquisition of 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 third
quarter of 2004.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement
information for the six months ended June 30, 2004 and 2003, assumes that all of
the acquisitions we have made and joint ventures we have entered into since
January 1, 2003, including the ones listed above, had occurred as of the
beginning of the period presented. We have prepared these unaudited pro forma
financial results for comparative purposes only. These unaudited pro forma
financial results may not be indicative of the results that would have occurred
if we had completed these acquisitions and joint ventures as of the beginning of
the period presented or the results that will be attained in the future. Amounts
presented below are in thousands, except for the per unit amounts:
Pro Forma
Six Months Ended June 30,
---------------------------
2004 2003
------------ ----------
(Unaudited)
Revenues............................................................ $ 3,782,355 $ 3,521,156
Operating Income.................................................... 458,492 433,132
Income Before Cumulative Effect of a Change in Accounting Principle. 388,845 366,810
Net Income.......................................................... $ 388,845 $ 370,275
Basic and Diluted Limited Partners' Net Income per unit:
Income Before Cumulative Effect of a Change in Accounting Principle $ 1.04 $ 1.15
Net Income......................................................... $ 1.04 $ 1.17
8
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 "substantially changed circumstances" with respect to those
rates and that they therefore could not be challenged in the Docket No. OR92-8
et al. proceedings, either for the past or prospectively. However, the initial
decision also made rulings generally adverse to SFPP on certain cost of service
issues relating to the evaluation of East Line rates, which are not
"grandfathered" under the Energy Policy Act. Those issues included the capital
structure to be used in computing SFPP's "starting rate base," the level of
income tax allowance SFPP may include in rates and the recovery of civil and
regulatory litigation expenses and certain pipeline reconditioning costs
incurred by SFPP. The initial decision also held SFPP's Watson Station gathering
enhancement service was subject to FERC jurisdiction and ordered SFPP to file a
tariff for that service.
The FERC subsequently reviewed the initial decision, and issued a series of
orders in which it adopted certain rulings made by the administrative law judge,
changed others and modified a number of its own rulings on rehearing. Those
orders began in January 1999, with FERC Opinion No. 435, and continued through
June 2003.
The FERC affirmed that all but one of SFPP's West Line rates are
"grandfathered" and that complainants had failed to satisfy the threshold burden
of demonstrating "substantially changed circumstances" necessary to challenge
those rates. The FERC further held that the one West Line rate that was not
grandfathered did not need to be reduced. The FERC consequently dismissed all
complaints against the West Line rates in Docket Nos. OR92-8 et al. without any
requirement that SFPP reduce, or pay any reparations for, any West Line rate.
The FERC initially modified the initial decision's ruling regarding the
capital structure to be used in computing SFPP's "starting rate base" to be more
favorable to SFPP, but later reversed that ruling. The FERC also made certain
modifications to the calculation of the income tax allowance and other cost of
service components, generally to SFPP's disadvantage.
On multiple occasions, the FERC required SFPP to file revised East Line rates
based on rulings made in the FERC's various orders. SFPP was also directed to
submit compliance filings showing the calculation of the revised rates, the
potential reparations for each complainant and in some cases potential refunds
to shippers. SFPP filed such revised East Line rates and compliance filings in
March 1999, July 2000, November 2001 (revised December 2001), October 2002 and
February 2003 (revised March 2003). Most of those filings were protested by
particular SFPP shippers. The FERC has held that certain of the rates SFPP filed
at the FERC's directive should be reduced retroactively and/or be subject to
refund; SFPP has challenged the FERC's authority to impose such requirements in
9
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. On July 20,2004, the U.S. Court of
Appeals for the District of Columbia Circuit issued an opinion affirming the
FERC orders under review on most issues, vacating the tax provision that the
FERC had allowed SFPP to include under the FERC's "Lakehead" policy giving a tax
allowance to partnership pipelines and remanding for further FERC proceedings on
other issues.
The court held that, in the context of the Docket No. OR92-8, et al.
proceedings, all of SFPP's West Line rates were grandfathered other than the
charge for use of SFPP's Watson Station gathering enhancement facility and the
rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded
that the FERC had a reasonable basis for concluding that the addition of a West
Line origin point at East Hynes, California did not involve a new "rate" for
purposes of the Energy Policy Act. It rejected arguments from West Line Shippers
that certain protests and complaints had challenged West Line rates prior to the
enactment of the Energy Policy Act.
The court also held that complainants had failed to satisfy their burden of
demonstrating substantially changed circumstances, and therefore could not
challenge grandfathered West Line rates in the Docket No. OR92-8 et al.
proceedings. It specifically rejected arguments that other shippers could
"piggyback" on the special Energy Policy Act exception permitting Navajo to
challenge grandfathered West Line rates, which Navajo had withdrawn under a
settlement with SFPP. The court remanded the changed circumstances issue "for
further consideration" by the FERC in light of the court's decision, described
below, regarding SFPP's tax allowance. The FERC has previously held in the
OR96-2 proceeding that the tax allowance policy should not be used as a
stand-alone factor in determining when there have been substantially changed
circumstances.
The court upheld the FERC's rulings on most East Line rate issues. However, it
found the FERC's reasoning inadequate on some issues, including the tax
allowance.
The court held the FERC had sufficient evidence to use SFPP's December 1988
stand-alone capital structure to calculate its starting rate base as of June
1985. It rejected SFPP arguments that would have resulted in a higher starting
rate base.
The court analyzed at length the tax allowance for pipelines that are
organized as partnerships. It concluded that the FERC had provided "no rational
basis" on the record before it for giving SFPP a tax allowance, and denied
10
recovery by SFPP of "income taxes not incurred and not paid."
The court accepted the FERC's treatment of regulatory litigation costs,
including the limitation of recoverable costs and their offset against
"unclaimed reparations" - that is, reparations that could have been awarded to
parties that did not seek them. The court also accepted the FERC's denial of any
recovery for the costs of civil litigation by East Line shippers against SFPP
based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix.
However, the court did not find adequate support for the FERC's decision to
allocate the limited litigation costs that SFPP was allowed to recover in its
rates equally between the East Line and the West Line, and ordered the FERC to
explain that decision further on remand.
The court held the FERC had failed to justify its decision to deny SFPP any
recovery of funds spent to recondition pipe on the East Line, for which SFPP had
spent nearly $6 million between 1995 and 1998. It concluded that the
Commission's reasoning was inconsistent and incomplete, and remanded for further
explanation, noting that "SFPP's shippers are presently enjoying the benefits of
what appears to be an expensive pipeline reconditioning program without sharing
in any of its costs."
The court affirmed the FERC's rulings on reparations in all respects. It held
the Arizona Grocery doctrine did not apply to orders requiring SFPP to file
"interim" rates, and that "FERC only established a final rate at the completion
of the OR92-8 proceedings." It held that the Energy Policy Act did not limit
complainants' ability to seek reparations for up to two years prior to the
filing of complaints against rates that are not grandfathered. It rejected
SFPP's arguments that the FERC should not have used a "test period" to compute
reparations, that it should have offset years in which there were
underrecoveries against those in which there were overrecoveries, and that it
should have exercised its discretion against awarding any reparations in this
case.
The court also rejected:
o Navajo's argument that its prior settlement with SFPP's predecessor did not
limit its right to seek reparations;
o Valero's argument that it should have been permitted to recover
reparations in the Docket No. OR92-8 et al. proceedings rather than
waiting to seek them, as appropriate, in the Docket No. OR96-2 et al.
proceedings;
o arguments that the former ARCO and Texaco had challenged East Line rates
when they filed a complaint in January 1994 and should therefore be entitled
to recover East Line reparations; and
o Chevron's argument that its reparations period should begin two years before
its September 1992 protest regarding the six-inch line reversal rather than
its August 1993 complaint against East Line rates.
We are currently in the process of reviewing the Court of Appeals decision and
determining what effects the rulings made in it could have on our rates and
obligation to pay additional reparations. We may seek rehearing before the Court
of Appeals and/or review by the United States Supreme Court, as well as
participate in any further proceedings before the FERC on remand.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC
(Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines (Line
Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject
to FERC's jurisdiction under the Interstate Commerce Act, and claimed that the
rate for that service was unlawful. Several other West Line shippers filed
similar complaints and/or motions to intervene.
Following a hearing in March 1997, a FERC administrative law judge issued an
initial decision holding that the movements on the Sepulveda pipelines were not
subject to FERC jurisdiction. On August 5, 1997, the FERC reversed that
decision. On October 6, 1997, SFPP filed a tariff establishing the initial
interstate rate for movements on the Sepulveda pipelines at the pre-existing
rate of five cents per barrel. Several shippers protested that rate. In December
1997, SFPP filed an application for authority to charge a market-based rate for
the Sepulveda service, which application was protested by several parties. On
September 30, 1998, the FERC issued an order finding that SFPP lacks market
power in the Watson Station destination market and set a hearing to determine
whether SFPP possessed market power in the origin market.
11
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 third 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 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. FERC and Court action on those petitions is pending.
The FERC's phase one order also held that SFPP failed to seek authorization
for the accounting entries necessary to reflect in SFPP's books, and thus in its
annual report to FERC ("FERC Form 6"), the purchase price adjustment
12
("PPA") arising from SFPP's 1998 acquisition by us. The phase one order
directed SFPP to file for permission to reflect the PPA in its FERC Form 6 for
the calendar year 1998 and each subsequent year. In its April 26, 2004
compliance filing, SFPP noted that it had previously requested such permission
and that the FERC's regulations require an oil pipeline to include a PPA in its
Form 6 without first seeking FERC permission to do so. Several parties protested
SFPP's compliance filing. SFPP answered those protests, and FERC action on this
matter is pending.
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 the second quarter of 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.
Chevron complaint OR02-4 proceedings. On February 11, 2002, Chevron, an
intervenor in the Docket No. OR96-2, et al. proceeding, filed a complaint
against SFPP in Docket No. OR02-4 along with a motion to consolidate the
complaint with the Docket No. OR96-2, et al. proceeding. On May 21, 2002, the
FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed a
request for rehearing, which the FERC dismissed on September 25, 2002. In
October 2002, Chevron filed a request for rehearing of the FERC's September 25,
2002 Order, which the FERC denied on May 23, 2003. On July 1, 2003, Chevron
filed a petition for review of this denial at the U.S. Court of Appeals for the
District of Columbia Circuit. On August 18, 2003, SFPP filed a motion to dismiss
Chevron's petition on the basis that Chevron lacks standing to bring its appeal
and that the case is not ripe for review. Chevron answered on September 10,
2003. SFPP's motion was pending, when the Court of Appeals, on December 8, 2003,
granted Chevron's motion to hold the case in abeyance pending the outcome of the
appeal of the Docket No. OR92-8, et al. proceeding. On January 8, 2004, the
Court of Appeals granted Chevron's motion to have its appeal of the FERC's
decision in Docket No. OR03-5 (see below) consolidated with Chevron's appeal of
the FERC's decision in the Docket No. OR02-4 proceeding. Chevron continues to
participate in the Docket No. OR96-2 et al. proceeding as an intervenor.
OR03-5 proceedings. On June 30, 2003, Chevron filed another complaint against
SFPP - substantially similar to its previous complaint - and moved to
consolidate the complaint with the Docket No. OR96-2, et al. proceeding. This
complaint was docketed as Docket No. OR03-5. Chevron requested that this new
complaint be treated as if it were an amendment to its complaint in Docket No.
OR02-4, which was previously dismissed by the FERC. By this request, Chevron
sought to, in effect, back-date its complaint, and claim for reparations, to
February 2002. SFPP answered Chevron's complaint on July 22, 2003, opposing
Chevron's requests for consolidation and for the back-
13
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 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.
14
SFPP believes the submission of the required, representative cost data
required by the CPUC indicates that SFPP's existing rates for California
intrastate services remain reasonable and that no refunds are justified.
We believe that the resolution of such matters will not have a material
adverse effect on our business, financial position, results of operations or
cash flows.
Trailblazer Pipeline Company
Rate Case
As required by its last rate case settlement, Trailblazer Pipeline Company
made a general rate case filing at the FERC on November 29, 2002. The filing
provides for a small rate decrease and a number of non-rate tariff changes. By
an order issued December 31, 2002, the FERC effectively bifurcated the
proceeding. The FERC accepted the rate decrease effective January 1, 2003,
subject to refund and a hearing. The FERC suspended most of the non-rate tariff
changes until June 1, 2003, subject to refund and a technical conference
procedure.
Trailblazer sought rehearing of the FERC rate decrease order with respect to
the refund condition. On April 15, 2003, the FERC granted Trailblazer's
rehearing request to remove the refund condition that had been imposed in the
FERC's December 31, 2002 order. Certain intervenors have sought rehearing as to
the FERC's acceptance of certain non-rate tariff provisions.
The technical conference on non-rate tariff issues was held on February 6,
2003. The non-rate tariff issues include:
o capacity award procedures;
o credit procedures;
o imbalance penalties; and
o the maximum length of bid terms considered for evaluation in the right of
first refusal process.
Comments on the non-rate tariff issues as discussed at the technical
conference were filed by parties in March 2003. On May 23, 2003, the FERC issued
an order deciding non-rate tariff issues and denying rehearing of its prior
order. In the May 23, 2003 order, the FERC:
o accepted Trailblazer's proposed capacity award procedures with very limited
changes;
o accepted Trailblazer's credit procedures subject to very extensive changes,
consistent with numerous recent orders involving other pipelines;
o accepted a compromise agreed to by Trailblazer and the active parties under
which existing shippers must match competing bids in the right of first
refusal process for up to ten years (in lieu of the current five years); and
o accepted Trailblazer's withdrawal of daily imbalance charges.
More specifically, the May 23, 2003 order:
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;
15
o required the pipeline to pay interest on prepayments or allow those funds
to go into an interest-bearing escrow account; and
o required much more specificity about credit criteria and procedures in
tariff provisions.
Certain shippers and Trailblazer sought rehearing of the May 23, 2003 order.
Trailblazer made its compliance filing on June 20, 2003. The tariff changes
under the May 23, 2003 order were made effective as of May 23, 2003, except that
Trailblazer filed to make the revised credit procedures effective August 15,
2003. In an order issued July 13, 2004, the FERC accepted Trailblazer's
compliance filing of June 20, 2003, but required some minor changes, and denied
the rehearing requests.
With respect to the rate review portion of the case, direct testimony was
filed by the FERC Staff and the Indicated Shippers on May 22, 2003 and
cross-answering testimony was filed by the Indicated Shippers on June 19, 2003.
Trailblazer's answering testimony was filed on July 29, 2003.
On September 22, 2003, Trailblazer filed an offer of settlement with the FERC
with respect of the rate review portion of the case. Under the settlement,
Trailblazer's rate would be reduced effective January 1, 2004, from $0.12 to
$0.09 per dekatherm of natural gas, and Trailblazer would file a new rate case
to be effective January 1, 2010.
On January 23, 2004, the FERC issued an order approving, with modification,
the settlement that was filed on September 22, 2003. The FERC modified the
settlement to expand the scope of severance of contesting parties to present and
future direct interests, including capacity release agreements. The settlement
had provided the scope of the severance to be limited to present direct
interests. On February 20, 2004, Trailblazer filed a letter with the FERC
accepting the modifications to the settlement. As of March 1, 2004, all members
of the Indicated Shippers group opposing the settlement had filed to withdraw
their opposition. On April 9, 2004, the FERC accepted tariff sheets setting out
the settlement rates and, recognizing that the settlement is now unopposed,
dismissed the pending initial decision on Trailblazer's rates as moot. The
settlement rates were put into effect January 1, 2004. On March 26, 2004,
Trailblazer refunded approximately $0.9 million to shippers covering the period
January 1, 2004 through February 29, 2004 pursuant to the terms of the rate case
settlement. On July 13, 2004, the FERC issued an order requiring Trailblazer to
refund additional amounts to shippers previously contesting the settlement.
Trailblazer issued these additional refunds, totaling approximately $73,000 on
July 23, 2004.
Fuel Tracking Filing
On March 31, 2004, Trailblazer made its annual filing to revise its fuel
tracker percentage (its fuel rate) applicable to its expansion shippers. In the
filing, Trailblazer proposed to reduce its fuel rate from the previous level of
2.0% to 1.57%. On April 12, 2004, Marathon Oil Company filed a protest stating
that Trailblazer overstated projected volumes at the Station 601 compressor
facility and proposed that the volumes at the station be reduced, which would
result in a reduction of the fuel rate to 1.20%. On April 30, 2004, the FERC
issued an order allowing Trailblazer to place its proposed 1.57% fuel rate into
effect, subject to refund, on May 1, 2004. The order also established a comment
procedure, pursuant to which Trailblazer filed comments supporting its proposal
on May 20, 2004 and Marathon filed reply comments on June 1, 2004. On July 9,
2004, the FERC issued an order adopting Marathon's position. Pursuant to the
order, Trailblazer is to file revised tariff sheets adjusting its fuel rate to
1.20% and refund to its customers with interest any amounts it over collected.
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
16
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 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
17
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
effect 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 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.
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
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exemption for local distribution companies which do not make off-system sales,
but clarified that the local distribution company exemption still applies if the
local distribution company is also a Hinshaw pipeline. The FERC also clarified
that a local distribution company can engage in certain sales and other energy
affiliate activities to the limited extent necessary to support sales to
customers located on its distribution system, and sales necessary to remain in
balance under pipeline tariffs, without becoming an energy affiliate. The FERC
declined to exempt 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.
On July 21, 2004, Trailblazer Pipeline Company and Kinder Morgan Interstate
Gas Transmission LLC filed additional requests for limited exemptions from
certain requirements of FERC Order 2004. These exemptions requested relief from
the independent functioning and information disclosure requirements of Order
2004. The exemption requests propose to treat as energy affiliates, within the
meaning of Order 2004, two groups of employees: individuals in the Choice Gas
Group within KMI's Retail operations and individuals in the Commodity sales and
purchase group within our Texas intrastate natural gas group. Order 2004
regulations governing relationships between interstate pipelines and their
energy affiliates would apply to relationships with these two groups. Under
these proposals, certain critical operating functions could continue to be
shared. We also requested an extension of time for full compliance with the
Standards of Conduct until 90 days after FERC acts on these exemption requests.
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 August 2, 2004, the FERC issued Order No. 2004-B. In this order, the
FERC extended the effective date of the new Standards of Conduct from September
1, 2004 to September 22, 2004. Also in this order, among other actions, the FERC
denied the request for rehearing made by our interstate pipelines to clarify the
applicability of the LDC and Parent Company exemptions to them. The July 21,
2004 joint request for limited exemption from certain requirements described
above remains pending at the FERC.
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. On June 22, 2004, the FERC issued an order granting an extension of time
for the filing of the quarterly financial reports for the first and second
quarters of 2004. The first quarter reports for major public utilities,
licensees and natural gas companies will be due on August 23, 2004, and the
second quarter reports will be due September 23, 2004. For non-major public
utilities, licensees, natural gas companies, and all oil pipeline companies, the
first quarter reports will be due on September 3, 2004, and the second quarter
reports will be due October 7, 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.
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Other Regulatory
In addition to the matters described above, we may face additional challenges
to our rates in the future. Shippers on our pipelines do have rights to
challenge the rates we charge under certain circumstances prescribed by
applicable regulations. There can be no assurance that we will not face
challenges to the rates we receive for services on our pipeline systems in the
future. In addition, since many of our assets are subject to regulation, we are
subject to potential future changes in applicable rules and regulations that may
have an adverse effect on our business, financial position, results of
operations or cash flows.
On July 20, 2004, the United States Court of Appeals for the District of
Columbia Circuit issued its opinion in BP West Coast Products, LLC, v. Federal
Energy Regulatory Commission, No. 99-1020, On Petitions for Review of Orders of
the Federal Energy Regulatory Commission (Circuit opinion), addressing in part
the tariffs of SFPP, L.P. Among other things, the Circuit opinion vacated the
income tax allowance portion of the FERC opinion and order allowing recovery in
SFPP's rates for income taxes and remanded this and other matters for further
proceedings consistent with the Circuit opinion. By its terms, the opinion only
pertains to SFPP, L.P. and it is based on the record in that case.
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 claims for breach of contractual duties and
covenants, breach of agency duties, civil conspiracy, and declaratory relief. In
addition to their claims for actual damages, plaintiffs seek an equitable
accounting, imposition of a constructive trust over the defendants' interests,
and punitive damages. After the trial court certified classes in both cases, the
Fort Worth Court of Appeals reversed and vacated the trial court's class
certification order in Shores because the trial court lacked jurisdiction to
certify a class. The court of appeals also ruled that most of the named
plaintiffs in Shores could not establish proper venue in Denton County and
dismissed those parties' claims. The trial court's class certification order in
Bank of Denton is currently on appeal to the Fort Worth Court of Appeals, but
the plaintiffs have filed a motion with the trial court to vacate its class
certification order, which was unopposed by the defendants. This motion was
granted in May 2004. The remaining claims in the Shores and Bank of Denton cases
are scheduled to go to trial on November 30, 2004.
On May 13, 2004, William Armor, one of the former plaintiffs in the Shores
matter whose claims were dismissed for improper venue by the Court of Appeals,
filed a new case alleging the same claims against the same defendants as he had
previously asserted in the Shores case. Armor v. Shell Oil Company, et al, No.
04-03559 (14th Judicial
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District, Dallas County Court). Defendants filed their answers and special
exceptions on June 4, 2004. Trial, if necessary, has been scheduled for
July 25, 2005.
Shell CO2 Company, Ltd., predecessor in interest to Kinder Morgan CO2 Company,
L.P., is among the named counter-claim defendants in Shell Western E&P Inc. v.
Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial District
Court, Harris County, Texas filed June 17, 1998) (the "SWEPI Action"). The
counter-claim plaintiffs are overriding royalty interest owners in the McElmo
Dome Unit and have sued for underpayment of royalties on carbon dioxide produced
from the McElmo Dome Unit. The counter-claim plaintiffs have asserted claims for
fraud/fraudulent inducement, real estate fraud, negligent misrepresentation,
breach of fiduciary duty, breach of contract, negligence, negligence per se,
unjust enrichment, violation of the Texas Securities Act, and open account.
Counter-claim plaintiffs seek actual damages, punitive damages, an accounting,
and declaratory relief. The trial court granted a series of summary judgment
motions filed by counter-claim defendants on all of plaintiffs' counter-claims
except for the fraud-based claims. The parties agreed to abate the case pending
settlement efforts. While the agreed abatement period has lapsed, no current
trial date is set.
On March 1, 2004, Bridwell Oil Company, one of the named
defendants/counter-claim plaintiffs in the SWEPI Action filed a new matter in
which it asserts claims which are virtually identical to the counterclaims it
asserts in the SWEPI Action against virtually the same parties. Bridwell Oil
Co. v. Shell Oil Co. et al, No. 160,199-B (78th Judicial District, Wichita
County Court). On June 25, 2004, defendants filed answers, special
exceptions, pleas in abatement and motions to transfer venue back to the
Harris County District Court, which motions are currently pending.
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 to
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determine issues related to the Court's subject matter jurisdiction, arising out
of the False Claims Act is complete and briefing is underway. On May 7, 2003,
Grynberg sought leave to file a Third Amended Complaint, which adds allegations
of undermeasurement related to CO2 production. Defendants have filed briefs
opposing leave to amend.
Mel R. Sweatman and Paz Gas Corporation v. Gulf Energy Marketing, LLC, et
al.
On July 25, 2002, we were served with this suit for breach of contract,
tortious interference with existing contractual relationships, conspiracy to
commit tortious interference and interference with prospective business
relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection
with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to be
shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder Morgan
Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this action
eliminated profit on Kinder Morgan Tejas, a portion of which Mr. Sweatman and
Paz Gas Corporation claim they are entitled to receive under an agreement with a
subsidiary of ours acquired in the Tejas Gas acquisition. We filed a motion to
remove the case from venue in Dewitt County, Texas to Harris County, Texas, and
our motion was denied in a venue hearing in November 2002.
In a Second Amended Original Petition, Sweatman and Paz assert new and
distinct allegations against us, principally that we were a party to an alleged
commercial bribery committed by us, Gulf Energy Marketing, and Intergen inasmuch
as we, in our role as acquirer of Kinder Morgan Tejas, allegedly paid Intergen
to not renew the underlying Entex contracts belonging to the Tejas/Paz joint
venture. Moreover, new and distinct allegations of breach of fiduciary and
bribery of a fiduciary are also raised in this amended petition for the first
time.
The parties have engaged in some discovery and depositions. At this stage of
discovery, we believe that our actions were justified and defensible under
applicable Texas law and that the decision not to renew the underlying gas sales
agreements was made unilaterally by persons acting on behalf of Entex. The
plaintiffs have moved for summary judgment asking the court to declare that a
fiduciary relationship existed for purposes of Sweatman's claims. We have moved
for summary judgment on the grounds that:
o there is no cause-in-fact of the gas sales nonrenewals attributable to
us; and
o the defense of legal justification applies to the claims for tortuous
interference.
In September 2003 and then again in November 2003, Sweatman and Paz filed
their third and fourth amended petitions, respectively, asserting all of the
claims for relief described above. In addition, the plaintiffs asked that the
court impose a constructive trust on (i) the proceeds of the sale of Tejas and
(ii) any monies received by any Kinder Morgan entity for sales of gas to any
Entex/Reliant entity following June 30, 2002 that replaced volumes of gas
previously sold under contracts to which Sweatman and Paz had a participating
interest pursuant to the joint venture agreement between Tejas, Sweatman and
Paz. In October 2003, the court granted, and then rescinded its order after a
motion to reconsider heard on February 13, 2004, a motion for partial summary
judgment on the issue of the existence of a fiduciary duty. We believe this suit
is without merit and we intend to defend the case vigorously. We have moved for
summary judgment on all of Sweatman's claims, asserting that even in the light
most favorable to Sweatman's assertions, there is no issue of material fact on
whether Sweatman even owned an interest in the underlying gas sales agreements
in dispute. That motion is presently set for hearing on August 13, 2004. Trial
of the case is set preferentially for January 17, 2005.
Maher et ux. v. Centerpoint Energy, Inc. d/b/a Reliant Energy,
Incorporated, Reliant Energy Resources Corp., Entex Gas Marketing Company,
Kinder Morgan Texas Pipeline, L.P., Kinder Morgan Energy Partners, L.P.,
Houston Pipeline Company, L.P. and AEP Gas Marketing, L.L.C., No. 30875
(District Court, Wharton County Texas).
On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan
Energy Partners, L.P. were served with the above-entitled Complaint. A First
Amended Complaint was served on October 23, 2002, adding additional
defendants Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc.,
Kinder Morgan Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. The
First Amended Complaint purports to bring a class action on behalf of those
Texas residents who purchased natural gas for residential purposes from the
so-called "Reliant Defendants" in Texas at any time during the period
encompassing "at least the last ten years."
The Complaint alleges that Reliant Energy Resources Corp., by and through its
affiliates, has artificially inflated the price charged to residential consumers
for natural gas that it allegedly purchased from the non-Reliant defendants,
including the above-listed Kinder Morgan entities. The Complaint further alleges
that in exchange for
22
Reliant Energy Resources Corp.'s purchase of natural gas at above market prices,
the non-Reliant defendants, including the above-listed Kinder Morgan entities,
sell natural gas to Entex Gas Marketing Company at prices substantially below
market, which in turn sells such natural gas to commercial and industrial
consumers and gas marketers at market price. The Complaint purports to assert
claims for fraud, violations of the Texas Deceptive Trade Practices Act, and
violations of the Texas Utility Code against some or all of the Defendants, and
civil conspiracy against all of the defendants, and seeks relief in the form of,
inter alia, actual, exemplary and statutory damages, civil penalties, interest,
attorneys' fees and a constructive trust ab initio on any and all sums which
allegedly represent overcharges by Reliant and Reliant Energy Resources Corp.
On November 18, 2002, the Kinder Morgan defendants filed a Motion to Transfer
Venue and, Subject Thereto, Original Answer to the First Amended Complaint. The
parties are currently engaged in preliminary discovery. Based on the information
available to date and our preliminary investigation, the Kinder Morgan
defendants believe that the claims against them are without merit and intend to
defend against them vigorously.
Marie Snyder, et al v. City of Fallon, United States Department of the Navy,
Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas
Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District
Court, District of Nevada)("Snyder"); 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
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the case.
On June 20, 2003, plaintiffs filed an additional Complaint for Class Action
(the "Galaz II" matter) asserting the same claims in Nevada State trial court on
behalf of the same purported class against virtually the same defendants,
including us (and excluding the United States Department of the Navy). On
September 30, 2003, the Kinder Morgan defendants filed a Motion to Dismiss the
Galaz II Complaint along with a Motion for Sanctions. On April 13, 2004,
plaintiffs' counsel voluntarily stipulated to a dismissal with prejudice of the
entire case in State Court. The Court has accepted the stipulation and the
parties are awaiting a final order from the Court dismissing the case with
prejudice.
Also on June 20, 2003, the plaintiffs in the Galaz matters filed yet another
Complaint for Class Action in the United States District Court for the District
of Nevada (the "Galaz III" matter) asserting the same claims in United States
District Court for the District of Nevada on behalf of the same purported class
against virtually the same defendants, including us. The Kinder Morgan
defendants filed a Motion to Dismiss the Galaz III matter on August 15, 2003. On
October 3, 2003, the plaintiffs filed a Motion for Withdrawal of Class Action,
which voluntarily drops the class action allegations from the matter and seeks
to have the case proceed on behalf of the Galaz family only. On December 5,
2003, the District Court granted the Kinder Morgan defendants' Motion to
Dismiss, but granted plaintiff leave to file a second Amended Complaint.
Plaintiff filed a Second Amended Complaint on December 13, 2003, and a Third
Amended Complaint on January 5, 2004. The Kinder Morgan defendants filed a
Motion to Dismiss the Third Amended Complaint on January 13, 2004. The Motion to
Dismiss was granted with prejudice on April 30, 2004. On May 7, 2004, Plaintiff
filed a Notice of Appeal in the United States Court of Appeals for the 9th
Circuit, which appeal is currently pending.
Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No.
CV03-03482 (Second Judicial District Court, State of Nevada, County of
Washoe) ("Jernee").
On May 30, 2003, a separate group of plaintiffs, individually and on behalf of
Adam Jernee, filed a civil action in the Nevada State trial court against us and
several Kinder Morgan related entities and individuals and additional unrelated
defendants ("Jernee"). Plaintiffs in the Jernee matter claim that defendants
negligently and intentionally failed to inspect, repair and replace unidentified
segments of their pipeline and facilities, allowing "harmful substances and
emissions and gases" to damage "the environment and health of human beings."
Plaintiffs claim that "Adam Jernee's death was caused by leukemia that, in turn,
is believed to be due to exposure to industrial chemicals and toxins."
Plaintiffs purport to assert claims for wrongful death, premises liability,
negligence, negligence per se, intentional infliction of emotional distress,
negligent infliction of emotional distress, assault and battery, nuisance,
fraud, strict liability, and aiding and abetting, and seek unspecified special,
general and punitive damages. The Kinder Morgan defendants filed Motions to
Dismiss the complaint on November 20, 2003, which Motions are currently pending.
In addition, plaintiffs and the defendant City of Fallon have appealed the Trial
Court's ruling on initial procedural matters concerning proper venue. On March
29, 2004, the Nevada Supreme Court stayed the action pending resolution of these
procedural matters on appeal.
Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326
(Second Judicial District Court, State of Nevada, County of Washoe) ("Sands").
On August 28, 2003, a separate group of plaintiffs, represented by the counsel
for the plaintiffs in the Jernee matter, individually and on behalf of Stephanie
Suzanne Sands, filed a civil action in the Nevada State trial court against us
and several Kinder Morgan related entities and individuals and additional
unrelated defendants ("Sands"). Plaintiffs in the Sands matter claim that
defendants negligently and intentionally failed to inspect, repair and replace
unidentified segments of their pipeline and facilities, allowing "harmful
substances and emissions and gases" to damage "the environment and health of
human beings." Plaintiffs claim that Stephanie Suzanne Sands' death was caused
by leukemia that, in turn, is believed to be due to exposure to industrial
chemicals and toxins. Plaintiffs purport to assert claims for wrongful death,
premises liability, negligence, negligence per se, intentional infliction of
emotional distress, negligent infliction of emotional distress, assault and
battery, nuisance, fraud, strict liability, and aiding and abetting, and seek
unspecified special, general and punitive damages. The Kinder Morgan defendants
were served with the Complaint on January 10, 2004. On February 26, 2004, the
Kinder Morgan defendants filed a Motion to Dismiss and a Motion to Strike, which
motions are currently pending. In addition, plaintiffs and the defendant City of
Fallon have appealed the Trial Court's ruling on initial procedural matters
concerning proper
24
venue and a peremptory challenge of the trial judge by the plaintiffs. On April
27, 2004, the Nevada Supreme Court stayed the action pending resolution of these
procedural matters on appeal.
Based on the information available to date, our own preliminary investigation,
and the positive results of investigations conducted by State and Federal
agencies, we believe that the claims against us in these matters are without
merit and intend to defend against them vigorously.
Marion County, Mississippi Litigation
In 1968, Plantation discovered a release from its 12-inch pipeline in Marion
County, Mississippi. The pipeline was immediately repaired. In 1998 and 1999, 62
lawsuits were filed on behalf of 263 plaintiffs in the Circuit Court of Marion
County, Mississippi. The majority of the claims are based on alleged exposure
from the 1968 release, including claims for property damage and personal injury.
A settlement has been reached between most of the plaintiffs and Plantation.
It is anticipated that all of the proceedings to complete the settlement will be
completed by the end of the 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 have
recently completed discovery. We intend to take depositions of several key ST
Services personnel who were involved in the transaction with GATX Terminals.
Once the depositions are complete, the parties will discuss the effectiveness of
various methods of alternative dispute resolutions in an effort to resolve the
case.
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
25
the Bushton Plant, a natural gas processing facility located in Kansas.
Plaintiff also asserts claims relating to the Helium Extraction Agreement
entered between Enron Helium Company (a division of Enron Corp.) and Mobil Oil
Corporation dated March 14, 1988. Plaintiff alleges that Defendants failed to
deliver propane and to allocate plant products to Plaintiff as required by the
Gas Processing Agreement and originally sought damages of approximately $5.9
million.
Plaintiff filed its Third Amended Petition on February 25, 2003. In its Third
Amended Petition, Plaintiff alleges claims for breach of the Gas Processing
Agreement and the Helium Extraction Agreement, requests a declaratory judgment
and asserts claims for fraud by silence/bad faith, fraudulent inducement of the
1997 Amendment to the Gas Processing Agreement, civil conspiracy, fraud, breach
of a duty of good faith and fair dealing, negligent misrepresentation and
conversion. As of April 7, 2003, Plaintiff alleged economic damages for the
period from November 1987 through March 1997 in the amount of $30.7 million. On
May 2, 2003, Plaintiff added claims for the period from April 1997 through
February 2003 in the amount of $12.9 million. On June 23, 2003, Plaintiff filed
a Fourth Amended Petition that reduced its total claim for economic damages to
$30.0 million. On October 5, 2003, Plaintiff filed a Fifth Amended Petition that
purported to add a cause of action for embezzlement. On February 10, 2004,
Plaintiff filed its Eleventh Supplemental Responses to Requests for Disclosure
that restated its alleged economic damages for the period of November 1987
through December 2003 as approximately $37.4 million. The matter went to trial
on June 21, 2004. On June 30, 2004, the jury returned a unanimous verdict in
favor of all defendants as to all counts. The Plaintiff has stated that it is
currently reviewing its appellate options.
Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions, that, to the extent an assessment of the
matter is possible, we have established an adequate reserve to cover potential
liability, and that these matters will not have a material adverse effect on our
business, financial position, results of operations or cash flows.
Proposed Office of Pipeline Safety Civil Penalty and Compliance Order
On July 15, 2004, the U.S. Department of Transportation's Office of Pipeline
Safety ("OPS") issued a Proposed Civil Penalty and Proposed Compliance Order
(the "Proposed Order") concerning alleged violations of certain federal
regulations concerning our pipeline Integrity Management Program. The violations
alleged in the Proposed Order are based upon the results of inspections of our
Integrity Management Program at our products pipelines facilities in Orange,
California and Doraville, Georgia conducted in April and June of 2003,
respectively. As a result of the alleged violations, the OPS seeks to have us
implement a number of changes to our Integrity Management Program and also seeks
to impose a proposed civil penalty of $350,000. We have already addressed a
number of the concerns identified by the OPS and intend to continue to work with
the OPS to ensure that our Integrity Management Program satisfies all applicable
regulations. However, we dispute some of the OPS findings and disagree that
civil penalties are appropriate, and therefore intend to appeal the Proposed
Order.
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:
26
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 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 June 30, 2004, ADEQ has not issued any such
administrative orders. SFPP is currently in discussions with ADEQ regarding the
investigation and remediation of the contamination resulting from the pipeline
rupture and a mutually satisfactory resolution of the Notice of Violations.
On March 30, 2004, the Texas Commission on Environmental Quality (TCEQ) issued
a Notice of Enforcement Action related to our CO2 segment's Snyder Gas Plant. We
are currently in settlement discussions with TCEQ regarding this issue.
On April 28, 2004, we discovered a spill of diesel fuel into a marsh near
Cordelia, California from a section of pipeline on our Pacific Operations.
Current estimates indicate that the size of the spill was approximately 2,000
barrels. Upon discovery of the spill and notification to regulatory agencies, a
unified response was implemented with the United States Coast Guard, the
California Department of Fish and Game, the Office of Spill Prevention and
Response 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 June 2004, we entered into discussions with the City of San Diego with
respect to impacted groundwater beneath the City's stadium property in San Diego
resulting from operations at the Mission Valley terminal facility. The City has
requested that SFPP work with the City as they seek to re-develop options for
the stadium area including future use of both groundwater aquifer and real
estate development. The City of San Diego and SFPP are working cooperatively
towards a long term plan as SFPP continues to remediate the impacted ground-
water. This site has been under the regulatory oversight and order of the
California Regional Water Quality Control Board.
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
27
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 June 30, 2004, we have recorded a total reserve for
environmental claims in the amount of $35.2 million. However, we are not able
to reasonably estimate when the eventual settlements of these claims will occur.
Other
We are a defendant in various lawsuits arising from the day-to-day operations
of our businesses. Although no assurance can be given, we believe, based on our
experiences to date, that the ultimate resolution of such items will not have a
material adverse impact on our business, financial position, results of
operations or cash flows.
4. Change in Accounting for Asset Retirement Obligations
For legal obligations associated with the retirement of long-lived assets that
result from the acquisition, construction or normal operation of a long-lived
asset, we follow the accounting and reporting provisions of Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations." We adopted SFAS No. 143 on January 1, 2003.
SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. Its primary impact on
us will be to change the method of accruing for oil production site restoration
costs related to our CO2 business segment. Prior to January 1, 2003, we
accounted for asset retirement obligations in accordance with SFAS No. 19,
"Financial Accounting and Reporting by Oil and Gas Producing Companies." Under
SFAS No. 143, the fair value of asset retirement obligations are recorded as
liabilities on a discounted basis when they are incurred, which is typically at
the time the assets are installed or acquired. Amounts recorded for the related
assets are increased by the amount of these obligations. Over time, the
liabilities will be accreted for the change in their present value and the
initial capitalized costs will be depreciated over the useful lives 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 June 30, 2004, we have recognized asset
28
retirement obligations in the aggregate amount of $33.9 million relating to
these requirements at existing sites within our CO2 business segment.
In our Natural Gas Pipelines business segment, if we were to cease providing
utility services, we would be required to remove surface facilities from land
belonging to our customers and others. Our Texas intrastate natural gas pipeline
group has various condensate drip tanks and separators located throughout its
natural gas pipeline systems, as well as inactive gas processing plants,
laterals and gathering systems which are no longer integral to the overall
mainline transmission systems, and asbestos-coated underground pipe which is
being abandoned and retired. Our Kinder Morgan Interstate Gas Transmission
system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of June 30, 2004, we have recognized asset
retirement obligations in the aggregate amount of $2.7 million relating to the
businesses within our Natural Gas Pipelines business segment.
We have included $0.8 million of our total $36.6 million asset retirement
obligations as of June 30, 2004 with "Accrued other current liabilities" in our
accompanying consolidated balance sheet. The remaining $35.8 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 six months ended June 30, 2004 and
2003 is as follows (in thousands):
Six Months Ended June 30,
---------------------------
2004 2003
---------- ---------
Balance at beginning of period................ $ 35,708 $ -
Initial ARO balance upon adoption............. - 14,125
Liabilities incurred.......................... 130 2,208
Liabilities settled........................... (307) (318)
Accretion expense............................. 1,038 420
Revisions in estimated cash flows............. - 208
---------- ----------
Balance at end of period...................... $ 36,569 $ 16,643
========== ==========
5. Distributions
On May 14, 2004, we paid a cash distribution of $0.69 per unit to our common
unitholders and to our Class B unitholders for the quarterly period ended March
31, 2004. KMR, our sole i-unitholder, received 872,958 additional i-units based
on the $0.69 cash distribution per common unit. The distributions were declared
on April 21, 2004, payable to unitholders of record as of April 30, 2004.
On July 21, 2004, we declared a cash distribution of $0.71 per unit for the
quarterly period ended June 30, 2004. The distribution will be paid on or before
August 13, 2004, to unitholders of record as of July 31, 2004. Our common
unitholders and Class B unitholders will receive cash. KMR will receive a
distribution in the form of additional i-units based on the $0.71 distribution
per common unit. The number of i-units distributed will be 920,140. For each
outstanding i-unit that KMR holds, a fraction of an i-unit (0.018039) will be
issued. The fraction was determined by dividing:
o $0.71, the cash amount distributed per common unit
by
o $39.36, the average of KMR's limited liability shares' closing market prices
from July 14-27, 2004, the ten consecutive trading days preceding the date
on which the shares began to trade ex-dividend under the rules of the New
York Stock Exchange.
29
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):
June 30, December 31,
---------- -------------
2004 2003
Goodwill
Gross carrying amount...... $ 740,612 $ 743,652
Accumulated amortization... (14,142) (14,142)
--------- -----------
Net carrying amount........ 726,470 729,510
--------- -----------
Lease value
Gross carrying amount...... 6,592 6,592
Accumulated amortization... (958) (888)
--------- -----------
Net carrying amount........ 5,634 5,704
--------- -----------
Contracts and other
Gross carrying amount...... 9,498 7,801
Accumulated amortization... (633) (303)
--------- -----------
Net carrying amount........ 8,865 7,498
--------- -----------
Total intangibles, net..... $ 740,969 $ 742,712
========= ===========
Changes in the carrying amount of goodwill for the six months ended June 30,
2004 are summarized as follows (in thousands):
Products Natural Gas
Pipelines Pipelines CO2 Terminals Total
----------- ----------- --- --------- -----
Balance as of December 31, 2003 $ 263,182 $ 253,358 $ 46,101 $ 166,869 $ 729,510
Acquisitions - - - - -
Disposals - purchase price adjs. - (3,040) - - (3,040)
Impairment losses - - - - -
----------- ----------- ----------- ----------- -----------
Balance as of June30, 2004 $ 263,182 $ 250,318 $ 46,101 $ 166,869 $ 726,470
=========== =========== =========== =========== ===========
Amortization expense on our intangibles consisted of the following (in
thousands):
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- ---------------------------
2004 2003 2004 2003
------------ ------------ ------------ ----------
Lease value............ $ 34 $ 35 $ 70 $ 70
Contracts and other.... 205 16 330 31
------------ ------------ ------------ ------------
Total amortization..... $ 239 $ 51 $ 400 $ 101
============ ============ ============ ============
As of June 30, 2004, our weighted average amortization period for our
intangible assets was approximately 25.2 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 June 30, 2004 and December 31, 2003, we have
reported $150.3 million in equity method goodwill within the caption
"Investments" in our accompanying consolidated balance sheets.
30
7. Debt
Our outstanding short-term debt as of June 30, 2004 was $691.8 million. The
balance primarily consisted of $487.5 million of commercial paper borrowings and
$200 million of 8.0% senior notes due March 15, 2005. As of June 30, 2004, we
intend and have the ability to refinance $328.1 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
4.742% during the second quarter of 2004 and 4.523% during the second quarter of
2003.
Credit Facilities
As of June 30, 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 June 30, 2004.
The amount available for borrowing under our credit facilities as of June 30,
2004 is reduced by:
o a $100 million letter of credit entered into on June 30, 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.
In August 2004, we intend to replace our existing bank facilities with a $1.25
billion five-year revolving credit facility. This new credit facility, if
completed as expected, will include covenants and require payment of facility
fees that are similar in nature to the covenants and facility fees required by
our current bank facilities as discussed in our Annual Report on Form 10-K for
the year ended December 31, 2003.
Interest Rate Swaps
Information on our interest rate swaps is contained in Note 10.
Commercial Paper Program
As of both December 31, 2003 and June 30, 2004, our commercial paper program
provided for the issuance of up to $1.05 billion of commercial paper. As of June
30, 2004, we had $487.5 million of commercial paper outstanding with an average
interest rate of 1.2058%. Borrowings under our commercial paper program reduce
the borrowings allowed under our credit facilities.
31
Kinder Morgan Liquids Terminals LLC Debt
Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC.
As part of our purchase price, we assumed debt of $87.9 million, consisting of
five series of tax-exempt industrial revenue bonds. Kinder Morgan Liquids
Terminals LLC was the obligor on the bonds, which consisted of the following:
o $4.1 million of 7.30% New Jersey industrial revenue bonds due September 1,
2019;
o $59.5 million of 6.95% Texas industrial revenue bonds due February 1, 2022;
o $7.4 million of 6.65% New Jersey industrial revenue bonds due September
1, 2022;
o $13.3 million of 7.00% Louisiana industrial revenue bonds due March 1,
2023; and
o $3.6 million of 6.625% Texas industrial revenue bonds due February 1, 2024.
In May 2004, we exercised our right to call and retire all of the industrial
revenue bonds (other than the $3.6 million of 6.625% bonds due February 1, 2024)
prior to maturity at a redemption price of $84.3 million, plus approximately
$1.9 million for interest, prepayment premiums and redemption fees. We borrowed
the necessary funds under our commercial paper program. Pursuant to Accounting
Principles Board Opinion No. 26, "Early Extinguishment of Debt," we recognized
the $1.4 million excess of our reacquisition price over both the carrying value
of the bonds and unamortized debt issuance costs as a loss on bond repurchases
and we included this amount under the caption "Other, net" in our accompanying
Consolidated Statements of Income.
Contingent Debt
We apply the disclosure provisions of FASB Interpretation (FIN) No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" to our agreements that contain
guarantee or indemnification clauses. These disclosure provisions expand those
required by FASB No. 5, "Accounting for Contingencies," by requiring a guarantor
to disclose certain types of guarantees, even if the likelihood of requiring the
guarantor's performance is remote. The following is a description of our
contingent debt agreements.
Cortez Pipeline Company Debt
Pursuant to a certain Throughput and Deficiency Agreement, the owners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a
subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers Pipeline
Company - 13% owner) are required, on a several, percentage ownership basis, to
contribute capital to Cortez Pipeline Company in the event of a cash deficiency.
The Throughput and Deficiency Agreement contractually supports the borrowings of
Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline
Company, by obligating the owners of Cortez Pipeline Company to fund cash
deficiencies at Cortez Pipeline Company, including cash deficiencies relating to
the repayment of principal and interest on borrowings by Cortez Capital
Corporation. Parent companies of the respective Cortez Pipeline Company owners
further severally guarantee, on a percentage basis, the obligations of the
Cortez Pipeline Company owners under the Throughput and Deficiency Agreement.
Due to our indirect ownership of Cortez Pipeline Company through Kinder Morgan
CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez Capital
Corporation. Shell Oil Company shares our several guaranty obligations jointly
and severally through December 31, 2006 for Cortez Capital Corporation's debt
programs in place as of April 1, 2000.
As of June 30, 2004, the debt facilities of Cortez Capital Corporation
consisted of:
o $85 million of Series D notes due May 15, 2013;
o a $175 million short-term commercial paper program; and
32
o a $175 million committed revolving credit facility due December 22, 2004 (to
support the above-mentioned $175 million commercial paper program).
As of June 30, 2004, Cortez Capital Corporation had $126.8 million of
commercial paper outstanding with an average interest rate of 1.1389%, the
average interest rate on the Series D notes was 7.0835% and there were no
borrowings under the credit facility.
Plantation Pipe Line Company Debt
On April 30, 1997, Plantation Pipe Line Company entered into a $10 million,
ten-year floating-rate term credit agreement. We, as an owner of Plantation Pipe
Line Company, severally guarantee this debt on a pro rata basis equivalent to
our respective 51.17% ownership interest. During 1999, this agreement was
amended to reduce the maturity date by three years. In April 2004, we extended
the maturity to July 20, 2004.
On July 20, 2004, Plantation paid the $10 million note outstanding and the
$150.2 million outstanding under its commercial paper program with funds of $190
million borrowed from its owners. We funded $97.2 million, which corresponds to
our 51.17% ownership interest in Plantation, in exchange for a seven year note
receivable bearing interest at the rate of 4.72% per annum. The note provides
for semiannual payments of principal and interest on December 31 and June 30
each year beginning on December 31, 2004 based on a 25 year amortization
schedule, with a final principal payment of $156.6 million due July 20, 2011. We
funded our advance of $97.2 million with borrowings under our commercial paper
program. ExxonMobil owns the remaining approximate 49% interest in Plantation
and funded the remaining $92.8 million on similar terms.
Red Cedar Gas Gathering Company Debt
In October 1998, Red Cedar Gas Gathering Company sold $55 million in aggregate
principal amount of Senior Notes due October 31, 2010. The $55 million was sold
in 10 different notes in varying amounts with identical terms.
The Senior Notes are collateralized by a first priority lien on the ownership
interests, including our 49% ownership interest, in Red Cedar Gas Gathering
Company. The Senior Notes are also guaranteed by us and the other owner of Red
Cedar Gas Gathering Company under joint and several liability. The principal is
to be repaid in seven equal installments beginning on October 31, 2004 and
ending on October 31, 2010. The $55 million was outstanding as of June 30, 2004.
Nassau County, Florida Ocean Highway and Port Authority Debt
Nassau County, Florida Ocean Highway and Port Authority is a political
subdivision of the State of Florida. During 1990, Ocean Highway and Port
Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal
amount of $38.5 million for the purpose of constructing certain port
improvements located in Fernandino Beach, Nassau County, Florida. A letter of
credit was issued as security for the Adjustable Demand Revenue Bonds and was
guaranteed by the parent company of Nassau Terminals LLC, the operator of the
port facilities. In July 2002, we acquired Nassau Terminals LLC and became
guarantor under the letter of credit agreement. In December 2002, we issued a
$28 million letter of credit under our credit facilities and the former letter
of credit guarantee was terminated. As of June 30, 2004, this letter of credit
was still outstanding under our credit facilities.
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
June 30, 2004. KMI would be obligated to perform under this guarantee only if we
and/or our assets were unable to satisfy our obligations.
33
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 June 30, 2004 and December 31, 2003, our partners' capital consisted of
the following limited partner units:
June 30, December 31,
--------------- --------------
2004 2003
--------------- --------------
Common units.................. 140,039,908 134,729,258
Class B units................. 5,313,400 5,313,400
i-units....................... 51,008,396 48,996,465
------------ ------------
Total limited partner units. 196,361,704 189,039,123
============ ============
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 June 30, 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 June 30, 2004, and December 31, 2003, our
Class B units were held entirely by KMI and our i-units were held entirely by
KMR.
In February 2004, we issued, in a public offering, 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 will issue an equivalent
amount of i-units to KMR based on the number of i-units it owns.
Based on the preceding,
34
KMR received a distribution of 872,958 i-units on May 14, 2004. These additional
i-units distributed were based on the $0.69 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 $0.69 per unit paid on May 14, 2004 for the
first quarter of 2004 required an incentive distribution to our general partner
of $90.7 million. Our distribution of $0.64 per unit paid on May 15, 2003 for
the first quarter of 2003 required an incentive distribution to our general
partner of $75.5 million. The increased incentive distribution to our general
partner paid for the first quarter of 2004 over the distribution paid for the
first 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 second quarter of 2004 of $0.71 per unit
will result in an incentive distribution to our general partner of approximately
$94.9 million. This compares to our distribution of $0.65 per unit and incentive
distribution to our general partner of approximately $79.6 million for the
second quarter of 2003.
9. Comprehensive Income
SFAS No. 130, "Accounting for Comprehensive Income," requires that enterprises
report a total for comprehensive income. For each of the three months and six
months ended June 30, 2004 and 2003, the only difference between our net income
and our comprehensive income was the unrealized gain or loss on derivatives
utilized for hedging purposes. For more information on our hedging activities,
see Note 10. Our total comprehensive income is as follows (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ---------------------
2004 2003 2004 2003
------------ ----------- ----------- ----------
Net income.................................................... $ 195,218 $ 168,957 $ 386,972 $ 339,435
Change in fair value of derivatives used for hedging purposes. (136,012) (19,304) (236,022) (73,174)
Reclassification of change in fair value of derivatives to
net income.................................................... 47,096 817 73,212 51,248
------------ ----------- ----------- -----------
Comprehensive income........................................ $ 106,302 $ 150,470 $ 224,162 $ 317,509
============ ========== =========== ===========
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 as a hedging mechanism against price volatility associated with:
35
o pre-existing or anticipated physical natural gas, natural gas liquids and
crude oil sales;
o pre-existing or anticipated physical carbon dioxide sales that have
pricing tied to crude oil prices;
o natural gas purchases; and
o system use and storage.
Our risk management activities are primarily used in order to protect our
profit margins and our risk management policies prohibit us from engaging in
speculative trading. Commodity-related activities of our risk management group
are monitored by our Risk Management Committee, which is charged with the review
and enforcement of our management's risk management policy.
Certain of our business activities expose us to foreign currency fluctuations.
However, due to the limited size of this exposure, we do not believe the risks
associated with changes in foreign currency will have a material adverse effect
on our business, financial position, results of operations or cash flows.
Our derivatives hedge the commodity price risks derived from our normal
business activities, which include the sale of natural gas, natural gas liquids,
oil and carbon dioxide, and these derivatives have been designated by us as cash
flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that
hedge exposure to variable cash flows of forecasted transactions as cash flow
hedges and the effective portion of the derivative's gain or loss is initially
reported as a component of other comprehensive income (outside earnings) and
subsequently is reclassified into earnings when the forecasted transaction
affects earnings. 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 our
accompanying Consolidated Balance Sheets are reclassified into earnings as the
hedged sales and purchases take place. Approximately $133.3 million of the
Accumulated other comprehensive loss balance of $318.6 million representing
unrecognized net losses on derivative activities as of June 30, 2004 is expected
to be reclassified into earnings during the next twelve months. During the six
months ended June 30, 2004, we reclassified $73.2 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 each of the six months ended June 30, 2004 and 2003, 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 would no longer
occur by the end of the originally specified time period.
We recognized no gain or loss during the second quarter or the first six
months of 2004 as a result of ineffective hedges. However, we recognized a gain
of $0.2 million during the second quarter of 2003 and a gain of $0.4 million
during the first six months of 2003 as a result of hedge ineffectiveness. All of
these amounts were reported within the captions "Gas purchases and other costs
of sales" in our accompanying Consolidated Statements of Income. For each of the
six months ended June 30, 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
accompanying Consolidated Balance Sheets as of June 30, 2004 and December 31,
2003 (in thousands):
36
June 30, December 31,
------------ -------------
2004 2003
------------ -------------
Derivatives-net asset/(liability)
Other current assets...................... $ 12,154 $ 18,157
Deferred charges and other assets......... 13,243 2,722
Accrued other liabilities................. (151,380) (90,426)
Other long-term liabilities and deferred
credits................................... $ (205,567) $ (101,463)
On June 30 2004, we renewed a 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. The former $50 million letter of credit expired
on June 30, 2004. The amount of the new letter of credit was increased from $50
million to $100 million and will expire on December 31, 2004.
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 June 30, 2004 and
December 31, 2003 we were essentially in a net payable position and had
virtually no amounts owed to us from other parties. In addition, defaults by
counterparties under over-the-counter swaps and options could expose us to
additional commodity price risks in the event that we are unable to enter into
replacement contracts for such swaps and options on substantially the same
terms. Alternatively, we may need to pay significant amounts to the new
counterparties to induce them to enter into replacement swaps and options on
substantially the same terms. While we enter into derivative transactions
principally with investment grade counterparties and actively monitor their
credit ratings, it is nevertheless possible that from time to time losses will
result from counterparty credit risk in the future.
Interest Rate Swaps
In order to maintain a cost effective capital structure, it is our policy to
borrow funds using a mix of fixed rate debt and variable rate debt. As of both
June 30, 2004 and December 31, 2003, we were a party to interest rate swap
agreements with a notional principal amount of $2.1 billion for the purpose of
hedging the interest rate risk associated with our fixed and variable rate debt
obligations.
As of June 30, 2004, a notional principal amount of $2.0 billion of these
agreements effectively converts the interest expense associated with the
following series of our senior notes from fixed rates to variable rates based on
an interest rate of LIBOR plus a spread:
o $200 million principal amount of our 8.0% senior notes due March 15, 2005;
o $200 million principal amount of our 5.35% senior notes due August 15,
2007;
o $250 million principal amount of our 6.30% senior notes due February 1,
2009;
o $200 million principal amount of our 7.125% senior notes due March 15,
2012;
o $250 million principal amount of our 5.0% senior notes due December 15,
2013;
o $300 million principal amount of our 7.40% senior notes due March 15,
2031;
o $200 million principal amount of our 7.75% senior notes due March 15,
2032; and
o $400 million principal amount of our 7.30% senior notes due August 15, 2033.
These swap agreements have termination dates that correspond to the maturity
dates of the related series of senior notes, therefore, as of June 30, 2004, the
maximum length of time over which we have hedged a portion of our exposure to
the variability in future cash flows associated with interest rate risk is
through August 15, 2033.
The swap agreements related to our 7.40% senior notes contain mutual cash-out
provisions at the then-current economic value every seven years. The swap
agreements related to our 7.125% senior notes contain cash-out
37
provisions at the then-current economic value at March 15, 2009. The swap
agreements related to our 7.75% senior notes and our 7.30% senior notes contain
mutual cash-out provisions at the then-current economic value every five years.
These interest rate swaps have been designated as fair value hedges as
defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge a
recognized asset or liability's exposure to changes in their fair value as fair
value hedges and the gain or loss on fair value hedges are to be recognized in
earnings in the period of change together with the offsetting loss or gain on
the hedged item attributable to the risk being hedged. The effect of that
accounting is to reflect in earnings the extent to which the hedge is not
effective in achieving offsetting changes in fair value.
As of June 30, 2004, we also had swap agreements that effectively convert the
interest expense associated with $100 million of our variable rate debt to fixed
rate debt. Half of these agreements, converting $50 million of our variable rate
debt to fixed rate debt, mature on August 1, 2005, and the remaining half mature
on September 1, 2005. These swaps are designated as a cash flow hedge of the
risk associated with changes in the designated benchmark interest rate (in this
case, one-month LIBOR) related to forecasted payments associated with interest
on an aggregate of $100 million of our portfolio of commercial paper.
Our interest rate swaps meet the conditions required to assume no
ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed for fair value hedges by SFAS No. 133.
Accordingly, we adjust the carrying value of each swap to its fair value each
quarter, with an offsetting entry to adjust the carrying value of the debt
securities whose fair value is being hedged. We record interest expense equal to
the variable rate payments or fixed rate payments under the swaps. Interest
expense is accrued monthly and paid semi-annually.
The differences between fair value and the original carrying value associated
with our interest rate swap agreements are included within "Deferred charges and
other assets" and "Other long-term liabilities and deferred credits" in our
accompanying Consolidated Balance Sheets. The offsetting entry to adjust the
carrying value of the debt securities whose fair value was being hedged is
recognized as "Market value of interest rate swaps" on our accompanying
Consolidated Balance Sheets.
The following table summarizes the net fair value of our interest rate swap
agreements associated with our interest rate risk management activities and
included on our accompanying Consolidated Balance Sheets as of June 30, 2004 and
December 31, 2003 (in thousands):
June 30, December 31,
------------ -------------
2004 2003
------------ -------------
Derivatives-net asset/(liability)
Deferred charges and other assets......... $ 80,187 $ 129,619
Other long-term liabilities and deferred
credits................................... (28,208) (8,154)
Market value of interest rate swaps..... $ 51,979 $ 121,465
============= ============
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
38
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.
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 June 30, Six Months Ended June 30,
------------------------------ -----------------------------
2004 2003 2004 2003
-------------- -------------- -------------- ------------
Revenues
Products Pipelines................................. $ 159,464 $ 145,284 $ 314,320 $ 289,701
Natural Gas Pipelines.............................. 1,554,831 1,341,160 2,992,739 2,822,114
CO2................................................ 110,572 54,631 216,158 103,087
Terminals.......................................... 132,315 123,372 256,221 238,383
------------- ------------- ------------- -------------
Total consolidated revenues........................ $ 1,957,182 $ 1,664,447 $ 3,779,438 $ 3,453,285
============= ============= ============= =============
Operating expenses (a)
Products Pipelines................................. $ 46,425 $ 40,480 $ 89,303 $ 81,666
Natural Gas Pipelines.............................. 1,463,867 1,258,224 2,803,827 2,653,756
CO2................................................ 41,904 16,290 80,289 32,803
Terminals.......................................... 64,287 60,619 124,393 115,057
------------- ------------- ------------- -------------
Total consolidated operating expenses.............. $ 1,616,483 $ 1,375,613 $ 3,097,812 $ 2,883,282
============= ============= ============= =============
Depreciation, depletion and amortization
Products Pipelines................................. $ 17,384 $ 16,723 $ 34,800 $ 33,283
Natural Gas Pipelines.............................. 12,926 13,603 25,768 26,229
CO2................................................ 29,130 14,281 56,118 26,043
Terminals.......................................... 10,438 8,980 20,723 18,008
------------- ------------- ------------- -------------
Total consolidated depreciation and amortization... $ 69,878 $ 53,587 $ 137,409 $ 103,563
============= ============= ============= =============
39
Three Months Ended June 30, Six Months Ended June 30,
------------------------------ -----------------------------
2004 2003 2004 2003
-------------- -------------- -------------- ------------
Earnings from equity investments
Products Pipelines................................. $ 8,933 $ 7,587 $ 13,952 $ 15,630
Natural Gas Pipelines.............................. 4,311 6,159 9,278 12,383
CO2................................................ 7,362 8,864 17,841 18,870
Terminals.......................................... 3 8 7 40
------------- ------------- ------------- -------------
Total consolidated equity earnings................. $ 20,609 $ 22,618 $ 41,078 $ 46,923
============= ============= ============= =============
Amortization of excess cost of equity investments
Products Pipelines................................. $ 821 $ 821 $ 1,642 $ 1,642
Natural Gas Pipelines.............................. 69 69 138 138
CO2................................................ 504 504 1,008 1,008
Terminals.......................................... - - - -
------------- ------------- ------------- -------------
Total consol. amortization of excess cost of invests $ 1,394 $ 1,394 $ 2,788 $ 2,788
============= ============= ============= =============
Other, net - income (expense)
Products Pipelines................................. $ 1,127 $ 1,285 $ 765 $ 1,510
Natural Gas Pipelines.............................. (4) 502 1,126 525
CO2................................................ 23 (12) 32 5
Terminals.......................................... (211) (267) (245) (255)
------------- ------------- ------------- -------------
Total segment other, net - income (expense)........ 935 1,508 1,678 1,785
Loss from early extinguishment of debt............. (1,424) - (1,424) -
------------- ------------- ------------- -------------
Total consolidated other, net - income (expense)... $ (489) $ 1,508 $ 254 $ 1,785
============= ============= ============= =============
Income tax benefit (expense)
Products Pipelines................................. $ (3,803) $ (3,141) $ (6,184) $ (5,966)
Natural Gas Pipelines.............................. 167 (725) (773) (833)
CO2................................................ (61) (20) (47) (20)
Terminals.......................................... (2,121) (2,430) (2,718) (3,685)
------------- ------------- ------------- -------------
Total consolidated income tax benefit (expense).... $ (5,818) $ (6,316) $ (9,722) $ (10,504)
============= ============= ============= =============
Segment earnings
Products Pipelines................................. $ 101,091 $ 92,991 $ 197,108 $ 184,284
Natural Gas Pipelines.............................. 82,443 75,200 172,637 154,066
CO2................................................ 46,358 32,388 96,569 62,088
Terminals.......................................... 55,261 51,084 108,149 101,418
------------- ------------- ------------- -------------
Total segment earnings(b).......................... 285,153 251,663 574,463 501,856
Interest and corporate administrative expenses (c). (89,935) (82,706) (187,491) (162,421)
------------- ------------- ------------- -------------
Total consolidated net income...................... $ 195,218 $ 168,957 $ 386,972 $ 339,435
============= ============= ============= =============
Segment earnings before depreciation, depletion and
amortization expense and amortization of excess cost
of equity investments
Products Pipelines................................. $ 119,296 $ 110,535 $ 233,550 $ 219,209
Natural Gas Pipelines.............................. 95,438 88,872 198,543 180,433
CO2................................................ 75,992 47,173 153,695 89,139
Terminals.......................................... 65,699 60,064 128,872 119,426
------------- ------------- ------------- -------------
Total segment earnings before DD&A (d)............. 356,425 306,644 714,660 608,207
Total consolidated depreciation, depletion and
amortiz............................................ (69,878) (53,587) (137,409) (103,563)
Total consol. amortization of excess cost of invests (1,394) (1,394) (2,788) (2,788)
Interest and corporate administrative expenses..... (89,935) (82,706) (187,491) (162,421)
------------- ------------- ------------- -------------
Total consolidated net income ..................... $ 195,218 $ 168,957 $ 386,972 $ 339,435
============= ============= ============= =============
June 30, December 31,
------------ -------------
2004 2003
Assets
Products Pipelines.................... $ 3,296,432 $ 3,198,107
Natural Gas Pipelines................. 3,375,572 3,253,792
CO2................................... 1,312,495 1,177,645
Terminals............................. 1,428,522 1,368,279
------------- --------------
Total segment assets.................. 9,413,021 8,997,823
Corporate assets(e)................... 78,477 141,359
------------- --------------
Total consolidated assets............. $ 9,491,498 $ 9,139,182
============= ==============
40
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
(b) Includes revenues, earnings from equity investments, income taxes and other,
net, less operating expenses, depreciation, depletion and amortization, and
amortization of excess cost of equity investments.
(c) Includes interest and debt expense, general and administrative expenses,
minority interest expense, loss from early extinguishment of debt (2004
only) and cumulative effect adjustment from a change in accounting principle
(2003 only).
(d) Includes revenues, earnings from equity investments, income taxes and other,
net, less operating expenses.
(e) Includes cash, cash equivalents and certain unallocable deferred charges.
12. Pensions and Other Post-retirement Benefits
In connection with our 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):
Other Post-retirement Benefits
-------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
------------------------------ ----------------------------
2004 2003 2004 2003
-------------- -------------- -------------- -----------
Net periodic benefit cost
Service cost...................... $ 28 $ 11 $ 56 $ 21
Interest cost..................... 97 201 194 403
Expected return on plan assets.... -- -- -- --
Amortization of prior service (31) (156) (62) (311)
cost..............................
Actuarial gain.................... (244) - (488) -
------- ------ ------- ------
Net periodic benefit
cost/(benefit).................... $ (150) $ 56 $ (300) $ 113
======= ====== ======= ======
Periodic benefit impact has been a benefit during 2004 largely due to the
amortization of an actuarial gain in the amount of $244,000 in each of the first
two quarters of 2004, 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 June 30, 2004, we estimate our overall net periodic postretirement
benefit cost to be an annual credit of approximately $600,000, or $150,000 per
quarter. These numbers could change in the remaining months 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 June 30, 2004, we have contributed
approximately $150,000 and we presently anticipate contributing an additional
$150,000 in the remaining months of 2004 for a total of $300,000.
13. Related Party Transactions
In June 2004, we bought two LM6000 gas-fired turbines and two boilers from
KMI for their estimated fair market value of $21.1 million, which we paid in
cash. This equipment was a portion of the equipment that became surplus as a
result of KMI's decision to exit the power development business.
14. New Accounting Pronouncements
FIN 46 (revised December 2003)
In December 2003, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 46 (revised December 2003), "Consolidation of
Variable Interest Entities." This interpretation of Accounting Research
Bulletin No. 51, "Consolidated Financial Statements," addresses consolidation
by business enterprises of variable interest
41
entities, which have one or more of the following characteristics:
o the equity investment at risk is not sufficient to permit the entity to
finance its activities without additional subordinated financial support
provided by any parties, including the equity holders;
o the equity investors lack one or more of the following essential
characteristics of a controlling financial interest:
o the direct or indirect ability to make decisions about the entity's
activities thorough voting rights or similar rights;
o the obligation to absorb the expected losses of the entity; and
o the right to receive the expected residual returns of the entity; and
o the equity investors have voting rights that are not proportionate to their
economic interests, and the activities of the entity involve or are
conducted on behalf of an investor with a disproportionately small voting
interest.
The objective of this Interpretation is not to restrict the use of variable
interest entities but to improve financial reporting by enterprises involved
with variable interest entities. The FASB believes that if a business enterprise
has a controlling financial interest in a variable interest entity, the assets,
liabilities, and results of the activities of the variable interest entity
should be included in consolidated financial statements with those of the
business enterprise.
This Interpretation explains how to identify variable interest entities and
how an enterprise assesses its interests in a variable interest entity to decide
whether to consolidate that entity. It requires existing unconsolidated variable
interest entities to be consolidated by their primary beneficiaries if the
entities do not effectively disperse risks among parties involved. Variable
interest entities that effectively disperse risks will not be consolidated
unless a single party holds an interest or combination of interests that
effectively recombines risks that were previously dispersed.
An enterprise that consolidates a variable interest entity is the primary
beneficiary of the variable interest entity. The primary beneficiary of a
variable interest entity is the party that absorbs a majority of the entity's
expected losses, receives a majority of its expected residual returns, or both,
as a result of holding variable interests, which are the ownership, contractual,
or other monetary interests in an entity that change with changes in the fair
value of the entity's net assets excluding variable interests. The primary
beneficiary of a variable interest entity is required to disclose:
o the nature, purpose, size and activities of the variable interest entity;
o the carrying amount and classification of consolidated assets that are
collateral for the variable interest entity's obligations; and
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
42
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.
EITF 03-06
In March 2004, the Emerging Issues Task Force issued Statement No. 03-06,
or EITF 03-06, "Participating Securities and the Two-Class Method under
Financial Accounting Standards Board Statement No. 128. Earnings Per Share."
EITF 03-06 addresses a number of questions regarding the computation of earnings
per share by companies that have issued securities other than common stock that
contractually entitle the holder to participate in dividends and earnings of the
company when, and if, it declares dividends on its common stock. The issue also
provides further guidance in applying the two-class method of calculating
earnings per share, clarifying what constitutes a participating security and how
to apply the two-class method of computing earnings per share once it is
determined that a security is participating, including how to allocate
undistributed earnings to such a security. EITF 03-06 was effective for fiscal
periods beginning after March 31, 2004. The adoption of EITF 03-06 did not
result in a change in our earnings per unit for any of the periods presented
and prior periods.
43
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
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 and should be read in conjunction with our Consolidated Financial Statements.
These financial statements are included elsewhere in this report and were
prepared in accordance with accounting principles generally accepted in the
United States of America.
Critical Accounting Policies and Estimates
Certain amounts included in or affecting our Consolidated Financial Statements
and related disclosures must be estimated, requiring us to make certain
assumptions with respect to values or conditions that cannot be known with
certainty at the time the financial statements are prepared. These estimates and
assumptions affect the amounts we report for assets and liabilities and our
disclosure of contingent assets and liabilities at the date of the financial
statements. We evaluate these estimates on an ongoing basis, utilizing
historical experience, consultation with experts and other methods we consider
reasonable in the particular circumstances. Nevertheless, actual results may
differ significantly from our estimates. Any effects on our business, financial
position or results of operations resulting from revisions to these estimates
are recorded in the period in which the facts that give rise to the revision
become known.
In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, the fair
values used to determine possible asset impairment charges, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. Further information about us
and information regarding our accounting policies and estimates that we
considered to be "critical" can be found in our Annual Report on Form 10-K for
the year ended December 31, 2003. There have not been any significant changes in
these policies and estimates during the first six months of 2004.
Results of Operations
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands)
Earnings before depreciation, depletion and amortization expense
and amortization of excess cost of equity investments
Products Pipelines........................................... $ 119,296 $ 110,535 $ 233,550 $ 219,209
Natural Gas Pipelines........................................ 95,438 88,872 198,543 180,433
CO2.......................................................... 75,992 47,173 153,695 89,139
Terminals.................................................... 65,699 60,064 128,872 119,426
------------ ------------ ------------ ------------
Segment earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments(a) 356,425 306,644 714,660 608,207
Total consolidated depreciation, depletion and amortization expense (69,878) (53,587) (137,409) (103,563)
Total consolidated amortization of excess cost of equity
investments...................................................... (1,394) (1,394) (2,788) (2,788)
Interest and corporate administrative expenses(b)................ (89,935) (82,706) (187,491) (162,421)
------------ ------------ ------------ -----------
Net income....................................................... $ 195,218 $ 168,957 $ 386,972 $ 339,435
============ ============ ============ ============
- ----------
(a) Includes revenues, earnings from equity investments, income taxes and other,
net, less operating expenses.
(b) Includes interest and debt expense, general and administrative expenses,
minority interest expense, loss from early extinguishment of debt (2004
only) and cumulative effect adjustment from a change in accounting principle
(2003 only).
Our consolidated net income for the second quarter and first six months of
2004 was $195.2 million and $387.0 million, respectively, or $0.51 and $1.03,
respectively, in earnings per diluted common unit. This compares to consolidated
net income for the second quarter and first six months of 2003 of $169.0 million
and $339.4 million, respectively, or $0.48 and $1.00, respectively, in earnings
per diluted common unit. We earned total revenues of $1,957.2 million in the
second quarter of 2004 and $3,779.4 million in the first six months of 2004.
These amounts compare to revenues of $1,664.4 million and $3,453.3 million
earned in the same periods of 2003.
44
Our net income for the first six months of 2003 included a $3.4 million
benefit from the cumulative effect of a change in accounting principle. The
change in accounting principle related to a change in accounting for asset
retirement obligations pursuant to our adoption of Statement of Financial
Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" on
January 1, 2003. Before the cumulative effect adjustment, our net income for the
six months ended June 30, 2003 totaled $336.0 million ($0.98 per diluted unit).
For more information on this cumulative effect adjustment from a change in
accounting principle, see Note 4 to our Consolidated Financial Statements,
included elsewhere in this report.
The increases in our second quarter and year-to-date net income in 2004
compared to 2003 reflected the continued benefits we received from following our
management strategy of providing fee-based services to growing energy markets.
By combining the performance of these services with expenditures made for
expansion and capital improvement projects and strategic acquisitions, we
reached record levels of net income in both the second quarter and the first six
months of 2004.
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 each of the second quarter and second quarter year-to-date
periods of 2004, all four of our reportable business segments reported increases
in earnings before depreciation, depletion and amortization, compared to the
same periods of 2003, with the strongest growth coming from our CO2 (carbon
dioxide), Natural Gas Pipelines and Products Pipelines business segments.
Also, we declared a record cash distribution of $0.71 per unit for the second
quarter of 2004 (an annualized rate of $2.84). This distribution is 9% higher
than the $0.65 per unit distribution we made for the second quarter of 2003, and
3% higher than the $0.69 per unit distribution we made for the first quarter of
2004. We expect to declare cash distributions of at least $2.84 per unit for
2004 and to increase our annualized cash distribution rate per unit to between
$2.90 and $2.94 by December 31, 2004; however, no assurance can be given that we
will be able to achieve these levels of distribution.
Products Pipelines
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 159,464 $ 145,284 $ 314,320 $ 289,701
Operating Expenses(a)...................................... (46,425) (40,480) (89,303) (81,666)
Earnings from equity investments........................... 8,933 7,587 13,952 15,630
Other, net................................................. 1,127 1,285 765 1,510
Income taxes............................................... (3,803) (3,141) (6,184) (5,966)
------------ ------------ ------------ ------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments............................................ 119,296 110,535 233,550 219,209
Depreciation, depletion and amortization expense........... (17,384) (16,723) (34,800) (33,283)
Amortization of excess cost of equity investments.......... (821) (821) (1,642) (1,642)
------------ ----------- ------------ ------------
Segment earnings......................................... $ 101,091 $ 92,991 $ 197,108 $ 184,284
============ ============ ============ ============
Refined product volumes (MMBbl)............................ 187.2 184.1 363.8 350.7
Natural gas liquids (MMBbl)................................ 9.5 8.4 21.0 21.2
----------- ----------- ----------- -----------
Total delivery volumes (MMBbl)(b).......................... 196.7 192.5 384.8 371.9
=========== =========== =========== ===========
- ----------
(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 consists of refined petroleum products and
natural gas liquids pipelines, related terminals and transmix processing
facilities. The segment reported earnings before depreciation, depletion and
amortization of $119.3 million on revenues of $159.5 million in the second
quarter of 2004. This compares to earnings before depreciation, depletion and
amortization of $110.5 million on revenues of $145.3 million in the
45
second quarter of 2003. For the comparable six-month periods ended June 30, the
segment reported earnings before depreciation, depletion and amortization of
$233.6 million on revenues of $314.3 million in 2004, and earnings before
depreciation, depletion and amortization of $219.2 million on revenues of $289.7
million in 2003. The segment's $8.8 million (8%) second quarter increase and
$14.4 million (7%) six-month increase in earnings before depreciation, depletion
and amortization in 2004 versus 2003 was broad-based across the segment, with
the strongest growth coming from our Pacific operations, our Southeast terminals
and our 44.8% ownership interest in the Cochin pipeline system.
For our Pacific operations, earnings before depreciation, depletion and
amortization increased $2.2 million (4%) and $7.0 million (6%), respectively, in
the three and six months ended June 30, 2004, when compared to the same periods
in 2003. The increases were primarily driven by higher terminal revenues
associated with incremental fees earned from ethanol-related services, refined
product gathering and incremental revenues related to the terminal operations we
acquired from Shell Oil Products in October 2003. Our Southeast terminals, which
include the operations of 14 refined products terminals located in the
southeastern United States that we acquired in December 2003 and March 2004,
reported earnings before depreciation, depletion and amortization of $3.5
million on revenues of $5.6 million in the second quarter of 2004. For the first
six months of 2004, the terminals reported earnings before depreciation,
depletion and amortization of $4.9 million on revenues of $7.9 million. For our
investment in Cochin, earnings before depreciation, depletion and amortization
increased $1.4 million (35%) and $3.8 million (43%), respectively, in the second
quarter and first six months of 2004, compared to the same periods last year.
The increases were primarily driven by higher revenues from pipeline throughput
deliveries.
The overall increases in earnings before depreciation, depletion and
amortization in both the second quarter and first six months of 2004, compared
to the same periods of 2003, were partly offset by lower earnings from our
CALNEV and North System pipeline systems. For CALNEV, earnings before
depreciation, depletion and amortization decreased $1.2 million (11%) and $1.4
million (6%), respectively, in the second quarter and first six months of 2004
compared to the same prior year periods. The decreases were driven by higher
fuel and power expenses and lower terminal and fee revenues. For our North
System, earnings before depreciation, depletion and amortization decreased $0.8
million (21%) and $2.6 million (21%), respectively, in the second quarter and
first six months of 2004 compared to the same year-earlier periods. The
decreases were driven by higher natural gas liquids storage expenses and lower
transport revenues.
Revenues for the segment increased $14.2 million (10%) in the second quarter
of 2004 versus the second quarter of 2003. In addition to incremental revenues
earned by our Southeast terminals, significant quarter-to-quarter increases in
revenues included a $3.6 million (61%) increase from Cochin, a $3.2 million (4%)
increase from our Pacific operations, a $0.8 million (6%) increase from our West
Coast terminals and a $0.7 million (9%) increase from our combined transmix
operations. Combined, the segment benefited from an almost 2% increase in the
volume of refined products delivered during the second quarter of 2004 compared
to the second quarter of 2003. Jet fuel delivery volumes were up over 8% in the
second quarter of 2004 compared to the second quarter of 2003, as both military
and commercial jet demand continued to rebound from 2003 levels.
Revenues for the segment increased $24.6 million (8%) in the first six months
of 2004 compared to the first six months of 2003. In addition to incremental
revenues earned by our Southeast terminals, significant period-to-period
increases in revenues included an $8.8 million (6%) increase from our Pacific
operations, a $7.0 million (52%) increase from Cochin, and $1.0 million
increases from each of the following: transmix processing, West Coast terminal
operations, and our Central Florida Pipeline system. Combined, the segment
benefited from an almost 4% increase in the volume of refined products delivered
during the first six months of 2004 compared to the first six months of 2003.
The overall increase in segment revenues for the first six months of 2004
compared to the same period of 2003 was partially offset by the $2.9 million
(14%) decrease in revenues from our North System. In April 2004, we filed a plan
with the Federal Energy Regulatory Commission to produce a line-fill service,
which we expect will mitigate the supply problems we experienced on our North
System in the first half of 2004.
The segment's operating expenses increased $5.9 million (15%) and $7.6
million (9%), respectively, in the second quarter and first six months of 2004,
compared to the same periods of 2003. In addition to incremental expenses
related to the acquisition of our Southeast terminal operations, the increases
in expenses primarily reflect higher period-to-period fuel and power expenses
incurred by our Pacific operations and our CALNEV Pipeline, and higher operating
and maintenance expenses from both Cochin and our Central Florida Pipeline. The
increases in
46
fuel and power expenses related to favorable credit adjustments to electricity
access and surcharge reserves taken in the second quarter of 2003 and to higher
product delivery volumes in both the second quarter and first half of 2004
compared to the same periods of 2003. The increases in operating and maintenance
expenses related to higher delivery volumes on the Cochin Pipeline and to
favorable adjustments to operating expenses on our Central Florida Pipeline
taken in the second quarter of 2003.
Earnings from equity investments consisted primarily of earnings related to
our approximate 51% ownership interest in Plantation Pipe Line Company. Total
equity earnings for the second quarter and first six months of 2004 increased
$1.3 million (18%) and decreased $1.7 million (11%), respectively, from
comparable periods in 2003. The quarter-to-quarter increase resulted primarily
from overall higher earnings from Plantation in the second quarter of 2004, due
to higher oil allowance revenues, lower oil losses, and lower rental expenses.
The decrease in equity earnings in the first six months of 2004 versus the first
six months of 2003 was mainly due to a $3.2 million expense recorded in the
first quarter of 2004 for our share of an environmental litigation settlement
reached between Plantation and various plaintiffs. We expect to recover the
effect of this settlement under our insurance policies. The overall decrease in
equity earnings resulting from higher litigation settlement costs was partially
offset by an increase in equity earnings associated with higher product delivery
revenues earned by Plantation, due to an approximate 3% increase in product
delivery volumes in the first half of 2004, compared to the first half of 2003.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased $0.7 million (4%) and $1.5
million (4%), respectively, in the second quarter and first six months of 2004,
compared to the same periods last year. The increases were primarily due to
incremental depreciations charges associated with our Southeast terminals, which
we acquired after the second quarter of 2003, and to higher property, plant and
equipment depreciation charges from our Pacific operations, related to the
capital spending we have made since the end of the second quarter of 2003.
Natural Gas Pipelines
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 1,554,831 $ 1,341,160 $ 2,992,739 $ 2,822,114
Operating Expenses(a)...................................... (1,463,867) (1,258,224) (2,803,827) (2,653,756)
Earnings from equity investments........................... 4,311 6,159 9,278 12,383
Other, net................................................. (4) 502 1,126 525
Income taxes............................................... 167 (725) (773) (833)
------------ ------------ ------------ ------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments............................................ 95,438 88,872 198,543 180,433
Depreciation, depletion and amortization expense........... (12,926) (13,603) (25,768) (26,229)
Amortization of excess cost of equity investments.......... (69) (69) (138) (138)
------------ ------------ ------------ ------------
Segment earnings......................................... $ 82,443 $ 75,200 $ 172,637 $ 154,066
============ ============ ============ ============
Natural gas transport volumes (Bcf)(b)..................... 270.4 302.2 543.0 584.0
=========== =========== =========== ===========
Natural gas sales volumes (Bcf)(c)......................... 242.8 227.7 487.9 434.9
=========== =========== =========== ===========
- ----------
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
(b) Includes Kinder Morgan Interstate Gas Transmission, Texas Intrastate group
and Trailblazer pipeline volumes.
(c) Includes Texas Intrastate group volumes.
Our Natural Gas Pipelines business segment includes our interstate and
intrastate natural gas transmission pipelines, natural gas storage, and natural
gas gathering and processing operations. The segment reported earnings before
depreciation, depletion and amortization of $95.4 million on revenues of
$1,554.8 million in the second quarter of 2004. This compares to earnings before
depreciation, depletion and amortization of $88.9 million on revenues of
$1,341.2 million in the second quarter of 2003. For the six-month periods ended
June 30, the segment reported earnings before depreciation, depletion and
amortization of $198.5 million on revenues of $2,992.7 million in 2004, and
earnings before depreciation, depletion and amortization of $180.4 million on
revenues of $2,822.1 million in 2003.
47
Both the $6.5 million (7%) three-month increase and the $18.1 million (10%)
six-month increase in overall earnings before depreciation, depletion and
amortization in 2004 versus 2003 were 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. Combined, our intrastate group reported increases in earnings
before depreciation, depletion and amortization of $12.1 million (27%) and $29.4
million (34%), respectively, in the second quarter and first six months of 2004,
compared to the same periods of 2003. The increases were driven by higher
margins from the natural gas sales activities of our Kinder Morgan Tejas and
Kinder Morgan Texas Pipeline systems, both of which purchase and sell natural
gas within the State of Texas. We also benefited from higher revenues from the
transmission of natural gas by our North Texas and Mier-Monterrey Mexico
pipelines and from higher fee revenues from the segmented services we provide in
the Texas market. Since the end of the second quarter of 2003, we have continued
to integrate the operations of these systems within and around the State of
Texas, benefiting from efficiencies achieved in securing natural gas supplies
and providing services for natural gas users in both Texas and the Monterrey,
Mexico region.
The segment's overall increases in earnings before depreciation, depletion
and amortization for the second quarter and first six month of 2004, compared to
the same periods of 2003, were partly offset by lower earnings from our two
Rocky Mountain natural gas pipeline systems: Kinder Morgan Interstate Gas
Transmission and Trailblazer Pipeline Company. Combined, these pipeline systems
reported decreases of $3.7 million (11%) and $8.9 million (12%), respectively,
in earnings before depreciation, depletion and amortization in the three and six
months ended June 30, 2004, when compared to the same prior year periods. For
Kinder Morgan Interstate Gas Transmission, the decreases were mainly due to
lower operational sales of natural gas, resulting in lower natural gas sales
revenues, and slightly lower transportation revenues. For Trailblazer, the
period-to-period decreases were primarily due to lower natural gas
transportation revenues, the result of lower gas transmission tariffs that
became effective January 1, 2004, pursuant to a rate case settlement.
Additionally, earnings before depreciation, depletion and amortization from
our natural gas processing and gathering assets, which includes the equity
earnings from our 49% investment in the Red Cedar Gas Gathering Company,
decreased $1.7 million (18%) in the second quarter of 2004 compared to the
second quarter of 2003, and decreased $2.4 million (12%) in the first six months
of 2004 compared to the first six months of 2003. The decreases were largely due
to higher operational sales of gas by Red Cedar in the second quarter and first
half of 2003, compared to the same periods this year.
Revenues earned by our Natural Gas Pipelines segment during the second quarter
and first six months of 2004 increased $213.6 million (16%) and $170.6 million
(6%), respectively, over comparable periods in 2003. For the comparable second
quarters, the overall increase in segment revenues includes an increase of
$220.2 million (18%) in natural gas sales revenues by our Kinder Morgan Tejas
and Kinder Morgan Texas Pipeline systems, resulting from an 11% increase in
average gas prices (from $5.35 per dekatherm in 2003 to $5.92 per dekatherm in
2004) and a 7% increase in sales volumes in the second quarter of 2004 versus
the second quarter of 2003. For the comparable six-month periods, the overall
increase in segment revenues includes an increase of $167.7 million (7%) in
natural gas sales revenues by these two systems, driven by a 12% increase in gas
sales volumes and partially offset by a 5% decrease in average sale prices (from
$5.93 per dekatherm in 2003 to $5.63 per dekatherm in 2004). During 2004, both
systems benefited from increased sales of natural gas across the State of Texas
and from full contract demand levels under long-term transportation and sales
contracts with a major customer. Combined, the two pipeline systems reported a
decrease of $1.8 million (4%) in revenues earned from natural gas
transportation, storage and other gas services in the second quarter of 2004
versus the second quarter of 2003, primarily due to lower natural gas storage
fees. For the comparable six month periods, however, transportation, storage and
service revenues increased $8.6 million (11%) in 2004 versus 2003, primarily due
to higher fees for natural gas blending, treating and other gas services.
We also benefited from higher revenues from our North Texas Pipeline and from
the inclusion of a full six months of operations from our Mier-Monterrey
Pipeline, which began operations in March 2003. The North Texas Pipeline, an
86-mile intrastate pipeline that connects to KMI's Natural Gas Pipeline Company
of America system in Lamar County, Texas, reported increases of $1.3 million
(72%) and $3.3 million (109%), respectively, in revenues in the second quarter
and first six months of 2004, compared to the same periods a year ago. The
increases resulted
48
from higher natural gas transmission fees received for providing gas to an
electric generating facility in north Texas, which started full service in
August 2003. Revenues from our Monterrey Pipeline remained flat across the
comparable second quarter periods, but the inclusion of an additional three
months of operations in 2004 contributed incremental revenues of $3.2 million in
the first six months of 2004, compared to the first six months of 2003.
Revenues from our Rocky Mountain pipeline systems decreased $6.7 million (13%)
and $11.2 million (10%), respectively, in the second quarter and first six
months of 2004, compared to the same periods last year. As described above, the
decreases were primarily due to lower gas transmission tariffs on our
Trailblazer system and to lower operational sales and transportation revenues
from our Kinder Morgan Interstate Gas Transmission system. Due to the
implementation of new tariff rates on January 1, 2004, average tariff rates on
Trailblazer decreased 11% and 10%, respectively, in the second quarter and first
six months of 2004 when compared to the same prior-year periods. The
period-to-period decreases in sales and transportation revenues earned by our
Kinder Morgan Interstate system were due to lower natural gas volumes, mainly
due to lower demand for natural gas in and around the Rocky Mountain region
during the first half of 2004 compared to the first half of 2003.
The segment's operating expenses, including natural gas purchase costs,
increased $205.6 million (16%) and $150.1 million (6%), respectively, in the
second quarter and first six months of 2004, versus the same periods of 2003.
The overall increases in operating expenses include increases of $207.0 million
(17%) and $149.6 million (6%), respectively, in purchased costs of natural gas
by our intrastate natural gas pipeline group in the second quarter and first six
months of 2004, compared to 2003. The higher gas purchase costs reflect the
growth in segment sales volumes, discussed above, as both Kinder Morgan Tejas
and Kinder Morgan Texas Pipeline purchase and sell significant volumes of
natural gas within the State of Texas. The increase in cost of sales for the
comparable three month periods also related to the quarter-to-quarter increase
in average gas prices, and the increase in cost of sales for the comparable six
month periods were parially offset by the period-to-period decrease in average
gas prices. Excluding the costs of sales, the segment's operating expenses
remained essentially flat for both the second quarter and first six months of
2004, compared to the same periods of 2003.
Equity earnings decreased $1.8 million (30%) and $3.1 million (25%),
respectively, in the second quarter and first six months of 2004, compared to
the same year-earlier periods. The decreases in period-to-period earnings from
equity investments primarily related to lower earnings from our investment in
Red Cedar, as discussed above. Both the $0.5 million decrease and the $0.6
million increase, respectively, in other income items for the second quarter and
first six months of 2004 compared to the same periods of 2003, resulted
primarily from timing differences on gains and losses realized from the
disposals of miscellaneous property and equipment. Income tax expenses increased
$0.9 million in the second quarter of 2004 compared to the second quarter of
2003, but remained relatively flat across the comparable six month periods. The
increase in income tax expenses in the second quarter of 2004 over the second
quarter of 2003 primarily related to higher taxes on the operations of our
Monterrey Pipeline, due to differences in the exchange rate and inflation
adjustments that are included in the calculation of periodic income tax expense.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, decreased $0.7 million (5%) and $0.5
million (2%), respectively, in the second quarter and first six months of 2004,
when compared to the same periods last year. Normal increases in depreciation
charges related to additional capital investments made since the end of the
second quarter of 2003 were more than offset by a decrease in charges on our
Trailblazer Pipeline Company, due to the rate case settlement which became
effective January 1, 2004.
49
CO2
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 110,572 $ 54,631 $ 216,158 $ 103,087
Operating Expenses(a)...................................... (41,904) (16,290) (80,289) (32,803)
Earnings from equity investments........................... 7,362 8,864 17,841 18,870
Other, net................................................. 23 (12) 32 5
Income taxes............................................... (61) (20) (47) (20)
------------- ------------ ------------- -------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments............................................ 75,992 47,173 153,695 89,139
Depreciation, depletion and amortization expense(b)........ (29,130) (14,281) (56,118) (26,043)
Amortization of excess cost of equity investments.......... (504) (504) (1,008) (1,008)
------------- ------------ ------------- -------------
Segment earnings......................................... $ 46,358 $ 32,388 $ 96,569 $ 62,088
============= ============ ============= =============
Carbon dioxide volumes transported (Bcf)(c)................ 138.6 104.6 321.1 206.9
============= ============ ============= =============
SACROC oil production (MBbl/d)(d).......................... 27.4 19.6 26.7 18.3
============= =========== ============= =============
Yates oil production (MBbl/d)(d)........................... 18.6 19.6 18.2 18.8
============= =========== ============= =============
Realized weighted average oil price per Bbl(e)............. $ 25.26 $ 24.21 $ 25.31 $ 24.50
============= ============ ============= =============
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and power
expenses and taxes, other than income taxes.
(b) Includes expenses of $25,484 in the second quarter of 2004 and $11,616 in
the second quarter of 2003 associated with production activities, and
expenses of $3,646 in the second quarter of 2004 and $2,665 in the second
quarter of 2003 associated with sales and transportation services. Includes
expenses of $48,600 in the first six months of 2004 and $20,788 in the first
six months of 2003 associated with production activities, and expenses of
$7,518 in the first six months of 2004 and $5,255 in the first six months of
2003 associated with sales and transportation services.
(c) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos
pipeline volumes.
(d) Represents 100% production from the field.
(e) Includes all Kinder Morgan crude oil properties.
Our CO2 business segment produces, transports and markets carbon dioxide for
use in enhanced oil recovery operations and owns interests in oil-producing
fields and other related assets. In the second quarter of 2004, the segment
reported earnings before depreciation, depletion and amortization of $76.0
million on revenues of $110.6 million. This compares to earnings before
depreciation, depletion and amortization of $47.2 million on revenues of $54.6
million in the second quarter of 2003. For the comparable six-month periods
ended June 30, the segment reported earnings before depreciation, depletion and
amortization of $153.7 million on revenues of $216.2 million in 2004, and
earnings before depreciation, depletion and amortization of $89.1 million on
revenues of $103.1 million in 2003.
Both the $28.8 million (61%) increase in earnings before depreciation,
depletion and amortization in the second quarter of 2004 over the second quarter
of 2003, and the $64.6 million (73%) increase in the first six months of 2004
over the comparable period of 2003 were driven by higher earnings from oil and
gas producing activities, higher deliveries of carbon dioxide, and our
acquisition of additional working interests in oil producing properties since
June 1, 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 in the
second quarter of 2004, we benefited from having a full quarter of
operations that included our additional ownership interest; 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 $230.2
million in cash and the assumption of $28.9 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
unit 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.
50
Combined, our oil and gas producing activities reported increases of $22.3
million (85%) and $44.7 million (91%), respectively, in earnings before
depreciation, depletion and amortization for the three and six months ended June
30, 2004, when compared to the same periods a year ago. These increases were
driven by the growth in operations at the SACROC oil field occurring since the
end of the second quarter of 2003. The growth reflects increases of 40% and 46%,
respectively, in daily oil production volumes for the second quarter and first
six months of 2004, compared to the same periods a year ago. We also benefited
from increases of 4% and 3%, respectively, in our realized weighted average
price of oil per barrel in the second quarter and first six months of 2004
versus the same time periods in 2003. We mitigate our price risk through a
long-term hedging strategy that is intended to generate more stable realized
prices. For more information on our hedging activities, see Note 10 to our
Consolidated Financial Statements, included elsewhere in this report.
Our carbon dioxide sales and transportation activities reported increases of
$6.5 million (31%) and $19.9 million (49%), respectively, in earnings before
depreciation, depletion and amortization for the three and six months ended June
30, 2004, when compared to the same periods last year. The increases were driven
by higher carbon dioxide delivery volumes, due to the continued expansion at
SACROC and the initiation of carbon dioxide flooding at the Yates oil field. We
also benefited from the inclusion of a full six months of operations from our
Centerline carbon dioxide pipeline, completed in May 2003. We do not recognize
profits on carbon dioxide sales to ourselves.
Revenues earned by our CO2 business segment during the second quarter and
first six months of 2004 increased $56.0 million (103%) and $113.1 million
(110%), respectively, over comparable periods in 2003. The increases were mainly
due to higher crude oil and gasoline plant product sales revenues, driven by
higher oil and gas production volumes, higher average crude oil and gasoline
product prices, and the additional working interests in oil producing properties
that we acquired since the end of the second quarter of 2003.
Additionally, in 2004, we benefited from higher revenues from carbon dioxide
transportation and related transportation services, both resulting from
increases in carbon dioxide delivery volumes throughout the Permian Basin.
Combined deliveries of carbon dioxide on our Central Basin Pipeline, our
majority-owned Canyon Reef Carriers and Pecos Pipelines, our 50% owned Cortez
Pipeline and our Centerline Pipeline increased 34.0 billion cubic feet (33%) and
114.2 billion cubic feet (55%), respectively, in the second quarter and first
six months of 2004, compared to the same periods in 2003.
Our acquisition of additional working interests and assets in the SACROC and
Yates oil field units that have occurred since the end of the second quarter of
2003, and referred to above, contributed incremental revenues of approximately
$29.2 million and $57.6 million, respectively, in the second quarter and first
six months of 2004. Revenues earned by our Centerline Pipeline during the second
quarter and first six months of 2004 totaled $2.0 million and $5.5 million,
respectively, compared to revenues of $1.5 million earned during its two months
of operations in the first half of 2003.
Operating expenses in the second quarter and first six months of 2004
increased $25.6 million (157%) and $47.5 million (145%), respectively, over the
same periods in 2003. Both period-to-period increases related to higher
operating and maintenance expenses, higher fuel and power costs, and higher
production taxes, all as a result of the increases in oil production volumes and
carbon dioxide delivery volumes.
Earnings from equity investments decreased $1.5 million (17%) and $1.0
million (5%), respectively, in the second quarter and first six months of 2004,
compared to the same periods last year. The overall decreases resulted from the
dissolution of MKM Partners, L.P. (which eliminated our 15% equity ownership
interest) following our SACROC acquisition referred to above. Equity earnings
from our 50% investment in the Cortez Pipeline Company increased $0.5 million
(8%) in the second quarter of 2004 compared to the second quarter of 2003, and
$4.0 million (29%) in the first six months of 2004 compared to the first six
months of 2003. The increases were mainly due to higher carbon dioxide delivery
volumes in 2004 versus 2003.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased $14.8 million (100%) and
$30.1 million (111%), respectively, in the second quarter and first six months
of 2004, when compared to the same periods last year. The increases were
primarily due to higher production, higher unit-of-production depletion rates
and the acquisition of our additional interests in the SACROC and Yates oil
fields.
51
Terminals
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 132,315 $ 123,372 $ 256,221 $ 238,383
Operating Expenses(a)...................................... (64,287) (60,619) (124,393) (115,057)
Earnings from equity investments........................... 3 8 7 40
Other, net................................................. (211) (267) (245) (255)
Income taxes............................................... (2,121) (2,430) (2,718) (3,685)
------------ ------------ ------------ ------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments............................................ 65,699 60,064 128,872 119,426
Depreciation, depletion and amortization expense........... (10,438) (8,980) (20,723) (18,008)
Amortization of excess cost of equity investments.......... - - - -
----------- ----------- ----------- -----------
Segment earnings......................................... $ 55,261 $ 51,084 $ 108,149 $ 101,418
=========== =========== ============ ============
Bulk transload tonnage (MMtons)(b)......................... 16.9 15.7 31.7 30.2
=========== =========== =========== ===========
Liquids leaseable capacity (MMBbl)......................... 36.5 35.9 36.5 35.9
=========== =========== =========== ===========
Liquids utilization %...................................... 96.0% 96.0% 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 and dry-bulk
material services, including all transload, engineering and other in-plant
services, as well as all the operations of our petroleum and
petrochemical-related liquids terminal facilities. Combined, the segment is
composed of approximately 51 owned or operated liquids and bulk terminal
facilities and approximately 60 rail transloading facilities located throughout
the United States. Beginning with the second quarter of 2004, we began grouping
our bulk and liquids terminal operations into nine regions, each representing an
aggregate used by our management to organize and evaluate segment performance
and to help make operating decisions and allocate resources.
The nine regions consist of the following:
o Midwest;
o Northeast;
o Mid-Atlantic;
o Southeast;
o Lower Mississippi River (Louisiana);
o Gulf Coast;
o West;
o Materials Services (rail transloading); and
o Engineering and other.
In the second quarter of 2004, our Terminals segment reported earnings before
depreciation, depletion and amortization of $65.7 million on revenues of $132.3
million. This compares to earnings before depreciation, depletion and
amortization of $60.1 million on revenues of $123.4 million in the second
quarter of 2003. For the comparable six-month periods, the segment reported
earnings before depreciation, depletion and amortization of $128.9 million on
revenues of $256.2 million in 2004, and earnings before depreciation, depletion
and amortization of $119.4 million on revenues of $238.4 million in 2003.
52
Earnings before depreciation, depletion and amortization in the second quarter
and first six months of 2004 increased $5.6 million (9%) and $9.5 million (8%),
respectively, over comparable periods in 2003. The increases were primarily due
to higher earnings from our Pasadena and Galena Park, Texas liquids terminals
(Gulf Coast), our Carteret and Perth Amboy, New Jersey liquids terminals
(Northeast), and our Pier IX bulk terminal (Mid-Atlantic). Combined, these five
terminal facilities reported increases in earnings before depreciation,
depletion and amortization of $2.9 million and $5.8 million, respectively, in
the second quarter and first six months of 2004, when compared to the same
periods of 2003. The increases from our Gulf Coast and Northeast liquids
terminals were driven by higher revenues resulting from higher throughput
volumes, contract price escalations, additional service contracts, expansion
projects and new pipeline connections, and increased imports in the Northeast.
As of June 30, 2004, expansion projects at our liquids terminals completed since
the end of the second quarter of 2003, which included the construction of
additional petroleum products storage tanks, increased total liquids leaseable
capacity by approximately 600,000 barrels (2%). The increases at Pier IX,
located in Newport News, Virginia, were primarily due to higher synfuel revenues
and higher revenues from transloading coal.
We also benefited from incremental earnings before depreciation, depletion and
amortization attributable to the two bulk terminal businesses in Tampa, Florida,
that we acquired in December 2003. The businesses include the operations of a
marine terminal and an inland bulk storage warehouse facility. Combined, these
businesses reported earnings before depreciation, depletion and amortization of
$1.6 million on revenues of $2.8 million for the second quarter of 2004, and
earnings before depreciation, depletion and amortization of $3.2 million on
revenues of $5.1 million for the six months ended June 30, 2004.
Revenues earned by our Terminals segment during the second quarter and first
six months of 2004 increased $8.9 million (7%) and $17.8 million (7%),
respectively, over comparable periods in 2003. The increase in revenues in the
second quarter of 2004 compared to the second quarter of 2003 includes
increases of $2.6 million from our Carteret, Pasadena and Galena Park liquids
terminal facilities, $1.3 million from our Pier IX terminal, $1.2 million from
our 66 2/3% ownership interest in the International Marine Terminals
Partnership, and $2.8 million from our Tampa bulk terminal acquisitions. The
increase in segment revenues in the first six months of 2004 compared to the
first six months of 2003 includes increases of $6.5 million from our Carteret,
Pasadena and Galena Park liquids terminal facilities, $1.9 million from our Pier
IX terminal, $3.9 million from IMT, and $5.1 million from our Tampa bulk
terminal acquisitions. The increases in segment revenues from our Gulf Coast and
Northeast terminals were driven by the same factors discussed above. The
increases in revenues from Pier IX related to higher synfuel and coal revenues.
The increases in revenues from IMT, a multi-purpose facility located in Port
Sulphur, Louisiana, were driven by higher bulk tonnage transfer volumes and by
higher dockage revenues. IMT works with shippers to coordinate deliveries of
other materials like iron ore to coincide with outbound shipments of coal.
Operating expenses increased $3.7 million (6%) and $9.3 million (8%),
respectively, in the second quarter and first six months of 2004 versus the same
periods of 2003. The increases were primarily due to higher operating and
maintenance expenses at our liquids terminals due to higher throughput volumes,
higher dockage and stevedoring expenses at our bulk terminals due to increased
tonnage and ship conveyance activities, and incremental expenses incurred by our
acquired Tampa bulk terminal businesses. Increases in segment operating expenses
included higher payroll costs, tank cleaning and related maintenance charges,
and higher fuel and utility costs, all related to increased petroleum and
dry-bulk tonnage transfer volumes. Incremental operating expenses incurred by
our acquired Tampa bulk terminal operations totaled $1.2 million in the second
quarter of 2004 and $1.9 million in the first six months of 2004.
Other income items were essentially flat year-over-year. Income tax expenses
during the second quarter and first six months of 2004 decreased $0.3 million
(13%) and $1.0 million (26%), respectively, over comparable periods in 2003. The
decreases in income tax expense were due to lower taxable income from Delta
Terminal Services LLC, the tax-paying entity that owns two liquid bulk storage
terminals in New Orleans, Louisiana and Cincinnati, Ohio. The decreases related
to lower earnings in both the second quarter and first six months of 2004
compared to the same periods last year.
Non-cash depreciation, depletion and amortization charges increased $1.5
million (16%) and $2.7 million (15%), respectively, in the second quarter and
first six months of 2004, over comparable periods in 2003. The increases in the
second quarter and first half of 2004 versus the same periods a year ago reflect
higher depreciation charges due
53
to the additional capital spending and acquisitions we have made since the end
of the second quarter of 2003, including additional transfers of completed
project costs into depreciable plant.
Other
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands-income/(expense)
General and administrative expenses........................ $ (39,457) $ (35,685) $ (87,711) $ (71,726)
Interest, net.............................................. (46,592) (44,896) (93,813) (89,821)
Minority interest.......................................... (2,462) (2,125) (4,543) (4,339)
Loss from early extinguishment of debt..................... (1,424) - (1,424) -
Cumulative effect adjustment from change in accounting
principle.................................................. - - - 3,465
------------ ------------ ------------ ------------
Interest and corporate administrative expenses........... $ (89,935) $ (82,706) $ (187,491) $ (162,421)
============ ============ ============ ============
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. In the second
quarter of 2004, we also included the $1.4 million loss from our early
extinguishment of debt in May 2004 as an item not attributable to any business
segment. The loss represented the excess of the price we paid to repurchase and
retire the principal amount of $84.3 million of tax-exempt industrial revenue
bonds over the bonds' carrying value. Combined, items not attributable to any
business segment totaled $89.9 million in the second quarter of 2004 and $82.7
million in the second quarter of 2003. For more information on our early
extinguishment of debt, see Note 7 to our Consolidated Financial Statements
included elsewhere in this report.
In addition, in the first quarter of 2003, we included the $3.4 million
benefit from the cumulative effect adjustment of a change in accounting for
asset retirement obligations as of January 1, 2003 (discussed above), as an item
not attributable to any business segment. For the six months ended June 30, 2004
and 2003, items not attributable to any business segment totaled $187.5 million
and $162.4 million, respectively.
Our general and administrative expenses, which include such items as salaries
and employee-related expenses, payroll taxes, legal fees, insurance and office
supplies and rentals, increased $3.8 million (11%) and $16.0 million (22%),
respectively, in the second quarter and first six months of 2004, when compared
to the same periods last year. The increases were primarily due to higher
employee bonus and benefit expenses and higher overall corporate and
worker-related insurance expenses.
Total interest expense, net of interest income, increased $1.7 million (4%)
and $4.0 million (4%), respectively, in the second quarter and first six months
of 2004 versus the same year-earlier periods. The increases were due to higher
average borrowings during both the three and six month periods ended June 30,
2004, compared to the three and six month periods ended June 30, 2003. The
increases in average borrowings were primarily due to capital spending related
to internal expansions and improvements, and to incremental borrowings made in
connection with acquisition expenditures. Since June 30, 2003, we acquired
additional oil reserve ownership interests and carbon dioxide assets, seven
refined petroleum products terminals from ConocoPhillips Company and Phillips
Pipe Line Company, two bulk terminal businesses in Tampa, Florida, and seven
refined petroleum products terminals from Exxon Mobil Corporation. Our overall
increase in net interest items in the first six months of 2004 compared to the
first six months of 2003 was partially offset by slightly lower (1%) average
borrowing rates. 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 represents the deduction in our consolidated net
income attributable to all outstanding ownership interests in our operating
limited partnerships and their consolidated subsidiaries that are not held by
us, remained relatively flat across both the comparable second quarter and
second quarter year-to-date periods of 2004 and 2003.
54
Financial Condition
Since the change in control of our general partner in February 1997, we have
continued to follow the strategy of maintaining a strong balance sheet in order
to allow flexibility in raising capital necessary for growth. Accordingly, we
attempt to maintain an overall conservative capital structure, consisting of a
mix of approximately 50% equity and 50% debt.
The following table illustrates the sources of our invested capital (dollars
in thousands). In addition to our results of operations, these balances are
affected by our financing activities as discussed below:
June 30, December 31,
---------- ------------
2004 2003
---------- ------------
Long-term debt, excluding market value of interest rate
swaps..................................................... $ 3,932,614 $4,316,678
Minority interest......................................... 41,501 40,064
Partners' capital......................................... 3,611,695 3,510,927
------------ ------------
Total capitalization.................................... 7,585,810 7,867,669
Short-term debt, less cash and cash equivalents........... 329,983 (21,081)
------------ ------------
Total invested capital.................................. $ 7,915,793 $ 7,846,588
============ ============
Capitalization:
Long-term debt, excluding market value of interest rate 51.8% 54.9%
swaps.....................................................
Minority interest....................................... 0.6% 0.5%
Partners' capital....................................... 47.6% 44.6%
------------ ------------
100.0% 100.0%
============ ============
Invested Capital:
Total debt, less cash and cash equivalents and excluding
market value of interest rate swaps................ 53.8% 54.7%
Partners' capital and minority interest................. 46.2% 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 retained
cash (resulting from including i-units in the determination of cash
distributions per unit but paying quarterly distributions on i-units in
additional i-units rather than cash), additional borrowings, the issuance of
additional common units or the issuance of additional i-units to KMR;
o interest payments with cash flows from operating activities; and
o debt principal payments with additional borrowings, as such debt principal
payments become due, or by the issuance of additional common units or the
issuance of additional i-units to KMR.
Through the six months ended June 30, 2004, we have continued to generate
strong cash flow from operations, and we provide for additional liquidity by
maintaining sizable cash balances and excess borrowing capacity related to our
commercial paper program and two committed revolving credit facilities. In
August 2004, we intend to replace our existing bank facilities with a $1.25
billion five-year revolving credit facility. This new credit facility, if
completed as expected, will include covenants and require payment of facility
fees that are similar in nature to the covenants and facility fees required by
our current bank facilities as discussed in our Annual Report on Form 10-K for
the year ended December 31, 2003. Currently, we do not anticipate any liquidity
problems.
55
On June 30 2004, we renewed a 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. The former $50 million letter of credit expired
on June 30, 2004. The amount of the new letter of credit was increased from $50
million to $100 million and will expire on December 31, 2004.
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 June 30, 2004, our budgeted expenditures for the remaining six months of
2004 for sustaining capital spending were approximately $69.8 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 $555.8 million for the six
months ended June 30, 2004, versus $336.1 million in the comparable period of
2003. The period-to-period increase of $219.7 million (65%) in cash flow from
operations was primarily due to a $93.6 million increase in cash inflows
relative to net changes in working capital items, a $90.9 million increase in
cash from overall higher partnership income, net of non-cash items including
depreciation charges and undistributed earnings from equity investments, and a
$44.5 million increase related to transportation rate reparation and refund
payments made in April 2003.
The favorable inflows from working capital in 2004 were mainly related to
timing differences in the collection and payment of both trade and related party
receivables and payables. The higher partnership income reflects the record
levels of segment earnings before depreciation, depletion and amortization
reported in the first six months of 2004 and discussed above in "Results of
Operations." Partially offsetting the overall increase in cash provided by
operating activities was an $8.7 million decrease in distributions received from
equity investments, primarily due to the dissolution of MKM Partners, L.P. on
June 30, 2003, which eliminated our 15% equity ownership interest.
Investing Activities
Net cash used in investing activities was $395.1 million for the six month
period ended June 30, 2004, compared to $310.0 million in the comparable 2003
period. The $85.1 million (27%) increase in cash used in investing activities
was primarily attributable to higher expenditures made for capital additions and
internal expansion projects during the first half of 2004 compared to the first
half of 2003. Including expansion and maintenance projects, our capital
expenditures were $339.5 million in the first six months of 2004 versus $273.4
million in the same year-ago period. The $66.1 million (24%) increase was mainly
driven by higher capital investment in our CO2 and Products Pipelines business
segments.
During the first six months of 2004, we have continued to increase our asset
infrastructure and to expand and grow our existing businesses through the
following ongoing or completed capital expenditure projects (all of the
following projects were included in our 2004 budget):
o CO2 expansion - more than $300 million is being invested during 2004 in new
well and injection compression facilities at the SACROC and Yates oil field
units in West Texas in order to enhance oil recovery from carbon
56
dioxide injection. By the end of 2004, we expect to reach production
levels of 30,000 barrels of oil per day at the SACROC unit and 20,000
barrels of oil per day at the Yates unit;
o Refined products pipeline expansions - includes the $200 million expansion
of our Pacific operations' East Line pipeline, and the approximate $90
million expansion of our Pacific operations' Concord to Sacramento,
California pipeline. The East Line 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%. We expect to
invest approximately $18 million in the project during 2004 and the expected
start-up for this expansion is sometime in the fourth quarter of 2005 or the
first quarter of 2006. The Concord to Sacramento project entails the
replacement of an existing 14-inch diameter pipeline with a new 20-inch
diameter line to help meet the region's growing demand for gasoline, diesel
and jet fuel. The new line is estimated to be in service before the end of
2004;
o Natural gas storage and pipeline expansions - includes two approximate $30
million projects in our Natural Gas Pipelines business segment: the Cheyenne
Market Center project and the Katy to Austin, Texas intrastate natural gas
pipeline project. The Cheyenne Market Center project entails the
construction of pipeline and storage facilities to accommodate an additional
six billion cubic feet of natural gas storage capacity at the natural gas
market center in Cheyenne, Wyoming. We commenced providing service to
customers on June 1, 2004. The Katy to Austin pipeline project entailed the
conversion of a 130-mile pipeline that we acquired in December 2003 from
crude oil to natural gas service and the construction of a five mile
lateral pipeline that together will provide approximately 170 million cubic
feet per day of natural gas to the Austin market. The pipeline began
service in mid-July 2004; and
o Terminals - includes approximately $19 million being invested at our
Carteret liquids terminal in New York Harbor in order to add 600,000 barrels
of storage capacity. Three 100,000 barrel petroleum products storage tanks
were completed in early-July and three more are expected to be completed in
December 2004. In addition, we are currently building a cement facility at
our Dakota bulk terminal located in St. Paul, Minnesota. The facility will
cost approximately $20 million and is expected to be completed sometime in
the fourth quarter of 2004.
Our sustaining capital expenditures were $46.1 million for the first six
months of 2004 compared to $40.1 million for the first six months of 2003.
Additionally, for the six months ended June 30, 2004, our acquisition outlays
totaled $51.7 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 six months ended June 30, 2003, our acquisition
of assets totaled $33.7 million, including $23.3 million for the acquisition of
an additional 12.75% ownership interest in the SACROC oil field unit in West
Texas from MKM Partners, L.P. For more information on our acquisitions, see Note
2 to the Consolidated Financial Statements included elsewhere in this report.
Financing Activities
Net cash used in financing activities was $150.3 million for the six months
ended June 30, 2004 and $22.3 million for the same prior-year period. The $128.0
million increase in cash used in financing activities in the first half of 2004
over the comparable 2003 period was primarily the result of a $150.7 million
decrease in cash flows from overall debt financing activities, a $78.0 million
increase in cash flows from additional partnership equity issuances, and a $53.1
million increase in outflows resulting from higher distributions to our
partners.
The decrease in cash flows from overall debt financing activities, consisting
of both our issuances and our payments of debt, was mainly due to lower
incremental commercial paper borrowings in the first six months of 2004 versus
the first six months of 2003, and to the redemption of long-term debt securities
in May 2004. At that time, we paid $84.3 million to redeem and retire the
principal amount of four series of tax-exempt bonds related to certain liquids
terminal facilities. Pursuant to certain provisions that gave us the right to
call and retire the bonds prior to maturity, we took advantage of the
opportunity to refinance at lower rates.
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The period-to-period increase in cash flows from partnership equity issuances
primarily related to the excess of cash received from both our February 2004
issuance of common units and our March 2004 issuance of i-units over cash
received from our June 2003 issuance of common units. On February 9, 2004, we
issued, in a public offering, an additional 5,300,000 of our common units at a
price of $46.80 per unit, less commissions and underwriting expenses. We
received net proceeds of $237.8 million for the issuance of these common units.
On March 25, 2004, we issued an additional 360,664 of our i-units to KMR at a
price of $41.59 per share, less closing fees and commissions. We received net
proceeds of $14.9 million for the issuance of these i-units. By comparison, in a
June 2003 public offering, we issued an additional 4,600,000 of our common
units, including 600,000 units upon exercise by the underwriters of an
over-allotment option, at a price of $39.35 per share, less commissions and
underwriting expenses. We received net proceeds of $173.3 million for the
issuance of these common units. We used the proceeds from each of these
issuances to reduce the borrowings under our commercial paper program.
Distributions to partners, consisting of all limited partners, our general
partner and minority interests, totaled $379.4 million in the first six months
of 2004 compared to $326.3 million in the same year-earlier period. The increase
in distributions was due to an increase in the per unit cash distributions paid,
an increase in the number of units outstanding and an increase in our general
partner incentive distributions. The increase in our general partner incentive
distributions resulted from both increased cash distributions per unit and an
increase in the number of common units and i-units outstanding.
On May 14, 2004, we paid a quarterly distribution of $0.69 per unit for the
first quarter of 2004, 8% greater than the $0.64 per unit distribution paid for
the first quarter of 2003. We paid this distribution in cash to our common
unitholders and to our Class B unitholders. KMR, our sole i-unitholder, received
872,958 additional i-units based on the $0.69 cash distribution per common unit.
For each outstanding i-unit that KMR held, a fraction (0.017412) of an i-unit
was 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.
On July 21, 2004, we declared a cash distribution for the quarterly period
ended June 30, 2004, of $0.71 per unit. The distribution will be paid on or
before August 13, 2004, to unitholders of record as of July 31, 2004. Our common
unitholders and Class B unitholders will receive cash. KMR, our sole
i-unitholder, will receive a distribution in the form of additional i-units
based on the $0.71 distribution per common unit. The number of i-units
distributed will be 920,140. For each outstanding i-unit that KMR holds, a
fraction (0.018039) of an i-unit will be issued. The fraction was determined by
dividing $0.71, the cash amount distributed per common unit by $39.36, the
average of KMR's shares' closing market prices from July 14-27, 2004, the ten
consecutive trading days preceding the date on which the shares began to trade
ex-dividend under the rules of the New York Stock Exchange.
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.
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Our general partner and owners of our common units and Class B units receive
distributions in cash, while KMR, the sole owner of our i-units, receives
distributions in additional i-units. The cash equivalent of distributions of
i-units is treated as if it had actually been distributed for purposes of
determining the distributions to our general partner. We do not distribute cash
to i-unit owners but retain the cash for use in our business.
Available cash is initially distributed 98% to our limited partners and 2% to
our general partner. These distribution percentages are modified to provide for
incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
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 second quarter of 2004 was $94.9
million. Our general partner's incentive distribution for the distribution that
we declared for the second quarter of 2003 was $79.6 million. Our general
partner's incentive distribution that we paid during the second quarter of 2004
to our general partner (for the first quarter of 2004) was $90.7 million. Our
general partner's incentive distribution that we paid during the second quarter
of 2003 to our general partner (for the first quarter of 2003) was $75.5
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.
Certain Contractual Obligations
There has been no material changes in either certain contractual obligations
or our obligations with respect to other entities which are not consolidated in
our financial statements that would affect the disclosures presented as of
December 31, 2003 in our 2003 Form 10-K report.
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;
59
o economic activity, weather, alternative energy sources, conservation and
technological advances that may affect price trends and demand;
o changes in our tariff rates implemented by the Federal Energy Regulatory
Commission or the California Public Utilities Commission;
o our ability to acquire new businesses and assets and integrate those
operations into our existing operations, as well as our ability to make
expansions to our facilities;
o difficulties or delays experienced by railroads, barges, trucks, ships or
pipelines in delivering products to or from our terminals or pipelines;
o our ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
o shut-downs or cutbacks at major refineries, petrochemical or chemical
plants, ports, utilities, military bases or other businesses that use our
services or provide services or products to us;
o changes in laws or regulations, third-party relations and approvals,
decisions of courts, regulators and governmental bodies that may adversely
affect our business or our ability to compete;
o our ability to offer and sell equity securities and debt securities or
obtain debt financing in sufficient amounts to implement that portion of our
business plan that contemplates growth through acquisitions of operating
businesses and assets and expansions of our facilities;
o our indebtedness could make us vulnerable to general adverse economic and
industry conditions, limit our ability to borrow additional funds and/or
place us at competitive disadvantages compared to our competitors that have
less debt or have other adverse consequences;
o interruptions of electric power supply to our facilities due to natural
disasters, power shortages, strikes, riots, terrorism, war or other causes;
o acts of nature, sabotage, terrorism or other similar acts causing damage
greater than our insurance coverage limits;
o capital markets conditions;
o the political and economic stability of the oil producing nations of the
world;
o national, international, regional and local economic, competitive and
regulatory conditions and developments;
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.
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You should not put undue reliance on any forward-looking statements.
See Items 1 and 2 "Business and Properties--Risk Factors" of our Annual
Report on Form 10-K for the year ended December 31, 2003, for a more detailed
description of these and other factors that may affect the forward-looking
statements. When considering forward-looking statements, one should keep in mind
the risk factors described in our 2003 Form 10-K report. The risk factors could
cause our actual results to differ materially from those contained in any
forward-looking statement. We disclaim any obligation to update the above list
or to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments. 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 June 30, 2004, our management, including our Chief Executive Officer and
Chief Financial Officer, has evaluated the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to Rule 13a-15(b)
under the Securities Exchange Act of 1934. There are inherent limitations to the
effectiveness of any system of disclosure controls and procedures, including the
possibility of human error and the circumvention or overriding of the controls
and procedures. Accordingly, even effective disclosure controls and procedures
can only provide reasonable assurance of achieving their control objectives.
Based upon and as of the date of the evaluation, our Chief Executive Officer and
our Chief Financial Officer concluded that the design and operation of our
disclosure controls and procedures were effective in all material respects to
provide reasonable assurance that information required to be disclosed in the
reports we file and submit under the Exchange Act is recorded, processed,
summarized and reported as and when required. There has been no change in our
internal control over financial reporting during the quarter ended June 30, 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.
As previously disclosed, on July 21, 2004, Michael C. Morgan resigned as
President of our general partner and its delegate. In connection with his
resignation, Mr. Morgan executed a Resignation and Non-Compete Agreement
pursuant to which Mr. Morgan resigned, agreed not to compete with us or our
affiliates through July 21, 2008, and forfeited 76,667 shares of KMI restricted
stock granted in July 2003 that would have vested in July 2006 and July 2008.
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.
10.1 -- Resignation and Non-Compete agreement dated July 21, 2004 between KMGP
Services, Inc. and Michael C. Morgan, President of Kinder Morgan, Inc.,
Kinder Morgan G.P., Inc. and Kinder Morgan Management, LLC.
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.
62
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(b) Reports on Form 8-K
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.
Current report dated July 21, 2004 on Form 8-K was filed on July 21, 2004,
pursuant to Items 7 and 12 of that form. In Item 12, we provided notice that on
July 21, 2004, we issued a press release regarding our financial results for the
quarter and six months ended June 30, 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: August 5, 2004
64