F O R M 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2003
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 1-11234
KINDER MORGAN ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0380342
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
500 Dallas Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-369-9000
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X] No [ ]
The Registrant had 134,721,558 common units outstanding at October 31, 2003.
1
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
PART I. FINANCIAL INFORMATION
Item 1: Financial Statements (Unaudited).................................. 3
Consolidated Statements of Income - Three and Nine Months Ended
September 30, 2003 and 2002...................................... 3
Consolidated Balance Sheets - September 30, 2003 and December 31,
2002............................................................. 4
Consolidated Statements of Cash Flows - Nine Months Ended
September 30, 2003 and 2002...................................... 5
Notes to Consolidated Financial Statements....................... 6
Item 2: Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................. 41
Results of Operations............................................ 41
Financial Condition.............................................. 52
Information Regarding Forward-Looking Statements................. 56
Item 3: Quantitative and Qualitative Disclosures About Market Risk........ 58
Item 4: Controls and Procedures........................................... 58
` PART II. OTHER INFORMATION
Item 1: Legal Proceedings................................................. 59
Item 2: Changes in Securities and Use of Proceeds......................... 59
Item 3: Defaults Upon Senior Securities................................... 59
Item 4: Submission of Matters to a Vote of Security Holders............... 59
Item 5: Other Information................................................. 59
Item 6: Exhibits and Reports on Form 8-K.................................. 59
Signatures........................................................ 61
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 Sept. 30, Nine Months Ended Sept. 30,
---------------------------- ---------------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
Revenues
Natural gas sales............................................ $1,209,888 $ 740,377 $3,827,246 $1,932,774
Services..................................................... 344,826 357,111 1,026,655 960,399
Product sales and other...................................... 96,128 23,832 250,226 122,148
---------- ---------- ---------- ----------
1,650,842 1,121,320 5,104,127 3,015,321
---------- ---------- ---------- ----------
Costs and Expenses
Gas purchases and other costs of sales....................... 1,212,200 729,773 3,822,989 1,890,342
Operations and maintenance................................... 98,089 92,644 293,763 278,399
Fuel and power............................................... 29,476 24,932 78,393 64,463
Depreciation, depletion and amortization..................... 55,031 42,546 158,594 126,495
General and administrative................................... 35,547 27,476 104,383 87,218
Taxes, other than income taxes............................... 15,534 14,546 46,326 40,798
---------- ---------- ---------- ----------
1,445,877 931,917 4,504,448 2,487,715
---------- ---------- ---------- ----------
Operating Income............................................... 204,965 189,403 599,679 527,606
Other Income (Expense)
Earnings from equity investments............................. 20,841 22,818 67,764 70,386
Amortization of excess cost of equity investments............ (1,394) (1,394) (4,182) (4,182)
Interest, net................................................ (44,714) (46,350) (134,535) (129,236)
Other, net................................................... 972 232 2,757 617
Minority Interest.............................................. (2,591) (2,410) (6,930) (7,458)
---------- ---------- ---------- ----------
Income Before Income Taxes and Cumulative Effect of a Change in
Accounting Principle........................................ 178,079 162,299 524,553 457,733
Income Taxes................................................... (3,903) (4,119) (14,407) (13,603)
---------- ---------- ---------- ----------
Income Before Cumulative Effect of a Change in Accounting 174,176 158,180 510,146 444,130
Principle.......................................................
Cumulative effect adjustment from change in accounting for asset
retirement obligations...................................... - - 3,465 -
---------- ---------- ---------- ----------
Net Income..................................................... $ 174,176 $ 158,180 $ 513,611 $ 444,130
========== ========== ========== ==========
Calculation of Limited Partners' interest in Net Income:
Income Before Cumulative Effect of a Change in Accounting $ 174,176 $ 158,180 $ 510,146 $ 444,130
Principle.......................................................
Less: General Partner's interest............................... (82,727) (70,380) (239,682) (197,408)
---------- ---------- ---------- ----------
Limited Partners' interest..................................... 91,449 87,800 270,464 246,722
Add: Limited Partners' interest in Change in Accounting Principle - - 3,430 -
---------- ---------- ---------- ----------
Limited Partners' interest in Net Income....................... $ 91,449 $ 87,800 $ 273,894 $ 246,722
========== ========== ========== ==========
Basic and Diluted Limited Partners' Net Income per Unit:
Income Before Cumulative Effect of a Change in Accounting $ 0.49 $ 0.50 $ 1.47 $ 1.46
Principle.......................................................
Cumulative effect adjustment from change in accounting for asset
retirement obligations...................................... - - 0.02 -
---------- ---------- ---------- ----------
Net Income..................................................... $ 0.49 $ 0.50 $ 1.49 $ 1.46
========== ========== ========== ==========
Weighted average number of units used in computation of Limited
Partners' Net Income per unit:
Basic.......................................................... 187,813 174,781 184,285 169,171
========== ========== ========== ==========
Diluted........................................................ 187,912 174,932 184,400 169,345
========== ========== ========== ==========
The accompanying notes are an integral part of these consolidated financial statements.
3
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
September 30, December 31,
2003 2002
------------- ------------
Assets
Current Assets
Cash and cash equivalents................ $ 42,445 $ 41,088
Accounts and notes receivable
Trade.................................. 534,632 457,583
Related parties........................ 17,653 17,907
Inventories
Products............................... 3,923 4,722
Materials and supplies................. 9,835 7,094
Gas imbalances........................... 40,102 25,488
Gas in underground storage............... 3,988 11,029
Other current assets..................... 30,624 104,479
------------ ------------
683,202 669,390
Property, Plant and Equipment, net.......... 6,632,302 6,244,242
Investments................................. 406,378 451,374
Notes receivable............................ 2,870 3,823
Goodwill.................................... 729,510 716,610
Other intangibles, net...................... 17,253 17,324
Deferred charges and other assets........... 209,282 250,813
------------ ------------
Total Assets................................ $ 8,680,797 $ 8,353,576
============ ============
Liabilities and Partners' Capital
Current Liabilities
Accounts payable
Trade.................................. $ 428,109 $ 373,368
Related parties........................ 355 43,742
Current portion of long-term debt........ 86,240 -
Accrued interest......................... 21,028 52,500
Deferred revenues........................ 7,201 4,914
Gas imbalances........................... 50,382 40,092
Accrued other current liabilities........ 204,091 298,711
------------ ------------
797,406 813,327
------------ ------------
Long-Term Liabilities and Deferred Credits
Long-term debt, outstanding.............. 3,855,803 3,659,533
Market value of interest rate swaps...... 140,903 166,956
------------ ------------
3,996,706 3,826,489
Deferred revenues........................ 23,504 25,740
Deferred income taxes.................... 31,705 30,262
Other long-term liabilities and deferred
credits.................................. 217,964 199,796
------------ ------------
4,269,879 4,082,287
------------ ------------
Commitments and Contingencies (Note 3)
Minority Interest........................... 44,144 42,033
------------ ------------
Partners' Capital
Common Units............................. 1,963,611 1,844,553
Class B Units............................ 121,360 123,635
i-Units.................................. 1,490,659 1,420,898
General Partner.......................... 80,631 72,100
Accumulated other comprehensive loss..... (86,893) (45,257)
------------ ------------
3,569,368 3,415,929
------------ ------------
Total Liabilities and Partners' Capital..... $ 8,680,797 $ 8,353,576
============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
4
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Increase/(Decrease) in Cash and Cash Equivalents In Thousands)
(Unaudited)
Nine Months Ended Sept. 30,
-------------------------------
2003 2002
----------- ----------
Cash Flows From Operating Activities
Net income............................................... $ 513,611 $ 444,130
Adjustments to reconcile net income to net cash provided by
operating activities:
Cumulative effect adjustment from change in accounting
for asset retirement obligations................... (3,465) --
Depreciation, depletion and amortization............. 158,594 126,495
Amortization of excess cost of equity investments.... 4,182 4,182
Earnings from equity investments..................... (67,764) (70,386)
Distributions from equity investments................ 61,084 58,920
Changes in components of working capital............. (107,284) (2,521)
FERC rate reparations and refunds.................... (44,944) --
Other, net........................................... (6,760) (14,551)
----------- ----------
Net Cash Provided by Operating Activities................ 507,254 546,269
----------- ----------
Cash Flows From Investing Activities
Acquisitions of assets............................... (40,714) (864,311)
Acquisitions of investments.......................... (10,000) --
Additions to property, plant and equipment for expansio
and maintenance projects.......................... (413,228) (342,562)
Sale of investments, property, plant and equipment,
net of removal costs.............................. 2,118 1,710
Contributions to equity investments.................. (11,210) (14,481)
Other................................................ 8,904 1,289
----------- ----------
Net Cash Used in Investing Activities.................... (464,130) (1,218,355)
----------- ----------
Cash Flows From Financing Activities
Issuance of debt..................................... 3,162,365 3,205,414
Payment of debt...................................... (2,880,518) (2,432,731)
Debt issue costs..................................... (1,119) (14,180)
Proceeds from issuance of common units............... 175,336 1,464
Proceeds from issuance of i-units.................... - 331,159
Contributions from General Partner................... 1,764 3,353
Distributions to partners:
Common units..................................... (252,011) (227,327)
Class B units.................................... (10,175) (9,298)
General Partner.................................. (231,186) (182,742)
Minority interest................................ (7,345) (7,365)
Other, net........................................... 1,122 3,917
----------- ----------
Net Cash (Used in)/Provided by Financing Activities...... (41,767) 671,664
----------- ----------
Increase/(Decrease) in Cash and Cash Equivalents......... 1,357 (422)
Cash and Cash Equivalents, beginning of period........... 41,088 62,802
----------- ----------
Cash and Cash Equivalents, end of period................. $ 42,445 $ 62,380
=========== ==========
Noncash Investing and Financing Activities:
Assets acquired by the assumption of liabilities $ 1,978 $ 153,430
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 that are, in the
opinion of our management, necessary for a fair presentation of our financial
results for the interim periods. You should read these consolidated financial
statements in conjunction with our consolidated financial statements and related
notes included in our Annual Report on Form 10-K for the year ended December 31,
2002.
Kinder Morgan, Inc. and Kinder Morgan Management, LLC
Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of
Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware
corporation, is the sole stockholder of our general partner, Kinder Morgan G.P.,
Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report.
Kinder Morgan Management, LLC, a Delaware limited liability company, was
formed on February 14, 2001. Our general partner owns all of Kinder Morgan
Management, LLC's voting securities and, pursuant to a delegation of control
agreement, our general partner delegated to Kinder Morgan Management, LLC, to
the fullest extent permitted under Delaware law and our partnership agreement,
all of its power and authority to manage and control the business and affairs of
us, our operating limited partnerships and their subsidiaries. Kinder Morgan
Management, LLC cannot take certain specified actions without the approval of
our general partner and its activities are limited to being a limited partner
in, and managing and controlling the business and affairs of, us, our operating
limited partnerships and their subsidiaries. Kinder Morgan Management, LLC is
referred to as "KMR" in this report.
Basis of Presentation
Our consolidated financial statements include our accounts and those of our
majority-owned and controlled subsidiaries and our operating partnerships. All
significant intercompany items have been eliminated in consolidation.
Certain amounts from prior periods have been reclassified to conform to the
current presentation. On January 1, 2002, we adopted Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible Assets" and we
reclassified to goodwill from investments the $140.3 million of total
unamortized excess cost over underlying fair value of net assets accounted for
under the equity method. However, pursuant to SFAS No. 142, this amount,
referred to as equity method goodwill, should continue to be recognized in
accordance with Accounting Principles Board Opinion No. 18, "The Equity Method
of Accounting for Investments in Common Stock." According to APB No. 18, equity
method goodwill should not be treated as being separable from the related
investment and should not be tested for impairment under SFAS No. 142, but
rather, tested under APB No. 18. 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."
Accordingly, we have elected to reverse our original reclassification of the
$140.3 million of equity method goodwill as of January 1, 2002 from our
investments to our goodwill. Compared to the amounts previously reported in our
Annual Report on Form 10-K for the year ended December 31, 2002, this reversal
has resulted in an increase to "Investments" and a decrease in "Goodwill" in the
amount of $140.3 million on our consolidated balance sheet as of December 31,
2002.
6
Net Income Per Unit
We compute Basic Limited Partners' Net Income per Unit by dividing our
limited partners' interest in net income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the potential dilution, by application of the treasury stock method,
that could occur if options to issue units were exercised, which would result in
the issuance of additional units that would then share in our net income.
Asset Retirement Obligations
As of January 1, 2003, we account for asset retirement obligations pursuant
to SFAS No. 143, "Accounting for Asset Retirement Obligations." For more
information on our asset retirement obligations, see Note 4.
2. Acquisitions and Joint Ventures
During the first nine months of 2003, we completed or made adjustments for
the following significant acquisitions. Each of the acquisitions was accounted
for under the purchase method and the assets acquired and liabilities assumed
were recorded at their estimated fair market values as of the acquisition date.
The preliminary 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.
Bulk Terminals from M.J. Rudolph
Effective January 1, 2003, we acquired long-term lease contracts from New
York-based M.J. Rudolph Corporation to operate four bulk terminal facilities at
major ports along the East Coast and in the southeastern United States. The
acquisition also includes the purchase of certain assets that provide
stevedoring services at these locations. The aggregate cost of the acquisition
was approximately $31.3 million. On December 31, 2002, we paid $29.9 million for
the Rudolph acquisition and this amount was included with "Other current assets"
on our accompanying consolidated balance sheet. In the first quarter of 2003, we
paid the remaining $1.4 million and we allocated our aggregate purchase price to
the appropriate asset and liability accounts. The acquired operations serve
various terminals located at the ports of New York and Baltimore, along the
Delaware River in Camden, New Jersey, and in Tampa Bay, Florida. Combined, these
facilities transload nearly four million tons annually of products such as
fertilizer, iron ore and salt. The acquisition expanded our growing Terminals
business segment and complements certain of our existing terminal facilities. In
our final analysis, it was considered reasonable to allocate a portion of our
purchase price to goodwill given the substance of this transaction, in
particular the synergies, and we include its operations in our Terminals
business segment.
Our allocation of the purchase price to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs.... $ 31,337
Liabilities assumed....................... 6
--------
Total purchase price...................... $ 31,343
========
Allocation of purchase price:
Current assets............................ $ 84
Property, plant and equipment............. 18,250
Intangibles-agreements ................... 100
Deferred charges and other assets ........ 9
Goodwill ................................. 12,900
--------
$ 31,343
========
MKM Partners, L.P.
On June 20, 2003, we signed an agreement with subsidiaries of Marathon Oil
Corporation to dissolve MKM Partners, L.P., a joint venture we formed on January
1, 2001 with subsidiaries of Marathon Oil Company. The joint venture assets
consisted of a 12.75% interest in the SACROC oil field unit and a 49.9% interest
in the Yates Field
7
unit, both of which are in the Permian Basin of West Texas. The MKM joint
venture was owned 85% by subsidiaries of Marathon Oil Company and 15% by Kinder
Morgan CO2 Company, L.P. It was dissolved effective June 30, 2003, and the net
assets were distributed to creditors and partners in accordance with its
partnership agreement.
Effective June 1, 2003, we acquired the MKM joint venture's 12.75% ownership
interest in the SACROC unit for $23.3 million and the assumption of $1.9 million
of liabilities. The SACROC unit is one of the largest and oldest oil fields in
the United States using carbon dioxide flooding technology. This transaction
increased our ownership interest in the SACROC unit to approximately 97%.
Our allocation of the purchase price to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs.... $ 23,302
Liabilities assumed....................... 1,905
--------
Total purchase price...................... $ 25,207
========
Allocation of purchase price:
Property, plant and equipment............. $ 25,207
--------
$ 25,207
========
IC Terminal Holdings Company
Effective September 1, 2002, we acquired all of the shares of the capital
stock of IC Terminal Holdings Company from the Canadian National Railroad. Our
purchase price was $17.7 million, consisting of $17.4 million and the assumption
of $0.3 million in liabilities. The total purchase price decreased $0.2 million
in the third quarter of 2003 primarily due to adjustments in the amount of
working capital items assumed on the acquisition date. The acquisition included
the former ICOM marine terminal in St. Gabriel, Louisiana. The St. Gabriel
facility has 400,000 barrels of liquids storage capacity and a related pipeline
network that serves one of the fastest growing petrochemical production areas in
the country. The acquisition further expanded our terminal businesses along the
Mississippi River. The acquired terminal is referred to as the Kinder Morgan St.
Gabriel terminal, and we include its operations in our Terminals business
segment.
Our allocation of the purchase price to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction
costs.............................. $ 17,372
Liabilities assumed................ 326
--------
Total purchase price............... $ 17,698
========
Allocation of purchase price:
Current assets..................... $ 46
Property, plant and equipment...... 14,303
Investment in ICPT, LLC............ 1,785
Non-current note receivable........ 1,350
Deferred charges and other assets.. 214
--------
$ 17,698
========
Owensboro Gateway Terminal
Effective September 1, 2002, we acquired the Lanham River Terminal near
Owensboro, Kentucky and related equipment for $7.7 million. In September 2002,
we paid approximately $7.2 million and established a $0.5 million purchase price
retention liability to be paid at the later of: (i) one year following the
acquisition, or (ii) the day we received consent to the assignment of a contract
between the seller and the New York Mercantile Exchange, Inc. We paid the $0.5
million liability in September 2003.
The facility is one of the nation's largest storage and handling points for
bulk aluminum. The terminal also handles a variety of other bulk products,
including petroleum coke, lime and de-icing salt. The terminal is situated on a
92-acre site along the Ohio River, and the purchase expands our presence along
the river, complementing our existing facilities located near Cincinnati, Ohio
and Moundsville, West Virginia. We refer to the acquired terminal as our
Owensboro Gateway Terminal and we include its operations in our Terminals
business segment.
8
Our allocation of the purchase price to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction
costs............................. $ 7,640
Liabilities assumed................ 11
--------
Total purchase price............... $ 7,651
========
Allocation of purchase price:
Current assets..................... $ 42
Property, plant and equipment...... 4,265
Intangibles-agreements............. 54
Goodwill........................... 3,290
--------
$ 7,651
========
The $3.3 million of goodwill was assigned to our Terminals business segment
and the entire amount is expected to be deductible for tax purposes.
Red Cedar Gas Gathering Company
Effective August 1, 2003, we acquired reversionary interests in the Red Cedar
Gas Gathering Company held by the Southern Ute Indian Tribe. Our purchase price
was $10.0 million. The 4% reversionary interests were held by the Southern Ute
Indian Tribe and were scheduled to take effect September 1, 2004 and September
1, 2009. With the elimination of these reversions, our ownership interest in Red
Cedar will be maintained at 49% in the future.
Our allocation of the purchase price to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction
costs............................ $ 10,000
--------
Total purchase price............... $ 10,000
========
Allocation of purchase price:
Investments........................ $ 10,000
--------
$ 10,000
========
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement
information for the nine months ended September 30, 2003 and 2002, assumes that
all of the acquisitions we have made since January 1, 2002, including the ones
listed above, had occurred as of January 1, 2002. We have prepared these
unaudited pro forma financial results for comparative purposes only. These
unaudited pro forma financial results may not be indicative of the results that
would have occurred if we had completed these acquisitions as of January 1, 2002
or the results that will be attained in the future. Amounts presented below are
in thousands, except for the per unit amounts:
Pro Forma
Nine Months Ended
September 30,
----------------------------
2003 2002
---- ----
(Unaudited)
Revenues................................................................... $ 5,112,861 $ 3,288,941
Operating Income........................................................... 603,034 544,095
Income Before Cumulative Effect of a Change in Accounting Principle........ 513,344 462,014
Net Income................................................................. $ 516,809 $ 462,014
Basic and diluted Limited Partners' Net Income per unit:
Income Before Cumulative Effect of a Change in Accounting Principle..... $ 1.48 $ 1.42
Net Income.............................................................. $ 1.50 $ 1.42
9
Acquisitions Subsequent to September 30, 2003
Shell Products Terminals
Effective October 1, 2003, we acquired five refined petroleum products
terminals in the western United States for approximately $20.0 million from
Shell Oil Products U.S. Following our acquisition, we plan to invest an
additional $8.0 million in the facilities. The terminals are located in Colton
and Mission Valley, California; Phoenix and Tucson, Arizona; and Reno, Nevada.
Combined, the terminals have 28 storage tanks with total capacity of
approximately 700,000 barrels for gasoline, diesel fuel and jet fuel. As part of
the transaction, Shell has entered into a long-term contract to store products
in the terminals. The acquisition enhances our Pacific operations and
complements our existing West Coast Terminals. The acquired operations will be
included as part of our Pacific operations and our Products Pipelines business
segment. This acquisition had no effect on our consolidated financial statements
during the periods covered by these financial statements.
Our allocation of the purchase price to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction
costs............................. $ 20,022
--------
Total purchase price............... $ 20,022
========
Allocation of purchase price:
Property, plant and equipment...... $ 20,022
--------
$ 20,022
========
Yates Field Unit and Carbon Dioxide Assets
Effective November 1, 2003, we acquired certain assets in the Permian Basin
of West Texas for approximately $227.5 million from a subsidiary of Marathon Oil
Corporation. The assets acquired consisted of the following:
o Marathon's approximate 42.5% interest in the Yates oil field unit for
approximately $212.5 million. We previously owned a 7.5% ownership interest
in the Yates field unit and we will now become operator of the field;
o Marathon's 100% interest in the crude oil gathering system surrounding the
Yates field for approximately $13.0 million; and
o Marathon Carbon Dioxide Transportation Company for approximately $2.0
million. Marathon 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.
3. Litigation and Other Contingencies
Federal Energy Regulatory Commission Proceedings
SFPP, L.P.
SFPP, L.P., referred to herein as SFPP, is the subsidiary limited partnership
that owns our Pacific operations, excluding CALNEV Pipe Line LLC and related
terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to
certain proceedings at the FERC involving shippers' complaints regarding the
interstate rates, as well as practices and the jurisdictional nature of certain
facilities and services, on our Pacific operations' pipeline systems. Generally,
the interstate rates on our Pacific operations' pipeline systems are
"grandfathered" under the Energy Policy Act of 1992 unless "substantially
changed circumstances" are found to exist. To the extent "substantially changed
circumstances" are found to exist, our Pacific operations may be subject to
substantial
10
exposure under these FERC complaints.
The complainants in the proceedings before the FERC have alleged a variety of
grounds for finding "substantially changed circumstances." Applicable rules and
regulations in this field are vague, relevant factual issues are complex, and
there is little precedent available regarding the factors to be considered or
the method of analysis to be employed in making a determination of
"substantially changed circumstances." If SFPP rates previously "grandfathered"
under the Energy Policy Act lose their "grandfathered" status and are found to
be unjust and unreasonable, shippers may be entitled to prospective rate
reductions and complainants may be entitled to reparations for periods from the
date of their respective complaint to the date of the implementation of the new
rates.
On June 24, 2003, a non-binding, phase one initial decision was issued by an
administrative law judge hearing a FERC case on the rates charged by SFPP on the
interstate portion of its pipelines (see OR96-2 section below for further
discussion). In his phase one initial decision, the administrative law judge
recommended that the FERC "ungrandfather" SFPP's interstate rates and found most
of SFPP's rates at issue to be unjust and unreasonable. The administrative law
judge has indicated that a phase two initial decision will address prospective
rates and whether reparations are necessary.
Initial decisions have no force or effect and must be reviewed by the FERC.
The FERC is not obliged to follow any of the administrative law judge's findings
and can accept or reject this initial decision in whole or in part. In addition,
as stated above, the facts are complex, the rules and regulations in this area
are vague and little precedent exists. If the FERC ultimately finds that these
rates should be "ungrandfathered" and are unjust and unreasonable, they could be
lowered prospectively and complaining shippers could be entitled to reparations
for prior periods. Resolution of this matter by the FERC is not expected before
late 2004.
We currently believe that these FERC complaints seek approximately $154
million in tariff reparations and prospective annual tariff reductions, the
aggregate average annual impact of which would be approximately $45 million. As
the length of time from the filing of the complaints increases, the amounts
sought by complainants in tariff reparations will likewise increase until a
determination of reparations owed is made by the FERC. 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
administrative law judge's initial decision does not change our estimate of what
the complainants seek. Furthermore, even if "substantially changed
circumstances" are found to exist, we believe that the resolution of these FERC
complaints will be for amounts substantially less than the amounts sought and
that the resolution of such matters will not have a material adverse effect on
our business, financial position, results of operations or cash flows.
OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a
consolidated proceeding that began in September 1992 and includes a number of
shipper complaints against certain rates and practices on SFPP's East Line (from
El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California
to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson
Station in Carson, California. The complainants in the case are El Paso
Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company,
Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products
Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing
Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.),
Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco
Corporation (now part of ConocoPhillips Company). The FERC has ruled that the
complainants have the burden of proof in those proceedings.
A FERC administrative law judge held hearings in 1996, and issued an initial
decision in September 1997. The initial decision held that all but one of SFPP's
West Line rates were "grandfathered" under the Energy Policy Act of 1992 and
therefore deemed to be just and reasonable; it further held that complainants
had failed to prove "changed circumstances" with respect to those rates and that
they therefore could not be challenged in the Docket No. OR92-8 et al.
proceedings, either for the past or prospectively. However, the initial decision
also made rulings generally adverse to SFPP on certain cost of service issues
relating to the evaluation of East Line rates, which are not "grandfathered"
under the Energy Policy Act. Those issues included the capital structure to be
used in computing SFPP's "starting rate base," the level of income tax allowance
SFPP may include in rates and the recovery of civil 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
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to file a tariff for that service.
The FERC subsequently reviewed the initial decision, and issued a series of
orders in which it adopted certain rulings made by the administrative law judge,
changed others and modified a number of its own rulings on rehearing. Those
orders began in January 1999, with FERC Opinion No. 435, and continued through
June 2003.
The FERC affirmed that all but one of SFPP's West Line rates are
"grandfathered" and that complainants had failed to satisfy the threshold burden
of demonstrating "changed circumstances" necessary to challenge those rates. The
FERC further held that the one West Line rate that was not grandfathered did not
need to be reduced. The FERC consequently dismissed all complaints against the
West Line rates in Docket Nos. OR92-8 et al. without any requirement that SFPP
reduce, or pay any reparations for, any West Line rate.
The FERC initially modified the initial decision's ruling regarding the
capital structure to be used in computing SFPP's "starting rate base" to be more
favorable to SFPP, but later reversed that ruling. The FERC also made certain
modifications to the calculation of the income tax allowance and other cost of
service components, generally to SFPP's disadvantage.
On multiple occasions, the FERC required SFPP to file revised East Line rates
based on rulings made in the FERC's various orders. SFPP was also directed to
submit compliance filings showing the calculation of the revised rates, the
potential reparations for each complainant and in some cases potential refunds
to shippers. SFPP filed such revised East Line rates and compliance filings in
March 1999, July 2000, November 2001 (revised December 2001), October 2002 and
February 2003 (revised March 2003). Most of those filings were protested by
particular SFPP shippers. The FERC has held that certain of the rates SFPP filed
at the FERC's directive should be reduced retroactively and/or be subject to
refund; SFPP has challenged the FERC's authority to impose such requirements in
this context.
While the FERC initially permitted SFPP to recover certain of its litigation,
pipeline reconditioning and environmental costs, either through a surcharge on
prospective rates or as an offset to potential reparations, it ultimately
limited recovery in such a way that SFPP was not able to make any such surcharge
or take any such offset. Similarly, the FERC initially ruled that SFPP would not
owe reparations to any complainant for any period prior to the date on which
that party's complaint was filed, but ultimately held that each complainant
could recover reparations for a period extending two years prior to the filing
of its complaint (except for Navajo, which was limited to one month of
pre-complaint reparations under a settlement agreement with SFPP's predecessor).
The FERC also ultimately held that SFPP was not required to pay reparations or
refunds for Watson Station gathering enhancement fees charged prior to filing a
FERC tariff for that service.
In April 2003, SFPP paid complainants and other shippers reparations and/or
refunds as required by FERC's orders. In August 2003, SFPP paid shippers an
additional refund as required by FERC's most recent order in the Docket No.
OR92-8 et al. proceedings. As of September 30, 2003, we have made payments of
$44.9 million in 2003 for reparations and refunds under order from the FERC.
Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond
Shamrock (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. The Court of
Appeals has designated the case as "complex" under its case management plan and
has set oral argument for November 12, 2003.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC
(Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines (Line
Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject
to FERC's jurisdiction under the Interstate Commerce Act, and, if so, claimed
that the rate for that service was unlawful. Several other West Line shippers
filed similar complaints and/or motions to intervene.
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Following a hearing in March 1997, a FERC administrative law judge issued an
initial decision holding that the movements on the Sepulveda pipelines were not
subject to FERC jurisdiction. On August 5, 1997, the FERC reversed that
decision. On October 6, 1997, SFPP filed a tariff establishing the initial
interstate rate for movements on the Sepulveda pipelines at the pre-existing
rate of five cents per barrel. Several shippers protested that rate. In December
1997, SFPP filed an application for authority to charge a market-based rate for
the Sepulveda service, which application was protested by several parties. On
September 30, 1998, the FERC issued an order finding that SFPP lacks market
power in the Watson Station destination market and set a hearing to determine
whether SFPP possessed market power in the origin market.
Following a hearing on December 21, 2000, an administrative law judge found
that SFPP possessed market power over the Sepulveda origin market. On February
28, 2003, the FERC issued an order upholding that decision. SFPP filed a request
for rehearing of that order on March 31, 2003. The FERC denied SFPP's request
for rehearing on July 9, 2003.
As part of its February 28, 2003 order denying SFPP's application for
market-based ratemaking authority, the FERC remanded to the ongoing litigation
in Docket No. OR96-2, et al. the question of whether SFPP's current rate for
service on the Sepulveda line is just and reasonable. That issue is currently
pending before the administrative law judge in the Docket No. OR96-2, et al.
proceeding. The procedural schedule in this remanded matter is currently
suspended pending issuance of the phase two initial decision in the Docket No.
OR96-2, et al. proceeding (see below).
OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar filed a
complaint at FERC (Docket No. OR97-2) challenging SFPP's West Line rates,
claiming they were unjust and unreasonable and no longer subject to
grandfathering. In October 1997, ARCO, Mobil and Texaco filed a complaint at the
FERC (Docket No. OR98-1) challenging the justness and reasonableness of all of
SFPP's interstate rates, raising claims against SFPP's East and West Line rates
similar to those that have been at issue in Docket Nos. OR92-8, et al. discussed
above, but expanding them to include challenges to SFPP's grandfathered
interstate rates from the San Francisco Bay area to Reno, Nevada and from
Portland to Eugene, Oregon - the North Line and Oregon Line. In November 1997,
Ultramar Diamond Shamrock Corporation filed a similar, expanded complaint
(Docket No. OR98-2). Tosco Corporation filed a similar complaint in April 1998.
The shippers seek both reparations and prospective rate reductions for movements
on all of the lines. 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 RHC filed complaints against SFPP's East Line
rates and Ultramar filed an additional complaint updating its pre-existing
challenges to SFPP's interstate pipeline rates. 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 fourth quarter of 2003 or the first quarter of 2004.
SFPP has filed a brief on exceptions to the FERC that contests the findings
in the initial decision. SFPP's opponents have responded to SFPP's brief.
Resolution of this matter by the FERC is not expected before late 2004.
OR02-4 proceedings. On February 11, 2002, Chevron, an intervenor in the
OR96-2 proceeding, filed a complaint against SFPP in Docket No. OR02-4 along
with a motion to consolidate the complaint with the OR96-2
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proceeding. On May 21, 2002, the FERC dismissed Chevron's complaint and motion
to consolidate. Chevron filed a request for rehearing and on September 25, 2002,
the FERC dismissed Chevron's rehearing request. In October 2002, Chevron filed a
request for rehearing of the FERC's September 25, 2002 Order. On May 23, 2003,
the FERC denied Chevron's rehearing request and on July 1, 2003, Chevron filed
an appeal of this denial at the U.S. Court of Appeals for the District of
Columbia Circuit, which appeal is currently pending. 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 is pending before the Court.
Chevron continues to participate in the OR96-2 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 OR96-2 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. 02-4, which
was previously dismissed by the FERC. By this request, Chevron sought to, in
effect, back-date its complaint, and claim for reparations, to February 2002.
SFPP answered Chevron's complaint on July 22, 2003, opposing Chevron's requests
for consolidation and for the back-dating of its complaint. At its October 22,
2003 meeting, 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 consolidating and for back-dating.
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 second 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
14
transportation rates, will be the subject of evidentiary hearings to be
conducted in December 2003 and are expected to be resolved by the CPUC by the
second 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 or estimate the amount of
dollars potentially subject to refund as a consequence of the CPUC resolution
requiring the provision by SFPP of cost-of-service data. SFPP believes that
submission of the required, representative cost data required by the CPUC will
indicate that SFPP's existing rates for California intrastate services remain
reasonable and that no refunds are justified.
We believe that the resolution of such matters will not have a material
adverse effect on our business, financial position, results of operations or
cash flows.
Trailblazer Pipeline Company
As required by its last rate case settlement, Trailblazer Pipeline Company
made a general rate case filing at the FERC on November 29, 2002. The filing
provides for a small rate decrease and also includes a number of non-rate tariff
changes. By an order issued December 31, 2002, FERC effectively bifurcated the
proceeding. The rate change was accepted to be effective on January 1, 2003,
subject to refund and a hearing. Most of the non-rate tariff changes were
suspended until June 1, 2003, subject to refund and a technical conference
procedure.
Trailblazer sought rehearing of the FERC order with respect to the refund
condition on the rate decrease. On April 15, 2003, the FERC granted
Trailblazer's rehearing request to remove the refund condition that had been
imposed in the December 31, 2002 Order. Certain intervenors have sought
rehearing as to the FERC's acceptance of certain non-rate tariff provisions. A
prehearing conference on the rate issues was held on January 16, 2003, where a
procedural schedule was established.
The technical conference on non-rate issues was held on February 6, 2003.
Those issues include:
- capacity award procedures;
- credit procedures;
- imbalance penalties; and
- the maximum length of bid terms considered for evaluation in the right of
first refusal process.
Comments on these issues as discussed at the technical conference were filed
by parties in March 2003. On May 23, 2003, FERC issued an order deciding
non-rate tariff issues and denying rehearing of its prior order. In the May 23,
2003 order, FERC:
- accepted Trailblazer's proposed capacity award procedures with very limited
changes;
- accepted Trailblazer's credit procedures subject to very extensive changes,
consistent with numerous recent orders involving other pipelines;
- 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 10 years (in lieu of the current 5 years); and
- accepted Trailblazer's withdrawal of daily imbalance charges.
The referenced order did the following:
- allowed shortened notice periods for suspension of service, but required at
least 30 days notice for service termination;
15
- 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;
- required the pipeline to pay interest on prepayments or allow those funds
to go into an interest-bearing escrow account; and
- required much more specificity about credit criteria and procedures in
tariff provisions.
Certain shippers have sought rehearing of the May 23, 2003 order. Trailblazer
made its compliance filing on June 20, 2003. Under the May 23, 2003 order, these
tariff changes are effective as of May 23, 2003, except that Trailblazer has
filed to make the revised credit procedures effective August 15, 2003.
With respect to the on-going rate review phase of the case, direct testimony
was filed by FERC Staff and Indicated Shippers on May 22, 2003 and
cross-answering testimony was filed by 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. Under the settlement, if approved by the FERC, Trailblazer's rate would be
reduced effective January 1, 2004, from about $0.12 to $0.09 per dekatherm of
natural gas, and Trailblazer would file a new rate case to be effective January
1, 2010. We do not expect the settlement to have a material effect on our
consolidated revenues in 2004 or in subsequent periods. Based on the comments,
this settlement is supported or not opposed by all participants including the
FERC staff, except for certain members of the Indicated Shippers group
(Marathon, BP), referred to hereafter as contesting parties. On October 3, 2003,
the presiding administrative law judge certified the settlement to the FERC and
severed the contesting parties.
The contesting parties filed rebuttal testimony on September 22, 2003. The
trial took place from October 8-10, 2003, and involved only Trailblazer and the
contesting parties. The FERC staff did not participate. Initial and reply briefs
are due on November 21, 2003 and December 19, 2003, respectively.
FERC Order 637
Kinder Morgan Interstate Gas Transmission LLC
On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its
filing to comply with FERC's Orders 637 and 637-A. That filing contained KMIGT's
compliance plan to implement the changes required by the FERC dealing with the
way business is conducted on interstate natural gas pipelines. All interstate
natural gas pipelines were required to make such compliance filings, according
to a schedule established by the FERC. From October 2000 through June 2001,
KMIGT held a series of technical and phone conferences to identify issues,
obtain input, and modify its Order 637 compliance plan, based on comments
received from FERC staff and other interested parties and shippers. On June 19,
2001, KMIGT received a letter from the FERC encouraging it to file revised
pro-forma tariff sheets, which reflected the latest discussions and input from
parties into its Order 637 compliance plan. KMIGT made such a revised Order 637
compliance filing on July 13, 2001. The July 13, 2001 filing contained little
substantive change from the original pro-forma tariff sheets that KMIGT
originally proposed on June 15, 2000. On October 19, 2001, KMIGT received an
order from the FERC, addressing its July 13, 2001 Order 637 compliance plan. In
the Order addressing the July 13, 2001 compliance plan, KMIGT's plan was
accepted, but KMIGT was directed to make several changes to its tariff, and in
doing so, was directed that it could not place the revised tariff into effect
until further order of the FERC. KMIGT filed its compliance filing with the
October 19, 2001 Order on November 19, 2001 and also filed a request for
rehearing/clarification of the FERC's October 19, 2001 Order on November 19,
2001. Several parties protested the November 19, 2001 compliance filing. KMIGT
filed responses to those protests on December 14, 2001.
On May 22, 2003, KMIGT received an Order on Rehearing and Compliance Filing
(May 2003 Order) from the FERC, addressing KMIGT's November 19, 2001 filed
request for rehearing and filing to comply with the directives of the October
19, 2001 Order. 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
16
FERC'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. The
June 20, 2003 compliance filing is pending FERC action. KMIGT is preparing for
full implementation of Order 637 on December 1, 2003. The evaluation of the full
impact of implementation of Order 637 on the KMIGT system is ongoing. We believe
that these matters will not have a material adverse effect on our business,
financial position, results of operations or cash flows.
Separately, numerous petitioners, including KMIGT, have filed appeals in
respect of Order 637 in the D.C. Circuit, potentially raising a wide array of
issues related to Order 637 compliance. Initial briefs were filed on April 6,
2001, addressing issues contested by industry participants. Oral arguments on
the appeals were held before the court in December 2001. On April 5, 2002, the
D.C. Circuit issued an order largely affirming Order Nos. 637, et seq. The D.C.
Circuit remanded the FERC's decision to impose a 5-year cap on bids that an
existing shipper would have to match in the right of first refusal process. The
D.C. Circuit also remanded the FERC's decision to allow forward-hauls and
backhauls to the same point. Finally, the D.C. Circuit held that several aspects
of the FERC's segmentation policy and its policy on discounting at alternate
points were not ripe for review. The FERC requested comments from the industry
with respect to the issues remanded by the D.C. Circuit. They were due July 30,
2002.
On October 31, 2002, the FERC issued an order in response to the D.C.
Circuit's remand of certain Order 637 issues. The order:
- eliminated the requirement of a 5-year cap on bid terms that an existing
shipper would have to match in the right of first refusal process, and
found that no term matching cap is necessary given existing regulatory
controls;
- affirmed FERC's policy that a segmented transaction consisting of both a
forwardhaul up to contract demand and a backhaul up to contract demand to
the same point is permissible; and
- accordingly required, under Section 5 of the Natural Gas Act, pipelines
that the FERC had previously found must permit segmentation on their
systems to file tariff revisions within 30 days to permit such segmented
forwardhaul and backhaul transactions to the same point.
On December 23, 2002, KMIGT filed revised tariff provisions (in a separate
docket) in compliance with the October 31, 2002 Order concerning the elimination
of the right of first refusal five-year term matching cap. In an order issued
January 22, 2003, the FERC approved such revised tariff provisions to be
effective January 23, 2003.
Trailblazer Pipeline Company
On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with
the FERC's Order Nos. 637 and 637-A. Trailblazer's compliance filing reflected
changes in:
- segmentation;
- scheduling for capacity release transactions;
- receipt and delivery point rights;
- treatment of system imbalances;
- operational flow orders;
- penalty revenue crediting; and
- right of first refusal language.
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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 order of October 15, 2001 and also filed for rehearing of the October 15,
2001 order. On April 16, 2003, the FERC issued its order on Trailblazer's
compliance filing and rehearing order. The FERC denied Trailblazer's requests
for rehearing and approved the compliance filing subject to modifications that
must be made within 30 days of the order.
Trailblazer made those modifications in a further compliance filing on May
16, 2003. Certain shippers have filed a limited protest regarding that
compliance filing. That filing is pending FERC action. Under the FERC orders,
limited aspects of Trailblazer's plan (revenue crediting) were effective as of
May 1, 2003, and the entire plan is expected to be effective as of December 1,
2003.
Trailblazer anticipates no adverse impact on its business as a result of the
implementation of Order No. 637.
Standards of Conduct Rulemaking
On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking in
Docket No. RM01-10 in which it proposed new rules governing the interaction
between an interstate natural gas pipeline and its affiliates. If adopted as
proposed, the Notice of Proposed Rulemaking could be read to limit
communications between KMIGT, Trailblazer and their respective affiliates. In
addition, the Notice could be read to require separate staffing of KMIGT and its
affiliates, and Trailblazer and its affiliates. Comments on the Notice of
Proposed Rulemaking were due December 20, 2001. Numerous parties, including
KMIGT, have filed comment on the Proposed Standards of Conduct Rulemaking. On
May 21, 2002, the FERC held a technical conference dealing with the FERC's
proposed changes in the Standard of Conduct Rulemaking. On June 28, 2002, KMIGT
and numerous other parties filed additional written comments under a procedure
adopted at the technical conference. The Proposed Rulemaking is awaiting further
FERC action. We believe that these matters, as finally adopted, will not have a
material adverse effect on our business, financial position, results of
operations or cash flows.
The FERC also issued a Notice of Proposed Rulemaking in Docket No.
RM02-14-000 in which it proposed new regulations for cash management practices,
including establishing limits on the amount of funds that can be swept from a
regulated subsidiary to a non-regulated parent company. Kinder Morgan Interstate
Gas Transmission LLC filed comments on August 28, 2002. On June 26, 2003, FERC
issued an interim rule to be effective August 7, 2003, under which regulated
companies are required to document cash management arrangements and
transactions. The interim rule does not include a proposed rule that would have
required regulated companies, as a prerequisite to participation in cash
management programs, to maintain a proprietary capital ratio of 30% and an
investment grade credit rating. On October 22, 2003, the FERC issued its final
rule amending its regulations effective November 2003 which, among other things,
requires FERC-regulated entities to file their cash management agreements with
the FERC and to notify the FERC within 45 days after the end of the quarter when
their proprietary capital ratio drops below 30%, and when it subsequently
returns to or exceeds 30%. We believe that these matters, as finally adopted,
will not have a material adverse effect on our business, financial position,
results of operations or cash flows.
Other Regulatory
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 negotiated 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 business, financial position,
results of operations or cash flows.
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In addition to the matters described above, we may face additional challenges
to our rates in the future. Shippers on our pipelines do have rights to
challenge the rates we charge under certain circumstances prescribed by
applicable regulations. There can be no assurance that we will not face
challenges to the rates we receive for services on our pipeline systems in the
future. In addition, since many of our assets are subject to regulation, we are
subject to potential future changes in applicable rules and regulations that may
have an adverse effect on our business, financial position, results of
operations or cash flows.
Southern Pacific Transportation Company Easements
SFPP, L.P. and Southern Pacific Transportation Company are engaged in a
judicial reference proceeding to determine the extent, if any, to which the rent
payable by SFPP for the use of pipeline easements on rights-of-way held by SPTC
should be adjusted pursuant to existing contractual arrangements (Southern
Pacific Transportation Company vs. Santa Fe Pacific Corporation, SFP Properties,
Inc., Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al., Superior Court of
the State of California for the County of San Francisco, filed August 31, 1994).
In the second quarter of 2003, the trial court set the rent at approximately
$5.0 million per year as of January 1, 1994. SPTC has appealed the matter to the
California Court of Appeals.
Carbon Dioxide Litigation
Kinder Morgan CO2 Company, L.P. directly or indirectly through its ownership
interest in the Cortez Pipeline Company, along with other entities, has been
named as a defendant with several others in a series of lawsuits in the United
States District Court in Denver, Colorado and certain state courts in Colorado
and Texas. The plaintiffs include several private royalty, overriding royalty
and working interest owners at the McElmo Dome (Leadville) Unit in southwestern
Colorado. Plaintiffs in the Colorado state court action also are overriding
royalty interest owners in the Doe Canyon Unit. Plaintiffs seek to also
represent classes of claimants composed of all private and governmental royalty,
overriding royalty and working interest owners, and governmental taxing
authorities who have an interest in the carbon dioxide produced at the McElmo
Dome Unit. Plaintiffs claim they and the members of any classes that might be
certified have been damaged because the defendants have maintained a low price
for carbon dioxide in the enhanced oil recovery market in the Permian Basin and
maintained a high cost of pipeline transportation from the McElmo Dome Unit to
the Permian Basin. Plaintiffs claim breaches of contractual and potential
fiduciary duties owed by defendants and also allege other theories of liability
including:
- common law fraud;
- fraudulent concealment; and
- negligent misrepresentation.
In addition to actual or compensatory damages, certain plaintiffs are seeking
punitive or trebled damages as well as declaratory judgment for various forms of
relief, including the imposition of a constructive trust over the defendants'
interests in the Cortez Pipeline and the Partnership. These cases are: CO2
Claims Coalition, LLC v. Shell Oil Co., et al., No. 96-Z-2451 (U.S.D.C. Colo.
filed 8/22/96); Rutter & Wilbanks et al. v. Shell Oil Co., et al., No. 00-Z-1854
(U.S.D.C. Colo. filed 9/22/00); Watson v. Shell Oil Co., et al., No. 00-Z-1855
(U.S.D.C. Colo. filed 9/22/00); Ainsworth et al. v. Shell Oil Co., et al., No.
00-Z-1856 (U.S.D.C. Colo. filed 9/22/00); Shell Western E&P Inc. v. Bailey, et
al., No 98-28630 (215th Dist. Ct. Harris County, Tex. filed 6/17/98); Shores, et
al. v. Mobil Oil Corporation, et al., No. GC-99-01184 (Texas Probate Court,
Denton County filed 12/22/99); First State Bank of Denton v. Mobil Oil
Corporation, et al., No. PR-8552-01 (Texas Probate Court, Denton County filed
3/29/01); and Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43
(Colo. Dist. Ct. Montezuma County filed 3/21/98).
At a hearing conducted in the United States District Court for the District
of Colorado on April 8, 2002, the Court orally announced that it had approved
the certification of proposed plaintiff classes and approved a proposed
settlement in the CO2 Claims Coalition, LLC, Rutter & Wilbanks, Watson, and
Ainsworth cases. The Court entered a written order approving the Settlement on
May 6, 2002. Plaintiffs counsel representing Shores, et al. appealed the court's
decision to the 10th Circuit Court of Appeals. On December 26, 2002, the 10th
Circuit Court of Appeals affirmed in all respects the District Court's Order
approving settlement. On March 24, 2003, the plaintiffs' counsel in the Shores
matter filed a Petition for Writ of Certiorari in the United States Supreme
Court seeking to have the
19
Court review and overturn the decision of the 10th Circuit Court of Appeals. On
June 9, 2003, the United States Supreme Court denied the Writ of Certiorari. On
July 16, 2003, the settlement in the CO2 Claims Coalition, LLC, Rutter &
Wilbanks, Watson, and Ainsworth cases became final. Following the decision of
the 10th Circuit, the plaintiffs and defendants jointly filed motions to abate
the Shell Western E&P Inc., Shores and First State Bank of Denton cases in order
to afford the parties time to discuss potential settlement of those matters.
These Motions were granted on February 6, 2003. In the Celeste C. Grynberg case,
the parties are currently engaged in discovery.
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.
Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating Company
et al. v. Gas Pipelines, et al.)
Stevens County, Kansas District Court, Case No. 99 C 30. In May, 1999, three
plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto, filed a
purported nationwide class action in the Stevens County, Kansas District Court
against some 250 natural gas pipelines and many of their affiliates. The
District Court is located in Hugoton, Kansas. Certain entities we acquired in
the Kinder Morgan Tejas acquisition are also defendants in this matter. The
Petition (recently amended) alleges a conspiracy to underpay royalties, taxes
and producer payments by the defendants' undermeasurement of the volume and
heating content of natural gas produced from nonfederal lands for more than
twenty-five years. The named plaintiffs purport to adequately represent the
interests of unnamed plaintiffs in this action who are comprised of the nation's
gas producers, State taxing agencies and royalty, working and overriding owners.
The plaintiffs seek compensatory damages, along with statutory penalties, treble
damages, interest, costs and fees from the defendants, jointly and severally.
This action was originally filed on May 28, 1999 in Kansas State Court in
Stevens County, Kansas as a class action against approximately 245 pipeline
companies and their affiliates, including certain Kinder Morgan entities.
Subsequently, one of the defendants removed the action to Kansas Federal
District Court and the case was styled as Quinque Operating Company, et al. v.
Gas Pipelines, et al., Case No. 99-1390-CM, United States District Court for the
District of Kansas. Thereafter, we filed a motion with the Judicial Panel for
Multidistrict Litigation to consolidate this action for pretrial purposes with
the Grynberg False Claim Act cases referred to below, because of common factual
questions. On April 10, 2000, the MDL Panel ordered that this case be
consolidated with the Grynberg federal False Claims Act cases discussed below.
On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling
remanding the case back to the State Court in Stevens County, Kansas. The Court
in Kansas has issued a case management order addressing the initial phasing of
the case. In this initial phase, the court will rule on motions to dismiss
(jurisdiction and sufficiency of pleadings), and if the action is not dismissed,
on class certification. Merits discovery has been stayed. The defendants filed a
motion to dismiss on grounds other than personal jurisdiction, which was denied
by the Court in August, 2002. The Motion to Dismiss for lack of Personal
Jurisdiction of the nonresident defendants has been briefed and is pending. The
current named plaintiffs are Will Price, Tom Boles, Cooper Clark Foundation and
Stixon Petroleum, Inc. Quinque Operating Company has been dropped from the
action as a named plaintiff. On April 10, 2003, the court issued its decision
denying plaintiffs' motion for class certification. On July 8, 2003, a hearing
was held on the motion to amend the complaint. On July 28, 2003, the Court
granted leave to amend the complaint. The amended complaint does not list us or
any of our affiliates as defendants. Additionally, a new complaint was filed and
that complaint does not list us or any of our affiliates as defendants. We will
continue to monitor these matters.
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United States of America, ex rel., Jack J. Grynberg v. K N Energy
Civil Action No. 97-D-1233, filed in the U.S. District Court, District of
Colorado. This action was filed on June 9, 1997 pursuant to the federal False
Claim Act and involves allegations of mismeasurement of natural gas produced
from federal and Indian lands. The Department of Justice has decided not to
intervene in support of the action. The complaint is part of a larger series of
similar complaints filed by Mr. Grynberg against 77 natural gas pipelines
(approximately 330 other defendants). Certain entities we acquired in the Kinder
Morgan Tejas acquisition are also defendants in this matter. An earlier single
action making substantially similar allegations against the pipeline industry
was dismissed by Judge Hogan of the U.S. District Court for the District of
Columbia on grounds of improper joinder and lack of jurisdiction. As a result,
Mr. Grynberg filed individual complaints in various courts throughout the
country. In 1999, these cases were consolidated by the Judicial Panel for
Multidistrict Litigation, and transferred to the District of Wyoming. The
multidistrict litigation matter is called In Re Natural Gas Royalties Qui Tam
Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument
on the motion to dismiss occurred on March 17, 2000. On July 20, 2000, the
United States of America filed a motion to dismiss those claims by Grynberg that
deal with the manner in which defendants valued gas produced from federal
leases, referred to as valuation claims. Judge Downes denied the defendant's
motion to dismiss on May 18, 2001. The United States' motion to dismiss most of
plaintiff's valuation claims has been granted by the court. Grynberg has
appealed that dismissal to the 10th Circuit, which has requested briefing
regarding its jurisdiction over that appeal. Discovery is now underway to
determine issues related to the Court's subject matter jurisdiction, arising out
of the False Claims Act. On May 7, 2003, Grynberg sought leave to file a Third
Amended Complaint, which adds allegations of 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 have filed a motion
to remove the case from venue in Dewitt County, Texas to Harris County, Texas,
and our motion was denied in a venue hearing in November 2002.
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:
- there is no cause-in-fact of the gas sales nonrenewals attributable to us;
and
- the defense of legal justification applies to the claims for tortuous
interference.
Based on the information available to date and our preliminary investigation,
we believe this suit is without merit and we intend to defend it vigorously.
Maher et ux. v. Centerpoint Energy, Inc. d/b/a Reliant Energy, Incorporated,
Reliant Energy Resources Corp., Entex Gas Marketing Company, Kinder Morgan Texas
Pipeline, L.P., Kinder Morgan Energy Partners, L.P., Houston Pipeline Company,
L.P. and AEP Gas Marketing, L.L.C., No. 30875 (District Court, Wharton
21
County Texas).
On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan
Energy Partners, L.P. were served with the above-entitled Complaint. A First
Amended Complaint was served on October 23, 2002, adding additional defendants
Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc., Kinder Morgan
Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. The First Amended
Complaint purports to bring a class action on behalf of those Texas residents
who purchased natural gas for residential purposes from the so-called "Reliant
Defendants" in Texas at any time during the period encompassing "at least the
last ten years."
The Complaint alleges that Reliant Energy Resources Corp., by and through its
affiliates, has artificially inflated the price charged to residential consumers
for natural gas that it allegedly purchased from the non-Reliant defendants,
including the above-listed Kinder Morgan entities. The Complaint further alleges
that in exchange for Reliant Energy Resources Corp.'s purchase of natural gas at
above market prices, the non-Reliant defendants, including the above-listed
Kinder Morgan entities, sell natural gas to Entex Gas Marketing Company at
prices substantially below market, which in turn sells such natural gas to
commercial and industrial consumers and gas marketers at market price. The
Complaint purports to assert claims for fraud, violations of the Texas Deceptive
Trade Practices Act, and violations of the Texas Utility Code against some or
all of the Defendants, and civil conspiracy against all of the defendants, and
seeks relief in the form of, inter alia, actual, exemplary and statutory
damages, civil penalties, interest, attorneys' fees and a constructive trust ab
initio on any and all sums which allegedly represent overcharges by Reliant and
Reliant Energy Resources Corp.
On November 18, 2002, the Kinder Morgan defendants filed a Motion to Transfer
Venue and, Subject Thereto, Original Answer to the First Amended Complaint. The
parties are currently engaged in preliminary discovery. Based on the information
available to date and our preliminary investigation, the Kinder Morgan
defendants believe that the claims against them are without merit and intend to
defend against them vigorously.
Marie Snyder, et al v. City of Fallon, United States Department of the Navy,
Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas
Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District
Court, District of Nevada)("Snyder"); 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.
22
The defendants responded to the Complaint by filing Motions to Dismiss on the
grounds that it fails to state a claim upon which relief can be granted. On
November 7, 2002, the United States District Court granted the Motion to Dismiss
filed by the United States, and further dismissed all claims against the
remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs
filed a Motion for Reconsideration and Leave to Amend, which was denied by the
Court on December 30, 2002. Plaintiffs have filed a Notice of Appeal to the
United States Court of Appeals for the 9th Circuit, which appeal is currently
pending.
On December 3, 2002, plaintiffs filed an additional Complaint for Class
Action in the Galaz 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, which appeal is currently pending.
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, which motions are
currently pending. On October 4, 2003, plaintiffs' counsel agreed in writing to
dismiss the Galaz II matter, but had not done so as of October 30, 2003.
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,
which Motion is currently pending. 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.
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 are
currently preparing Motions to Dismiss the Jernee matter.
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
23
have not yet been formally served with a copy of the complaint.
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 the Snyder matter,
the three Galaz matters, the Jernee matter and the Sands matter 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 the settlement will be completed by the end of November
2003. Plantation believes that the ultimate resolution of these Marion County,
Mississippi cases will not have a material effect on its 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.
Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party in
interest for Enron Helium Company, a division of Enron Corp., Enron Liquids
Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder
Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252 (189th
Judicial District Court, Harris County, Texas)
On September 1, 2000, Plaintiff Exxon Mobil Corporation filed its Original
Petition and Application for Declaratory Relief against Kinder Morgan Operating
L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder
Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P.,
Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron
Helium Company. Plaintiff added Enron Corp. as party in interest for Enron
Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a
Defendant. The claims against Enron Corp. were severed into a separate cause of
action. Plaintiff's claims are based on a Gas Processing Agreement entered into
on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company
relating to gas produced in the Hugoton Field in Kansas and processed at the
Bushton Plant, a natural gas processing facility located in Kansas. Plaintiff
also asserts claims relating to the
24
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 November 1987 through March 1997 in the amount of $30.7 million. On May
2, 2003, Plaintiff added claims for the period April 1997 through February 2003
in the amount of $12.9 million. 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 October 15, 2003,
plaintiff filed its Tenth Supplemental Responses to Requests for Disclosure that
restated its alleged economic damages for the period of November 1987 through
September 2003 as approximately $37.1 million. The parties are currently engaged
in discovery. Based on the information available to date in our investigation,
the Kinder Morgan Defendants believe that the claims against them are without
merit and intend to defend against them vigorously.
Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions, that, to the extent an assessment of the
matter is possible, we have established an adequate reserve to cover potential
liability, and that these matters will not have a material adverse effect on our
business, financial position, results of operations or cash flows.
Environmental Matters
We are subject to environmental cleanup and enforcement actions from time to
time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) generally imposes joint and several
liability for cleanup and enforcement costs on current or predecessor owners and
operators of a site, without regard to fault or the legality of the original
conduct. Our operations are also subject to federal, state and local laws and
regulations relating to protection of the environment. Although we believe our
operations are in substantial compliance with applicable environmental
regulations, risks of additional costs and liabilities are inherent in pipeline,
terminal and carbon dioxide field and oil field operations, and there can be no
assurance that we will not incur significant costs and liabilities. Moreover, it
is possible that other developments, such as increasingly stringent
environmental laws, regulations and enforcement policies thereunder, and claims
for damages to property or persons resulting from our operations, could result
in substantial costs and liabilities to us.
We are currently involved in the following governmental proceedings related
to compliance with environmental regulations associated with our assets and have
established a reserve to address the costs associated with the cleanup:
- 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;
- several ground water hydrocarbon remediation efforts under administrative
orders issued by the California Regional Water Quality Control Board and
two other state agencies;
- 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
- a ground water remediation effort taking place between Chevron, Plantation
Pipe Line Company and the Alabama Department of Environmental Management.
In addition, we are from time to time involved in civil proceedings relating
to damages alleged to have occurred as a result of accidental leaks or spills of
refined petroleum products, natural gas liquids, natural gas and carbon
25
dioxide.
Furthermore, our review of assets related to Kinder Morgan Interstate Gas
Transmission LLC indicates possible environmental impacts from petroleum and
used oil releases into the soil and groundwater at nine sites. Additionally, our
review of assets related to Kinder Morgan Texas Pipeline indicates possible
environmental impacts from petroleum releases into the soil and groundwater at
six sites. Further delineation and remediation of any environmental impacts from
these matters will be conducted. Reserves have been established to address the
closure of these issues.
Although no assurance can be given, we believe that the ultimate resolution
of the environmental matters set forth in this note will not have a material
adverse effect on our business, financial position, results of operations or
cash flows. As of September 30, 2003, we have recorded a total reserve for
environmental claims in the amount of $40.3 million. However, we were not able
to reasonably estimate when the eventual settlements of these claims will occur.
Other
We are a defendant in various lawsuits arising from the day-to-day operations
of our businesses. Although no assurance can be given, we believe, based on our
experiences to date, that the ultimate resolution of such items will not have a
material adverse impact on our business, financial position, results of
operations or cash flows.
4. Change in Accounting for Asset Retirement Obligations
In August 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations." SFAS No. 143 provides accounting
and reporting guidance for legal obligations associated with the retirement of
long-lived assets that result from the acquisition, construction or normal
operation of a long-lived asset. The provisions of this Statement are effective
for fiscal years beginning after June 15, 2002. We adopted SFAS No. 143 on
January 1, 2003.
SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. Its primary impact on
us will be to change the method of accruing for oil production site restoration
costs related to our CO2 Pipelines business segment. Prior to January 1, 2003,
we accounted for asset retirement obligations in accordance with SFAS No. 19,
"Financial Accounting and Reporting by Oil and Gas Producing Companies." Under
SFAS No. 143, the fair value of asset retirement obligations are recorded as
liabilities on a discounted basis when they are incurred, which is typically at
the time the assets are installed or acquired. Amounts recorded for the related
assets are increased by the amount of these obligations. Over time, the
liabilities will be accreted for the change in their present value and the
initial capitalized costs will be depreciated over the useful lives of the
related assets. The liabilities are eventually extinguished when the asset is
taken out of service. Specifically, upon adoption of this Statement, an entity
must recognize the following items in its balance sheet:
- a liability for any existing asset retirement obligations adjusted for
cumulative accretion to the date of adoption;
- an asset retirement cost capitalized as an increase to the carrying amount
of the associated long-lived asset; and
- accumulated depreciation on that capitalized cost.
Amounts resulting from initial application of this Statement shall be
measured using current information, current assumptions and current interest
rates. The amount recognized as an asset retirement cost shall be measured as of
the date the asset retirement obligation was incurred. Cumulative accretion and
accumulated depreciation shall be measured for the time period from the date the
liability would have been recognized had the provisions of this Statement been
in effect to the date of adoption of this Statement.
The cumulative effect adjustment for this change in accounting principle
resulted in income of $3.5 million in the first quarter of 2003. Furthermore, as
required by SFAS No. 143, we recognized the cumulative effect of initially
26
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 Pipelines business segment, we are required to plug and abandon
oil wells that have been removed from service and to remove our surface wellhead
equipment and compressors. As of September 30, 2003, we have recognized asset
retirement obligations in the aggregate amount of $13.6 million relating to
these requirements at existing sites within our CO2 Pipelines segment.
In our Natural Gas Pipelines business segment, if we were to cease providing
utility services, we would be required to remove surface facilities from land
belonging to our customers and others. Our Texas intrastate natural gas pipeline
group has various condensate drip tanks and separators located throughout its
natural gas pipeline systems, as well as inactive gas processing plants,
laterals and gathering systems which are no longer integral to the overall
mainline transmission systems, and asbestos-coated underground pipe which is
being abandoned and retired. Our Kinder Morgan Interstate Gas Transmission
system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of September 30, 2003, we have recognized
asset retirement obligations in the aggregate amount of $3.0 million relating to
the businesses within our Natural Gas Pipelines segment.
We have included $0.8 million of our total $16.6 million asset retirement
obligations as of September 30, 2003 with "Accrued other current liabilities" in
the accompanying consolidated balance sheet and the remaining $15.8 million with
"Other long-term liabilities and deferred credits." No assets are legally
restricted for purposes of settling our asset retirement obligations. A
reconciliation of the beginning and ending aggregate carrying amount of our
asset retirement obligations for the nine months ended September 30, 2003 is as
follows (in thousands):
Balance at December 31, 2002........ $ -
Cumulative effect transition 14,125
adjustment..........................
Liabilities incurred................ 2,199
Liabilities settled................. (582)
Accretion expense................... 654
Revisions in estimated cash flows... 208
---------
Balance at September 30, 2003....... $ 16,604
=========
Pro Forma Information
Had the provisions of SFAS No. 143 been in effect prior to January 1, 2003,
our net income and associated per unit amounts, and the amount of our liability
for asset retirement obligations, would have been as follows (in thousands,
except per unit amounts):
Pro Forma Pro Forma
Three Months Ended Nine Months Ended
------------------ -----------------
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2003 2002 2003 2002
---- ---- ---- ----
Reported income before cumulative effect of a change in
accounting principle.................................. $174,176 $158,180 $510,146 $444,130
Adjustments from change in accounting for asset
retirement obligations................................ -- (288) -- (874)
-------- -------- -------- --------
Adjusted income before cumulative effect of a change in
accounting principle..................................... $174,176 $157,892 $510,146 $443,256
======== ======== ======== ========
Reported income before cumulative effect of a change in
accounting principle per unit (fully diluted)............ $ 0.49 $ 0.50 $ 1.47 $ 1.46
======== ======== ======== ========
Adjusted income before cumulative effect of a change in
accounting principle per unit (fully diluted)............ $ 0.49 $ 0.50 $ 1.47 $ 1.45
======== ======== ======== ========
27
Dec. 31, Sept. 30, Dec. 31,
2002 2002 2001
---- ---- ----
Liability for asset retirement obligations............. $14,125 $14,041 $14,345
5. Distributions
On August 14, 2003, we paid a cash distribution of $0.65 per unit to our
common unitholders and to our class B unitholders for the quarterly period ended
June 30, 2003. KMR, our sole i-unitholder, received 811,878 additional i-units
based on the $0.65 cash distribution per common unit. The distributions were
declared on July 16, 2003, payable to unitholders of record as of July 31, 2003.
On October 15, 2003, we declared a cash distribution of $0.66 per unit for
the quarterly period ended September 30, 2003. The distribution will be paid on
or before November 14, 2003, to unitholders of record as of October 31, 2003.
Our common unitholders and class B unitholders will receive cash. KMR will
receive a distribution in the form of additional i-units based on the $0.66
distribution per common unit. The number of i-units distributed will be 811,625.
For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.016844)
will be issued. The fraction was determined by dividing:
- $0.66, the cash amount distributed per common unit
by
- $39.184, the average of KMR's limited liability shares' closing market
prices from October 15-28, 2003, the ten consecutive trading days preceding
the date on which the shares began to trade ex-dividend under the rules of
the New York Stock Exchange.
6. Intangibles
Effective January 1, 2002, we adopted SFAS No. 141, "Business Combinations"
and SFAS No. 142, "Goodwill and Other Intangible Assets." These accounting
pronouncements require that we prospectively cease amortization of all
intangible assets having indefinite useful economic lives. Such assets,
including goodwill, are not to be amortized until their lives are determined to
be finite. A recognized intangible asset with an indefinite useful life should
be tested for impairment annually or on an interim basis if events or
circumstances indicate that the fair value of the asset has decreased below its
carrying value. We completed this initial transition impairment test in June
2002 and determined that our goodwill was not impaired as of January 1, 2002. We
have selected an impairment measurement test date of January 1 of each year and
we have determined that our goodwill was not impaired as of January 1, 2003.
Under ABP No. 18, any premium paid by an investor, which is analogous to
goodwill, must also be identified. Under prior rules, excess cost over
underlying fair value of net assets accounted for under the equity method,
referred to as equity method goodwill, would have been amortized, however, under
SFAS No. 142, equity method goodwill is not subject to amortization but rather
to impairment testing pursuant to ABP No. 18. 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 December 31, 2002
and September 30, 2003, we have reported $140.3 million in equity method
goodwill within the caption "Investments" in the accompanying consolidated
balance sheets.
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):
28
Sept. 30, Dec. 31,
2003 2002
----------- -----------
Goodwill
Gross carrying amount......... $ 743,652 $ 730,752
Accumulated amortization...... (14,142) (14,142)
----------- -----------
Net carrying amount........... 729,510 716,610
----------- -----------
Lease value
Gross carrying amount......... 6,592 $ 6,592
Accumulated amortization...... (853) (748)
----------- -----------
Net carrying amount........... 5,739 5,844
----------- -----------
Contracts and other
Gross carrying amount......... 11,801 $ 11,719
Accumulated amortization...... (287) (239)
----------- -----------
Net carrying amount........... 11,514 11,480
----------- -----------
Total intangibles, net........... $ 746,763 $ 733,934
=========== ===========
Changes in the carrying amount of goodwill for the nine months ended
September 30, 2003 are summarized as follows (in thousands):
Products Natural Gas CO2
Pipelines Pipelines Pipelines Terminals Total
----------- ----------- ----------- ----------- -----------
Balance at Dec. 31, 2002...... $ 263,182 $ 253,358 $ 46,101 $ 153,969 $ 716,610
Goodwill acquired............. -- -- -- 12,900 12,900
Goodwill dispositions, net.... -- -- -- -- --
Impairment losses............. -- -- -- -- --
----------- ----------- ----------- ----------- -----------
Balance at Sept. 30, 2003..... $ 263,182 $ 253,358 $ 46,101 $ 166,869 $ 729,510
=========== =========== =========== =========== ===========
Amortization expense on intangibles consists of the following (in
thousands):
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
---------------------------- ---------------------------
2003 2002 2003 2002
----------- ------------ ------------ ----------
Lease value............ $ 35 $ 35 $ 105 $ 105
Contracts and other.... 17 10 48 30
----------- ------------ ------------ ----------
$ 52 $ 45 $ 153 $ 135
=========== =========== =========== ===========
The weighted average amortization period for our intangible assets is
approximately 41 years. Our estimated amortization expense for these assets for
each of the next five fiscal years is $0.2 million.
7. Debt
Our outstanding short-term debt as of September 30, 2003 was $513.8 million.
The balance consisted of:
- $506.9 million of commercial paper borrowings;
- $5 million under the Central Florida Pipeline LLC Notes; and
- $1.9 million in other borrowings.
As of September 30, 2003, we intend and have the ability to refinance $427.6
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. Currently, we do
not anticipate any liquidity problems. The weighted average interest rate on all
of our borrowings was approximately 4.346% during the third quarter of 2003 and
4.864% during the third quarter of 2002.
29
Credit Facilities
As of September 30, 2003, we had two credit facilities:
- a $570 million unsecured 364-day credit facility due October 14, 2003
(subsequently replaced October 14, 2003 by a $570 million unsecured 364-day
credit facility due October 12, 2004); and
- a $480 million unsecured three-year credit facility due October 15, 2005.
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 at
December 31, 2002 or at September 30, 2003. None of our debt or credit
facilities are subject to payment acceleration as a result of any change to our
credit ratings. However, the margin that we pay with respect to LIBOR based
borrowings under our credit facilities is tied to our credit ratings. Interest
on the two credit facilities accrues at our option at a floating rate equal to
either:
- the administrative agent's base rate (but not less than the Federal Funds
Rate, plus 0.5%); or
- LIBOR, plus a margin, which varies depending upon the credit rating of our
long-term senior unsecured debt.
The amount available for borrowing under our credit facilities is reduced by:
- a $23.7 million letter of credit that supports Kinder Morgan Operating L.P.
"B"'s tax-exempt bonds;
- 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);
- a $0.2 million letter of credit entered into on June 4, 2002 that supports
a workers' compensation insurance policy;
- a $0.5 million letter of credit entered into on March 31, 2003 that
supports an engineering contract; and
- our outstanding commercial paper borrowings.
Our three-year credit facility also permits us to obtain bids for fixed rate
loans from members of the lending syndicate.
Our $570 million unsecured 364-day credit facility expired October 14, 2003.
On that date, we obtained a new $570 million unsecured 364-day credit facility
due October 12, 2004. The terms of this credit facility are substantially
similar to the terms of the expired facility.
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
September 30, 2003, we have entered into interest rate swap agreements with a
notional principal amount of $1.95 billion for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt obligations.
The $1.95 billion notional principal amount of our interest rate swap agreements
has not changed since December 31, 2002.
These swaps meet the conditions required to assume no ineffectiveness under
SFAS No. 133 and, therefore, we have accounted for them using the "shortcut"
method prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust
the carrying value of each swap to its fair value each quarter, with an
offsetting entry to adjust the carrying value of the debt securities whose fair
value is being hedged. For more information on our risk management activities,
see Note 10.
30
Commercial Paper Program
As of December 31, 2002, our commercial paper program provided for the
issuance of up to $1.05 billion of commercial paper. As of September 30, 2003,
we had $506.9 million of commercial paper outstanding with an average interest
rate of 1.1745%. Borrowings under our commercial paper program reduce the
borrowings allowed under our credit facilities.
Central Florida Pipeline LLC Debt
Effective January 1, 2001, we acquired Central Florida Pipeline LLC. As part
of our purchase price, we assumed an aggregate principal amount of $40.0 million
of Senior Notes originally issued to a syndicate of eight insurance companies.
The Senior Notes have a fixed annual interest rate of 7.84% with repayments in
annual installments of $5.0 million beginning July 23, 2001. The final payment
is due July 23, 2008. Interest is payable semiannually on January 1 and July 23
of each year. At December 31, 2002, Central Florida's outstanding balance under
the Senior Notes was $30.0 million. In July 2003, we made an annual repayment of
$5.0 million and at September 30, 2003, Central Florida's outstanding balance
under the Senior Notes was $25.0 million.
For additional information regarding our debt facilities, see Note 9 to our
consolidated financial statements included in our Form 10-K for the year ended
December 31, 2002.
Contingent Debt
Cortez Pipeline Company Debt
Pursuant to a certain Throughput and Deficiency Agreement, the owners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a
subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers Pipeline
Company - 13% owner) are required, on a percentage ownership basis, to
contribute capital to Cortez Pipeline Company in the event of a cash deficiency.
The Throughput and Deficiency Agreement contractually supports the borrowings of
Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline
Company, by obligating the owners of Cortez Pipeline Company to fund cash
deficiencies at Cortez Pipeline Company, including cash deficiencies relating to
the repayment of principal and interest on borrowings by Cortez Capital
Corporation. Parent companies of the respective Cortez Pipeline Company owners
further severally guarantee, on a percentage basis, the obligations of the
Cortez Pipeline Company owners under the Throughput and Deficiency Agreement.
Due to our indirect ownership of Cortez Pipeline Company through Kinder
Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez
Capital Corporation. Shell Oil Company shares our guaranty obligations jointly
and severally through December 31, 2006 for Cortez Capital Corporation's debt
programs in place as of April 1, 2000.
As of September 30, 2003, the debt facilities of Cortez Capital Corporation
consisted of:
- $95 million of Series D notes due May 15, 2013;
- a $175 million short-term commercial paper program; and
- a $175 million committed revolving credit facility due December 26, 2003
(to support the above-mentioned $175 million commercial paper program).
As of September 30, 2003, Cortez Capital Corporation had $140.4 million of
commercial paper outstanding with an interest rate of 1.11%. During the third
quarter of 2003, the average interest rate on the Series D notes was 7.0389%. As
of September 30, 2003, there were no borrowings under the credit facility.
31
Plantation Pipeline Company Debt
On April 30, 1997, Plantation Pipeline Company entered into a $10 million,
ten-year floating-rate term credit agreement. We, as an owner of Plantation
Pipeline Company, severally guarantee this debt on a pro rata basis equivalent
to our respective 51% ownership interest. During 1999, this agreement was
amended to reduce the maturity date by three years. The $10 million is
outstanding as of September 30, 2003.
Red Cedar Gas Gathering Company Debt
In October 1998, Red Cedar Gas Gathering Company sold $55 million in
aggregate principal amount of Senior Notes due October 31, 2010. The $55 million
was sold in 10 different notes in varying amounts with identical terms.
The Senior Notes are collateralized by a first priority lien on the ownership
interests, including our 49% ownership interest, in Red Cedar Gas Gathering
Company. The Senior Notes are also guaranteed by us and the other owner of Red
Cedar Gas Gathering Company under joint and several liability. The principal is
to be repaid in seven equal installments beginning on October 31, 2004 and
ending on October 31, 2010. The $55 million is outstanding as of September 30,
2003.
Nassau County, Florida Ocean Highway and Port Authority Debt
Nassau County, Florida Ocean Highway and Port Authority is a political
subdivision of the State of Florida. During 1990, Ocean Highway and Port
Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal
amount of $38.5 million for the purpose of constructing certain port
improvements located in Fernandino Beach, Nassau County, Florida. A letter of
credit was issued as security for the Adjustable Demand Revenue Bonds and was
guaranteed by the parent company of Nassau Terminals LLC, the operator of the
port facilities. In July 2002, we acquired Nassau Terminals LLC and became
guarantor under the letter of credit agreement. In December 2002, we issued a
$28 million letter of credit under our credit facilities and the former letter
of credit guarantee was terminated.
Certain Relationships and Related Transactions
Lines of Credit
We have agreed to guarantee potential borrowings under lines of credit
available from Wachovia Bank, National Association, formerly known as First
Union National Bank, to Messrs. Thomas Bannigan, C. Park Shaper and James Street
and Ms. Deborah Macdonald. Each of these officers is primarily liable for any
borrowing on his or her line of credit, and if we make any payment with respect
to an outstanding loan, the officer on behalf of whom payment is made must
surrender a percentage of his or her options to purchase KMI common stock. Our
current obligations under the guaranties, on an individual basis, generally do
not exceed $1.0 million and such obligations, in the aggregate, do not exceed
$1.9 million. To date, we have made no payment with respect to these lines of
credit. As of October 31, 2003, each line of credit was either terminated or
refinanced without a guarantee from us. We have no further guaranteed
obligations with respect to any borrowings by our officers.
KMI Asset Contributions
In conjunction with our acquisition of Natural Gas Pipelines assets from KMI
on December 31, 1999 and 2000, KMI became a guarantor of approximately $522.7
million of our debt. This amount has not changed as of December 31, 2002 and
September 30, 2003. KMI would be obligated to perform under this guarantee only
if we and/or our assets were unable to satisfy our obligations.
32
8. Partners' Capital
As of September 30, 2003, our partners' capital consisted of:
- 134,712,958 common units;
- 5,313,400 Class B units; and
- 48,184,840 i-units.
Together, these 188,211,198 units represent our limited partners' interest
and an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights. As of September 30, 2003,
our common unit total consisted of 121,757,223 units held by third parties,
11,231,735 units held by KMI and its consolidated affiliates (excluding our
general partner); and 1,724,000 units held by our general partner. Our Class B
units were held entirely by KMI and our i-units were held entirely by KMR.
As of December 31, 2002, our partners' capital consisted of:
- 129,943,218 common units;
- 5,313,400 Class B units; and
- 45,654,048 i-units.
Our total common units outstanding at December 31, 2002, consisted of
116,987,483 units held by third parties, 11,231,735 units held by KMI and its
consolidated affiliates (excluding our general partner) and 1,724,000 units held
by our general partner. Our Class B units were held entirely by KMI and our
i-units were held entirely by KMR.
In June 2003, we issued in a public offering 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. After commissions and underwriting expenses, we received
net proceeds of $173.3 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. We initially issued i-units in May 2001. The i-units
are a separate class of limited partner interests in us. All of our i-units are
owned by KMR and are not publicly traded. In accordance with its limited
liability company agreement, KMR's activities are restricted to being a limited
partner in, and controlling and managing the business and affairs of, the
Partnership, our operating partnerships and our subsidiaries.
Through the combined effect of the provisions in our partnership agreement
and the provisions of KMR's limited liability company agreement, the number of
outstanding KMR shares and the number of i-units will at all times be equal.
Furthermore, under the terms of our partnership agreement, we agreed that we
will not, except in liquidation, make a distribution on an i-unit other than in
additional i-units or a security that has in all material respects the same
rights and privileges as our i-units. The number of i-units we distribute to KMR
is based upon the amount of cash we distribute to the owners of our common
units. When cash is paid to the holders of our common units, we will issue
additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by
KMR will have the same value as the cash payment on the common unit.
The cash equivalent of distributions of i-units will be treated as if it had
actually been distributed for purposes of determining the distributions to our
general partner. We will not distribute the cash to the holders of our i-units
but will retain the cash and use the cash in our business. If additional units
are distributed to the holders of our common units, we will issue an equivalent
amount of i-units to KMR based on the number of i-units it owns. Based on the
33
preceding, KMR received a distribution of 811,878 i-units in August 2003. These
additional i-units distributed were based on the $0.65 per unit distributed to
our common unitholders on August 14, 2003.
For the purposes of maintaining partner capital accounts, our partnership
agreement specifies that items of income and loss shall be allocated among the
partners, other than owners of i-units, in accordance with their percentage
interests. Normal allocations according to percentage interests are made,
however, only after giving effect to any priority income allocations in an
amount equal to the incentive distributions that are allocated 100% to our
general partner. Incentive distributions are generally defined as all cash
distributions paid to our general partner that are in excess of 2% of the
aggregate value of cash and i-units being distributed.
Incentive distributions allocated to our general partner are determined by
the amount that quarterly distributions to unitholders exceed certain specified
target levels. Our distribution of $0.65 per unit paid on August 14, 2003 for
the second quarter of 2003 required an incentive distribution to our general
partner of $79.6 million. Our distribution of $0.61 per unit paid on August 14,
2002 for the second quarter of 2002 required an incentive distribution to our
general partner of $64.4 million. The increased incentive distribution to our
general partner paid for the second quarter of 2003 over the distribution paid
for the second quarter of 2002 reflects the increase in the amount distributed
per unit as well as the issuance of additional units.
Our declared distribution for the third quarter of 2003 of $0.66 per unit
will result in an incentive distribution to our general partner of approximately
$81.8 million. This compares to our distribution of $0.61 per unit and incentive
distribution to our general partner of approximately $69.5 million for the third
quarter of 2002.
9. Comprehensive Income
SFAS No. 130, "Accounting for Comprehensive Income," requires that
enterprises report a total for comprehensive income. For each of the nine months
ended September 30, 2003 and 2002, the only difference between our net income
and our comprehensive income was the unrealized gain or loss on derivatives
utilized for hedging purposes. For more information on our hedging activities,
see Note 10. Our total comprehensive income is as follows (in thousands):
Three Months Ended Nine Months Ended
Sept. 30, Sept. 30,
2003 2002 2003 2002
-------- -------- -------- --------
Net income.......................................................... $174,176 $158,180 $513,611 $444,130
Change in fair value of derivatives used for hedging purposes....... (35,508) (15,680) (108,682) (97,536)
Reclassification of change in fair value of derivatives to net income 15,798 3,442 67,046 (9,386)
-------- -------- -------- --------
Comprehensive income................................................ $154,466 $145,942 $471,975 $337,208
======== ======== ======== ========
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.
The energy risk management products that we use include:
- commodity futures and options contracts;
- fixed-price swaps; and
34
- basis swaps.
Pursuant to our management's approved policy, we are to engage in these
activities only as a hedging mechanism against price volatility associated with:
- pre-existing or anticipated physical natural gas, natural gas liquids and
crude oil sales;
- pre-existing or anticipated physical carbon dioxide sales that have pricing
tied to crude oil prices;
- natural gas purchases; and
- system use and storage.
Our risk management activities are only used in order to protect our profit
margins and our risk management policies prohibit us from engaging in
speculative trading. Commodity-related activities of our risk management group
are monitored by our Risk Management Committee, which is charged with the review
and enforcement of our management's risk management policy. Certain of our
business activities expose us to foreign currency fluctuations. However, 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. Accordingly, as of September 30, 2003, no financial
instruments were used to limit the effects of foreign exchange rate fluctuations
on our financial results.
Our derivatives that hedge our commodity price risks involve our normal
business activities, which include the sale of natural gas, natural gas liquids,
oil and carbon dioxide, and these derivatives have been designated by us as cash
flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that
hedge exposure to variable cash flows of forecasted transactions as cash flow
hedges and the effective portion of the derivative's gain or loss is initially
reported as a component of other comprehensive income (outside earnings) and
subsequently reclassified into earnings when the forecasted transaction affects
earnings. To be effective, changes in the value of the derivative or its
resulting cash flows must substantially offset changes in the value or cash
flows of the item being hedged. The ineffective portion of the gain or loss is
reported in earnings immediately.
The gains and losses included in "Accumulated other comprehensive income
(loss)" in the accompanying consolidated balance sheets are reclassified into
earnings as the hedged sales and purchases take place. Approximately $40.9
million of the Accumulated other comprehensive loss balance of $86.9 million
representing unrecognized net losses on derivative activities as of September
30, 2003 is expected to be reclassified into earnings during the next twelve
months. During the nine months ended September 30, 2003, we reclassified $67.0
million of Accumulated other comprehensive income into earnings. This amount
includes the balance of $45.3 million representing unrecognized net losses on
derivative activities at December 31, 2002. During the nine months ended
September 30, 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 will no longer occur by the end of the originally
specified time period.
We recognized a gain of $0.2 million during the third quarter of 2003 and no
gain or loss during the third quarter of 2002 as a result of hedge
ineffectiveness. We recognized a gain of $0.6 million during the first nine
months of 2003 and a gain of $0.5 million during the first nine months of 2002
as a result of hedge ineffectiveness. All of these amounts are reported within
the captions "Gas purchases and other costs of sales" and "Operations and
maintenance" in the accompanying Consolidated Statements of Income. For each of
the nine months ended September 30, 2003 and 2002, we did not exclude any
component of the derivative instruments' gain or loss from the assessment of
hedge effectiveness.
The differences between the current market value and the original physical
contracts value associated with our hedging activities are primarily reflected
as "Other current assets" and "Accrued other current liabilities" in the
accompanying consolidated balance sheets. As of September 30, 2003, the balance
in "Other current assets" on our consolidated balance sheet included $20.4
million related to risk management hedging activities, and the balance in
"Accrued other current liabilities" included $61.6 million related to risk
management hedging activities. As of December 31, 2002, the balance in "Other
current assets" on our consolidated balance sheet included $57.9 million
35
related to risk management hedging activities, and the balance in "Accrued other
current liabilities" included $101.3 million related to risk management hedging
activities.
The remaining differences between the current market value and the original
physical contracts value associated with our hedging activities are reflected as
deferred charges or deferred credits in the accompanying consolidated balance
sheets. As of September 30, 2003, the balance in "Deferred charges and other
assets" included $2.5 million related to risk management hedging activities, and
the balance in "Other long-term liabilities and deferred credits" included $49.0
million related to risk management hedging activities. As of December 31, 2002,
the balance in "Deferred charges and other assets" included $5.7 million related
to risk management hedging activities, and the balance in "Other long-term
liabilities and deferred credits" included $8.5 million related to risk
management hedging activities.
Our over-the-counter swaps and options are with a number of parties, who
principally have investment grade credit ratings. We both owe money and are owed
money under these financial instruments. Defaults by counterparties under
over-the-counter swaps and options could expose us to additional commodity price
risks in the event that we are unable to enter into replacement contracts for
such swaps and options on substantially the same terms. Alternatively, we may
need to pay significant amounts to the new counterparties to induce them to
enter into replacement swaps and options on substantially the same terms. While
we enter into derivative transactions principally with investment grade
counterparties and actively monitor their credit ratings, it is nevertheless
possible that from time to time losses will result from counterparty credit risk
in the future.
Interest Rate Swaps
In order to maintain a cost effective capital structure, it is our policy to
borrow funds using a mix of fixed rate debt and variable rate debt. As of
September 30, 2003 and as of December 31, 2002, we were a party to interest rate
swap agreements with a notional principal amount of $1.95 billion for the
purpose of hedging the interest rate risk associated with our fixed and variable
rate debt obligations.
As of September 30, 2003, a notional principal amount of $1.75 billion of
these agreements effectively converts the interest expense associated with the
following series of our senior notes from fixed rates to variable rates based on
an interest rate of LIBOR plus a spread:
- $200 million principal amount of our 8.0% senior notes due March 15, 2005;
- $200 million principal amount of our 5.35% senior notes due August 15,
2007;
- $250 million principal amount of our 6.30% senior notes due February 1,
2009;
- $200 million principal amount of our 7.125% senior notes due March 15,
2012;
- $300 million principal amount of our 7.40% senior notes due March 15, 2031;
- $200 million principal amount of our 7.75% senior notes due March 15, 2032;
and
- $400 million principal amount of our 7.30% senior notes due August 15,
2033.
These swap agreements have termination dates that correspond to the maturity
dates of the related series of senior notes, therefore, as of September 30,
2003, the maximum length of time over which we have hedged a portion of our
exposure to the variability in future cash flows associated with interest rate
risk is through August 2033.
The swap agreements related to our 7.40% senior notes contain mutual cash-out
provisions at the then-current economic value every seven years. The swap
agreements related to our 7.125% senior notes contain cash-out provisions at the
then-current economic value at March 15, 2009. The swap agreements related to
our 7.75% senior notes and our 7.30% senior notes contain mutual cash-out
provisions at the then-current economic value every five years.
36
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 September 30, 2003, we also had swap agreements that effectively
convert the interest expense associated with $200 million of our variable rate
debt to fixed rate. The maturity dates of these swap agreements range from
October 1, 2003 to September 1, 2005. Prior to March 2002, this swap was
designated a hedge of our $200 million Floating Rate Senior Notes, which were
retired (repaid) in March 2002. Subsequent to the repayment of our Floating Rate
Senior Notes, the swaps were designated as a cash flow hedge of the risk
associated with changes in the designated benchmark interest rate (in this case,
one-month LIBOR) related to forecasted payments associated with interest on an
aggregate of $200 million of our portfolio of commercial paper.
Our interest rate swaps meet the conditions required to assume no
ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed for fair value hedges by SFAS No. 133.
Accordingly, we adjust the carrying value of each swap to its fair value each
quarter, with an offsetting entry to adjust the carrying value of the debt
securities whose fair value is being hedged. We record interest expense equal to
the variable rate payments or fixed rate payments under the swaps. Interest
expense is accrued monthly and paid semi-annually. As of September 30, 2003, we
recognized an asset of $149.2 million and a liability of $8.3 million for the
$140.9 million net fair value of our swap agreements, and we included these
amounts with "Deferred charges and other assets" and "Other long-term
liabilities and deferred credits" on the accompanying balance sheet. The
offsetting entry to adjust the carrying value of the debt securities whose fair
value was being hedged was recognized as "Market value of interest rate swaps"
on the accompanying balance sheet. As of December 31, 2002, we recognized an
asset of $179.1 million and a liability of $12.1 million for the $167.0 million
net fair value of our swap agreements, and we included these amounts with
"Deferred charges and other assets" and "Other long-term liabilities and
deferred credits" on the accompanying balance sheet and again, the offsetting
entry to adjust the carrying value of the debt securities whose fair value was
being hedged was recognized as "Market value of interest rate swaps" on the
accompanying balance sheet.
We are exposed to credit related losses in the event of nonperformance by
counterparties to these interest rate swap agreements. While we enter into
derivative transactions primarily with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that from
time to time losses will result from counterparty credit risk.
11. Reportable Segments
We divide our operations into four reportable business segments:
- Products Pipelines;
- Natural Gas Pipelines;
- CO2 Pipelines; and
- Terminals.
We evaluate performance principally based on each segments' earnings, which
exclude general and administrative expenses, third-party debt costs, interest
income and expense and minority interest. Our reportable segments are strategic
business units that offer different products and services. Each segment is
managed separately because each segment involves different products and
marketing strategies.
Our Products Pipelines segment derives its revenues primarily from the
transportation and terminaling of refined petroleum products, including
gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas
Pipelines
37
segment derives its revenues primarily from the transmission, storage, gathering
and sale of natural gas. Our CO2 Pipelines segment derives its revenues
primarily from the transportation and marketing of carbon dioxide used as a
flooding medium for recovering crude oil from mature oil fields, and from the
production and sale of crude oil from fields in the Permian Basin of West Texas.
Our Terminals segment derives its revenues primarily from the transloading and
storing of refined petroleum products and dry and liquid bulk products,
including coal, petroleum coke, cement, alumina, salt, and chemicals.
Financial information by segment follows (in thousands):
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
---------------------------- ----------------------------
2003 2002 2003 2002
------------- ------------- ------------- -------------
Revenues
Products Pipelines................................. $ 145,874 $ 146,277 $ 435,575 $ 426,736
Natural Gas Pipelines.............................. 1,321,651 829,614 4,143,765 2,168,117
CO2 Pipelines...................................... 66,577 38,191 169,664 104,731
Terminals.......................................... 116,740 107,238 355,123 315,737
------------- ------------- ------------- -------------
Total consolidated revenues........................ $ 1,650,842 $ 1,121,320 $ 5,104,127 $ 3,015,321
============= ============= ============= =============
Operating expenses (a)
Products Pipelines................................. $ 42,784 $ 43,608 $ 124,450 $ 125,383
Natural Gas Pipelines.............................. 1,234,149 752,270 3,887,905 1,949,963
CO2 Pipelines...................................... 21,372 12,772 54,175 38,944
Terminals.......................................... 56,994 53,245 174,941 159,712
------------- ------------- ------------- -------------
Total consolidated operating expenses.............. $ 1,355,299 $ 861,895 $ 4,241,471 $ 2,274,002
============= ============= ============= =============
(a) Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses
and taxes, other than income taxes.
Depreciation, depletion and amortization
Products Pipelines................................. $ 16,827 $ 16,086 $ 50,110 $ 48,130
Natural Gas Pipelines.............................. 13,777 11,489 40,006 35,393
CO2 Pipelines...................................... 15,298 7,505 41,341 21,387
Terminals.......................................... 9,129 7,466 27,137 21,585
------------- ------------- ------------- -------------
Total consol. depreciation, depletion and amortiz.. $ 55,031 $ 42,546 $ 158,594 $ 126,495
============= ============= ============= =============
Earnings from equity investments
Products Pipelines................................. $ 6,989 $ 8,592 $ 22,619 $ 25,700
Natural Gas Pipelines.............................. 5,877 5,691 18,260 17,788
CO2 Pipelines...................................... 7,978 8,526 26,848 26,936
Terminals.......................................... (3) 9 37 (38)
------------- ------------- ------------- -------------
Total consolidated equity earnings................. $ 20,841 $ 22,818 $ 67,764 $ 70,386
============= ============= ============= =============
Amortization of excess cost of equity investments
Products Pipelines................................. $ 819 $ 819 $ 2,461 $ 2,461
Natural Gas Pipelines.............................. 70 70 208 208
CO2 Pipelines...................................... 505 505 1,513 1,513
Terminals.......................................... -- -- -- --
------------- ------------- ------------- -------------
Total consol. amortization of excess cost of invests $ 1,394 $ 1,394 $ 4,182 $ 4,182
============= ============= ============= =============
Income taxes and Other, net - income (expense)
Products Pipelines................................. $ (2,135) $ (2,675) $ (6,591) $ (8,430)
Natural Gas Pipelines.............................. (180) (1) (488) 18
CO2 Pipelines...................................... (62) 6 (77) 96
Terminals.......................................... (554) (1,217) (4,494) (4,670)
------------- ------------- ------------- -------------
Total consolidated income taxes and other, net..... $ (2,931) $ (3,887) $ (11,650) $ (12,986)
============= ============= ============= =============
38
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
---------------------------- ----------------------------
2003 2002 2003 2002
------------- ------------- ------------- -------------
Operating income
Products Pipelines................................. $ 86,263 $ 86,583 $ 261,015 $ 253,223
Natural Gas Pipelines.............................. 73,725 65,855 215,854 182,761
CO2 Pipelines...................................... 29,907 17,914 74,148 44,400
Terminals.......................................... 50,617 46,527 153,045 134,440
------------- ------------- ------------- -------------
Total segment operating income (a) ................ 240,512 216,879 704,062 614,824
Corporate administrative expenses.................. (35,547) (27,476) (104,383) (87,218)
------------- ------------- ------------- -------------
Total consolidated operating income................ $ 204,965 $ 189,403 $ 599,679 $ 527,606
============= ============= ============= =============
(a) Represents amounts reported above as revenues, less operating expenses and
depreciation, depletion and amortization.
Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments
Products Pipelines................................. $ 107,944 $ 108,586 $ 327,153 $ 318,623
Natural Gas Pipelines.............................. 93,199 83,034 273,632 235,960
CO2 Pipelines...................................... 53,121 33,951 142,260 92,819
Terminals.......................................... 59,189 52,785 175,725 151,317
------------- ------------- ------------- -------------
Total segment earnings before DD&A (a)............. 313,453 278,356 918,770 798,719
Total consol. depreciation, depletion and amortiz.. (55,031) (42,546) (158,594) (126,495)
Total consol. amortization of excess cost of invests (1,394) (1,394) (4,182) (4,182)
Interest and corporate administrative expenses (b). (82,852) (76,236) (242,383) (223,912)
------------- ------------- ------------- -------------
Total consolidated net income ..................... $ 174,176 $ 158,180 $ 513,611 $ 444,130
============= ============= ============= =============
(a) Represents amounts reported above as revenues, earnings from equity investments and income taxes and other, net, less
operating expenses.
(b) Includes interest and debt expense, general and administrative expenses, minority interest expense and cumulative effect
adjustment from a change in accounting principle (2003 only).
Segment earnings
Products Pipelines................................. $ 90,298 $ 91,681 $ 274,582 $ 268,032
Natural Gas Pipelines.............................. 79,352 71,475 233,418 200,359
CO2 Pipelines...................................... 37,318 25,941 99,406 69,919
Terminals.......................................... 50,060 45,319 148,588 129,732
------------- ------------- ------------- -------------
Total segment earnings (a)......................... 257,028 234,416 755,994 668,042
Interest and corporate administrative expenses..... (82,852) (76,236) (242,383) (223,912)
------------- ------------- ------------- -------------
Total consolidated net income...................... $ 174,176 $ 158,180 $ 513,611 $ 444,130
============= ============= ============= =============
(a) Represents amounts reported above as revenues, earnings from equity investments and income taxes and other, net, less
operating expenses, depreciation, depletion and amortization and amortization of excess cost of equity investments.
Sept. 30, Dec. 31,
2003 2002
------------- -------------
Assets
Products Pipelines..................... $ 3,125,940 $ 3,088,799
Natural Gas Pipelines.................. 3,183,172 3,121,674
CO2 Pipelines.......................... 838,209 613,980
Terminals.............................. 1,317,308 1,165,096
------------- -------------
Total segment assets................... 8,464,629 7,989,549
Corporate assets (a)................... 216,168 364,027
------------- -------------
Total consolidated assets.............. $ 8,680,797 $ 8,353,576
============= =============
(a) Includes cash, cash equivalents and certain unallocable deferred charges.
12. New Accounting Pronouncements
In January 2003, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 46, "Consolidation of Variable Interest Entities". This
interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial
Statements", provides guidance on the identification of, and financial reporting
for, entities over which control is achieved through means other than voting
rights; such entities are known as variable interest entities (VIE). FIN No. 46
is the guidance that determines:
39
- whether consolidation is required under the "controlling financial
interest" model of ARB No. 51 or other existing authoritative guidance; or
- whether the variable-interest model under FIN No. 46 should be used to
account for existing and new entities.
All entities, other than those excluded from the scope of FIN No. 46, must
first decide whether an entity is a VIE. If an entity meets FIN No. 46's
criteria for VIE status, FIN No. 46 is applicable. Otherwise, existing
authoritative guidance for consolidation should be applied. FIN No. 46 also
provides guidance for identifying the enterprise that will consolidate a VIE,
which is the enterprise that is exposed to the majority of an entity's risks
(defined as expected losses) or receives the majority of the benefits from an
entity's activities (defined as expected residual returns). That enterprise is
referred to as the "primary beneficiary" of the VIE, and FIN No. 46 requires
that the primary beneficiary and all other enterprises that hold a significant
variable interest in a VIE make new disclosure in their financial statements.
Pursuant to FIN No. 46, an entity is considered a VIE if any of the following
factors are present:
- the equity investment in the entity is insufficient to finance the
operations of that entity without additional subordinated financial support
from other parties;
- the equity investors of the entity lack decision-making rights;
- an equity investor holds voting rights that are disproportionately low in
relation to the actual economics of the investor's relationship with the
entity, and substantially all of the entity's activities involve or are
conducted on behalf of that investor;
- other parties protect the equity investors from expected losses;
- parties, other than the equity holders, hold the right to receive the
entity's expected residual returns, or the equity investors' rights to
expected residual returns is capped.
Therefore, some common structures, such as limited partnerships, joint
ventures, trusts, and vendor-financing arrangements, may, in certain instances,
qualify as VIEs under FIN No. 46's criteria. In addition, FIN No. 46 requires
that, upon meeting certain criteria, portions of a legal entity must be
evaluated as separate VIEs, apart from the larger entity.
In October 2003, the FASB deferred the latest date by which all public
entities must apply FIN No. 46, to the first reporting period ending after
December 15, 2003. This broader deferral applies to all VIEs and potential VIEs,
both financial and non-financial in nature. However, the deferral only applies
to VIEs that existed prior to February 1, 2003. The requirements of FIN No. 46
applied immediately to VIEs created after January 31, 2003, and those situations
were not subject to the deferral. Pursuant to the deferral, public companies
must complete their evaluations of VIEs that existed prior to February 1, 2003,
and the consolidation of those for which they are the primary beneficiary for
financial statements issued for the first period ending after December 15, 2003.
For calendar year companies, consolidation of previously existing VIEs will be
required in their December 31, 2003 financial statements. We continue to
evaluate the effect from the adoption of this Statement on our consolidated
financial statements.
40
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
Results of Operations
Throughout the following discussion and analysis, we refer to (i) revenues,
(ii) costs and expenses, (iii) operating income, (iv) earnings from equity
investments, net of amortization of excess cost, and (v) earnings. Costs and
expenses include (i) natural gas purchases and other costs of sales, (ii)
operations and maintenance expenses, (iii) fuel and power expenses, (iv)
depreciation, depletion and amortization, (v) general and administrative
expenses, and (vi) taxes, other than income taxes. Our operating income
represents revenues less costs and expenses. Our earnings represent (i)
operating income, (ii) earnings from equity investments, net of amortization of
excess cost, (iii) interest income and expense, (iv) other income and expense
items, net, (v) minority interest, and (vi) income taxes. We do not attribute
general and administrative expenses, interest income and expense or minority
interest to any of our reportable business segments. For more detailed segment
information, please refer to Note 11 to our Consolidated Financial Statements,
entitled "Reportable Segments" included elsewhere in this report.
Third Quarter 2003 Compared With Third Quarter 2002
Total consolidated net income for the third quarter of 2003 was $174.2
million ($0.49 per diluted unit), up10% from the $158.2 million ($0.50 per
diluted unit) of net income reported for the third quarter of 2002. The $16.0
million quarter-to-quarter increase in earnings demonstrates continued strong
demand for services across our portfolio of pipeline and terminal businesses.
Moving forward, we will continue to focus on increasing the utilization of
existing assets and investing in new infrastructure to help meet growing energy
demand across the United States.
Revenues for the third quarter of 2003 totaled $1,650.8 million, compared
with revenues of $1,121.3 million for the same period last year. Costs and
expenses were $1,445.8 million in the third quarter of 2003, compared with
$931.9 million in the same period a year ago. Our third quarter 2003 operating
income was $205.0 million, 8% over the $189.4 million in operating income earned
during the third quarter of 2002.
During the third quarter, earnings and revenues grew in each of our four
reportable business segments except Products Pipelines, where both earnings and
revenues were essentially flat. The increase in our overall net income was
primarily driven by higher earnings from our CO2 Pipelines and Natural Gas
Pipelines business segments. The increase was mainly due to strong internal
growth of operations since the start of the third quarter of 2002, primarily the
result of higher oil sales volumes and increased natural gas transportation,
storage and sales activity.
Third quarter equity earnings, net of amortization of excess costs, from
investments accounted for under the equity method of accounting were $19.4
million in the third quarter of 2003 and $21.4 million in the third quarter of
2002. Our equity earnings predominantly consist of returns on our investments in
Plantation Pipe Line Company, Cortez Pipeline Company and the Red Cedar
Gathering Company. The $2.0 million (9%) decrease in equity earnings, net of
amortization of excess costs, was primarily due to our acquisition of MKM
Partners, L.P.'s 12.75% ownership interest in the SACROC oil field unit on June
1, 2003, and the subsequent dissolution of MKM Partners, L.P. on June 30, 2003.
MKM Partners, L.P. was an oil and gas joint venture formed on January 1, 2001
and owned 85% by subsidiaries of Marathon Oil Company and 15% by Kinder Morgan
CO2 Company, L.P. Prior to the dissolution of the joint venture, we accounted
for our investment in MKM Partners, L.P. under the equity method of accounting.
On October 15, 2003, we declared a record quarterly cash distribution of
$0.66 per unit (an annualized rate of $2.64) for the third quarter of 2003. This
distribution is 8% higher than the $0.61 per unit distribution we made for the
third quarter of 2002. It will be paid on November 14, 2003 to unitholders of
record on October 31, 2003.
Products Pipelines
Our Products Pipelines segment's third quarter 2003 results were consistent
with the results reported through the first six months of the year and with the
third quarter results from 2002. The segment earned $90.3 million on revenues of
$145.9 million in the third quarter of 2003. In the third quarter of 2002,
Products Pipelines reported earnings of $91.7 million on revenues of $146.3
million. The segment's costs and expenses totaled $59.6 million in
41
the third quarter of 2003 and $59.7 million in the third quarter of 2002.
Operating income for the quarters ended September 30, 2003 and 2002 were $86.3
million and $86.6 million, respectively. Earnings from our Products Pipelines'
equity investments, net of amortization of excess costs, were $6.2 million in
the third quarter of 2003 and $7.8 million in the third quarter of 2002. Income
tax expense decreased to $2.3 million in the third quarter of 2003 from $2.9
million in the same period of 2002.
Third quarter 2003 earnings increases from our Transmix operations, Central
Florida pipeline, Pacific operations and North System were offset by declines in
earnings from our ownership interest in the Cochin pipeline system, our Cypress
products pipeline, our investment in Plantation Pipe Line Company and our West
Coast Terminals. Cochin's earnings and revenues were negatively impacted by a
pipeline rupture and fire in July 2003 that led to the shut down of the system
for 29 days during the third quarter. In addition, the system was operated at
less than maximum pressure for the balance of the quarter. Both the $1.4 million
(2%) and $0.4 million (0%) decreases in quarter-to-quarter segment earnings and
revenues were significantly impacted by a $3.2 million (80%) drop in earnings
and a $3.1 million (41%) drop in revenues from our 44.8% interest in Cochin.
Overall, total segment delivery volumes decreased 2% in the third quarter of
2003 compared to the same quarter of 2002. Gasoline delivery volumes were down
4% due to continued refinery problems in the Southeast and the continuing
process of converting from methyl tertiary-butyl ether (MTBE) to ethanol in the
State of California. MTBE-blended gasoline is being replaced by an ethanol blend
and since ethanol is not shipped in our pipelines, we realize a small reduction
in California gasoline volumes; however, higher fees we earn from
ethanol-related services at our terminals positively contribute to our earnings.
In addition, for the second consecutive quarter in 2003, declines in jet fuel
delivery volumes were more than offset by increases in delivered diesel volumes.
Operations at our transmix facilities, where we process and separate pipeline
transmix into pipeline-quality gasoline and light distillate products on a fee
basis, reported increases of $1.3 million (33%) in earnings and $1.2 million
(19%) in revenues primarily due to a 22% increase in the volume of transmix
processed. Central Florida reported third quarter 2003 increases in earnings and
revenues of $0.7 million (16%) and $0.6 million (7%), respectively, over the
third quarter of 2002, mainly due to an almost 8% increase in delivery volumes
related to customer additions. On our Pacific operations, earnings increased
$0.6 million (1%) and revenues were flat in the third quarter of 2003, when
compared to the same quarter last year. The earnings increase was primarily due
to lower maintenance expenses. Revenues were flat across both quarters as
decreases in mainline delivery volume revenues were offset by increases in
non-transportation terminal revenues, as the market continued to transition to
ethanol, which cannot be shipped through our pipelines but is blended at our
terminals. We also profited from a $0.4 million (19%) increase in earnings and a
$0.5 million (7%) increase in revenues from our North System pipeline.
Throughput deliveries on the pipeline dropped 8% compared to third quarter 2002,
but we benefited from an almost 17% increase in average tariff rates as a result
of an increased Cost of Service tariff agreement filed with the Federal Energy
Regulatory Commission in May 2003.
In addition to the negative impact of Cochin's results, referred to above,
partially offsetting the segment's overall increases in earnings and revenues
were a $0.4 million (34%) decrease in earnings and a $0.4 million (22%) decrease
in revenues from our Cypress pipeline. Cypress' lower earnings resulted from the
drop in revenues, due to customers catching up on liquids volumes earned but not
delivered in prior periods, and to lower throughput volumes.
On July 30, 2003, we experienced a rupture on our Pacific operations' Tucson
to Phoenix line. Through a combination of increased deliveries on our Los
Angeles to Phoenix line and terminal modifications at our Tucson terminal that
allowed volumes of Phoenix-grade gasoline to be trucked into Phoenix, we were
able to deliver most of the volumes into the Phoenix area which normally flow
through the ruptured line. The 8-inch line resumed service on August 24, 2003.
The impact of the rupture on our results of operations for the quarter was not
material. Our longer term plan to ensure adequate capacity into the Phoenix
market is to:
- replace 4,600 feet of 8-inch pipe on the damaged line (which was completed
on September 12, 2003);
- construct approximately four miles of new 12-inch pipe in Phoenix from Star
Pass Boulevard to West Weymouth Avenue to replace existing 8-inch pipe
(estimated completion date is December 15th, 2003); and
42
- construct about seven miles of new 12-inch pipe from Starr Pass Boulevard
to our Tucson terminal to replace existing 8-inch pipe (estimated
completion date is February 1, 2004).
The segment's costs and expenses were flat for the third quarters of 2003 and
2002, and the $1.6 million (21%) decrease in equity earnings, net of
amortization, was mainly due to lower earnings from our investment in Plantation
Pipe Line Company. The decrease was driven by a 6% decrease in
quarter-to-quarter delivery volumes on the Plantation system, primarily due to
various refinery shut-downs in the third quarter of 2003 and to a loss of some
supply and delivery contracts to competing pipelines. The $0.6 million (21%)
decrease in income tax expense was directly related to Plantation's lower
pre-tax income.
Natural Gas Pipelines
Our Natural Gas Pipelines segment again reported strong quarterly results.
The segment reported earnings of $79.4 million on revenues of $1,321.7 million
in the third quarter of 2003. In the third quarter of 2002, the segment reported
earnings of $71.5 million on revenues of $829.6 million. The segment's costs and
expenses were $1,248.0 million in the third quarter of 2003 and $763.7 million
in the third quarter of 2002. Operating income for each of the two quarters
ended September 30, 2003 and 2002 was $73.7 million and $65.9 million,
respectively. Earnings from our Natural Gas Pipelines' equity investments, net
of amortization of excess costs, were $5.8 million in the third quarter of 2003
versus $5.6 million in the same quarter last year. The segment also recognized
income tax expense of $0.7 million in the third quarter of 2003.
The segment's $7.9 million (11%) increase in earnings in the third quarter of
2003 compared to the third quarter of 2002 was primarily attributable to growth
in the operations of our Texas intrastate natural gas pipeline group. The
group's earnings in the third quarter of 2003 exceeded last year's third quarter
amount by $15.2 million, more than offsetting a $7.2 million decrease in
quarter-to-quarter earnings from our two Rocky Mountain natural gas pipeline
systems: Kinder Morgan Interstate Gas Transmission and Trailblazer Pipeline
Company. The earnings increase on our intrastate pipeline systems was driven by
increases in natural gas sales, transportation and storage activities, primarily
related to long-term contracts signed with BP in August 2002. Our intrastate
group reported a 6% increase in natural gas sales volumes in the third quarter
of 2003 compared to the third quarter of 2002. In 2003, we benefited from the
inclusion of a full quarter of results from our Kinder Morgan North Texas and
Mier-Monterrey Mexico pipeline systems, both included as part of the intrastate
pipeline group. These two pipelines reported combined earnings of $4.4 million,
revenues of $6.3 million and costs and expenses of $1.2 million in the third
quarter of 2003. The North Texas pipeline was completed and placed in service in
August 2002, and the Mier-Monterrey pipeline was completed in placed in service
in March 2003. The earnings decrease on our Rocky Mountain pipeline systems was
primarily due to the timing of favorable settlements of operational gas
balancing agreements in the third quarter of 2002.
Increases in sales volumes and prices of natural gas since the end of the
third quarter of 2002 have driven the quarter-to-quarter increase in segment
revenues, but the higher gas prices have likewise increased our natural gas
purchase costs, thereby offsetting some of the growth in revenues from natural
gas sales. The segment's service and other revenues, including transportation
and storage services, increased $23.8 million (27%), primarily due to
incremental demand fee revenues associated with gas transportation agreements.
In total, segment transport volumes were up nearly 9% in the third quarter of
2003 compared to the third quarter of 2002.
As described above, the segment's overall increase in costs and expenses was
mostly due to the higher gas purchase costs incurred by our intrastate gas
pipeline group as a result of the increase in gas prices since the end of the
third quarter of 2002. Non-cash depreciation and amortization expenses were also
higher by $2.3 million (20%) in the third quarter of 2003 versus the third
quarter of 2002. The increase was due to recent capital expenditures made within
our intrastate pipeline operations, including the new capital assets related to
the start-up of the North Texas and Mier-Monterrey pipelines.
The $0.2 million (4%) increase in equity earnings was primarily due to higher
earnings from the segment's 25% ownership interest in Thunder Creek Gas
Services, LLC, mainly due to higher gas gathering revenues. The segment's $0.7
million in income tax expense in the third quarter of 2003 was related to the
earnings from the start-up of our Mier-Monterrey pipeline.
43
CO2 Pipelines
Since the end of the third quarter of 2002, we have profited from both
increased drilling activity and a higher ownership interest (effective June 1,
2003) in the operations of the SACROC oil field unit in the Permian Basin of
West Texas. The CO2 Pipelines segment reported record earnings of $37.3 million
on revenues of $66.6 million in the third quarter of 2003. This compares to
earnings of $25.9 million on revenues of $38.2 million in the third quarter of
2002. Costs and expenses totaled $36.7 million in the third quarter of 2003 and
$20.3 million in the third quarter of 2002. Operating income for each of the
quarters ended September 30, 2003 and 2002 was $29.9 million and $17.9 million,
respectively. In addition, the segment reported $7.5 million in equity earnings,
net of amortization of excess costs, in the quarter ended September 30, 2003.
Equity earnings, net of amortization, totaled $8.0 million in the third quarter
of 2002.
The $11.4 million (44%) increase in quarter-to-quarter segment earnings was
primarily attributable to the $28.4 million (74%) increase in revenues,
partially offset by higher depreciation, depletion and amortization expenses,
and by higher operating, maintenance and fuel and power expenses. The segment's
increase in revenues was mainly due to higher oil production volumes. Oil
production at the SACROC unit averaged 20,900 barrels per day in the third
quarter of 2003, a 55% increase in production over the same period last year.
Production reached over 23,000 barrels per day at the end of September 2003, and
we expect production to surpass 25,000 barrels per day by the end of the year.
As mentioned above, effective June 1, 2003, we acquired MKM Partners, L.P.'s
12.75% ownership interest in the SACROC unit. We acquired this interest for
$23.3 million and the assumption of $1.9 million of liabilities, and the
acquisition increased our ownership interest in SACROC to approximately 97%.
As a result of our oil reserve ownership interests, we are exposed to
commodity price risk, but the risk is mitigated by our long-term hedging
strategy that is intended to generate more stable realized prices. For the
comparable quarters ended September 30, 2003 and 2002, we benefited from an
approximate 4% increase in our realized weighted average price of oil per barrel
(from $22.54 per barrel in third quarter 2002 to $23.50 per barrel in third
quarter 2003). For more information on our hedging activities, see Note 10 to
our Consolidated Financial Statements, included elsewhere in this report.
Additionally, the segment benefited from a $4.0 million adjustment to
revenues due to favorable settlements of pending royalty litigation, and from
slightly higher carbon dioxide transportation revenues due to an increase in
carbon dioxide deliveries to all fields throughout West Texas. While carbon
dioxide delivery volumes increased almost 24% in the third quarter of 2003
compared to the third quarter of 2002, a significant proportion (63%) of the
quarter-to-quarter increase in carbon dioxide delivery volumes resulted from the
inclusion of deliveries from our Centerline pipeline, which began operations in
May 2003. The Centerline Pipeline consists of approximately 113 miles of 16-inch
pipe located in the Permian Basin between Denver City, Texas and Snyder, Texas,
and primarily transports carbon dioxide to the SACROC oil field unit. We do not
recognize profits on carbon dioxide sales to ourselves.
The overall increase in segment earnings was partially offset by higher
depreciation, depletion and amortization charges and by higher operating and
maintenance expenses. Non-cash depletion and depreciation-related charges were
up $7.8 million (104%), a result of the higher production volumes (as depletion
expense is calculated on a per unit production basis), a higher per barrel
depletion rate and additional capital investments made since the end of the
third quarter of 2002. Operating, maintenance, and fuel and power expenses
increased $7.7 million (77%), principally the result of the increase in oil
production volumes.
The segment's $7.5 million of equity earnings in the third quarter of 2003
represents earnings from its 50% ownership interest in Cortez Pipeline Company.
Equity earnings realized in the third quarter of 2002 consisted of $5.9 million
from the segment's equity interest in Cortez and $2.1 million from its previous
15% ownership interest in MKM Partners, L.P. Effective June 30, 2003, MKM
Partners, L.P. was dissolved. The $1.6 million (27%) increase in equity earnings
from Cortez was driven by an almost 14% increase in carbon dioxide delivery
volumes due to the increased demand for carbon dioxide in West Texas.
44
Terminals
Our Terminals segment, including both our bulk and liquids terminal
businesses, reported earnings of $50.1 million on revenues of $116.7 million in
the third quarter of 2003. In the same quarter last year, the segment earned
$45.3 million on revenues of $107.2 million. Costs and expenses for each of the
quarters ended September 30, 2003 and 2002 were $66.1 million and $60.7 million,
respectively. Operating income for each of the quarters ended September 30, 2003
and 2002 was $50.6 million and $46.5 million, respectively.
Both our dry bulk and liquids terminal operations reported quarter-to-quarter
increases in earnings, revenues and operating income. Terminal operations
acquired on or after September 1, 2002 accounted for $2.6 million of the $4.8
million increase in segment earnings.
These acquisitions included:
- the Owensboro Gateway Terminal, acquired effective September 1, 2002;
- the St. Gabriel Terminal, acquired effective September 1, 2002;
- the purchase of four floating cranes at our bulk terminal facility in Port
Sulphur, Louisiana in December 2002; and
- the bulk terminal businesses acquired from M.J. Rudolph Corporation,
effective January 1, 2003.
The above acquisitions contributed an incremental $6.9 million of revenues
and $4.3 million of costs and expenses to the third quarter of 2003 compared to
the third quarter of 2002.
Excluding these acquisitions, terminal earnings increased $2.2 million and
revenues increased $2.6 million in the third quarter of 2003, compared to the
third quarter of 2002. A $2.1 million (3%) increase in liquids terminal revenues
accounted for the majority of the change in segment earnings and revenues. The
revenue increase was primarily due to an increase in refined petroleum imports
to the United States and to expansion projects that have increased the leaseable
capacity at some of our largest liquids terminals. Expansion projects undertaken
since the end of the third quarter of 2002, including the work done at our
Carteret, New Jersey and Pasadena, Texas terminals, have increased our liquids
terminals' leaseable capacity by almost 3% over the third quarter of 2002, more
than offsetting a slight (1.5%) drop in our overall utilization percentage. Over
half of the decline in utilization was associated with tank maintenance.
Revenues at our Carteret terminal accounted for $1.3 million of this increase,
primarily due to the construction of five 100,000 barrel petroleum products
storage tanks since the end of the third quarter of 2002 and to escalations in
annual contract provisions.
In our dry-bulk businesses, excluding the acquisitions above, revenues were
essentially flat, as decreases in revenues from our two largest coal terminals
were virtually offset by increases in revenues from other coal terminals,
petroleum coke and other bulk tonnage transfers, and dock services. The
segment's overall decrease in coal revenues was related to decreases in coal
tonnage handled at our Grand Rivers, Kentucky and Cora, Illinois coal terminals.
As we anticipated and discussed in our Annual Report on Form 10-K for the year
ended December 31, 2002, these terminals experienced a drop in contract volumes
handled for the Tennessee Valley Authority due to the fact that the TVA has
diverted some of its business to new competing coal terminals that have come
on-line since the end of the third quarter of 2002.
Third quarter costs and expenses from all terminals owned during both years
totaled $61.6 million in the third quarter of 2003, compared with $60.5 million
in the comparable period of 2002. The $1.1 million (2%) increase in costs and
expenses was mainly due to higher depreciation expense associated with ongoing
capital improvements at selected terminal sites.
Segment Operating Statistics
Operating statistics for the third quarter of 2003 and 2002 are as follows
(historical pro forma for acquired assets):
45
Three Months Ended
Sept. 30, 2003 Sept. 30, 2002
Products Pipelines
Gasoline (MMBbl)......................... 115.8 120.7
Diesel (MMBbl)........................... 42.0 38.6
Jet Fuel (MMBbl)......................... 28.4 30.0
------ ------
Total Refined Product Volumes (MMBbl).... 186.2 189.3
Natural Gas Liquids (MMBbl).............. 9.4 10.6
------ ------
Total Delivery Volumes (MMBbl) (1)....... 195.6 199.9
Natural Gas Pipelines (2)
Transport Volumes (Bcf) ................. 333.1 306.8
Sales Volumes (Bcf) ..................... 242.9 228.1
CO2 Pipelines
Delivery Volumes (Bcf) (3)............... 129.2 104.4
SACROC Oil Production (MBbl/d) .......... 20.9 13.5
Realized Weighted Average Oil Price per
Bbl (4)................................. $23.50 $22.54
Terminals
Bulk Terminals
Transload Tonnage (MMtons) (5)........ 13.3 14.6
Liquids Terminals
Leaseable Capacity (MMBbl)............ 36.0 35.0
Liquids Utilization %................. 95.5% 97.0%
Note: Historical pro forma for acquired assets.
(1) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
(2) Includes Kinder Morgan Interstate Gas Transmission, Texas Intrastate group
and Trailblazer pipeline volumes.
(3) Includes Cortez, Central Basin, Canyon Reef Carriers and Centerline
pipeline volumes.
(4) Includes all partnership crude oil properties.
(5) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs; excludes operatorship of LAXT bulk terminal.
Other
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. Together, these
items totaled $82.9 million in the third quarter of 2003 and $76.2 million in
the third quarter of 2002.
Our general and administrative expenses totaled $35.6 million in the third
quarter of 2003 compared with $27.5 million in the third quarter of 2002. The
$8.1 million (29%) quarter-to-quarter increase in general and administrative
expenses was principally due to higher legal expenses, employee benefit and
pension costs and overall corporate and worker-related insurance expenses.
Total interest expense, net of interest income, was $44.7 million in the
third quarter of 2003 versus $46.3 million in the same quarter of 2002. The $1.6
million (3%) quarter-to-quarter decrease in net interest charges was due to
lower average borrowing rates during the third quarter of 2003 compared with the
same quarterly period last year.
Minority interest remained relatively flat in the third quarter of each year,
totaling $2.6 million in the third quarter of 2003 versus $2.4 million in the
third quarter of 2002. The $0.2 million (8%) quarterly increase in 2003 over
2002 was chiefly due to higher net income realized by International Marine
Terminals, a Louisiana partnership owned 66 2/3% and controlled by us.
Nine Months Ended September 30, 2003 Compared With Nine Months Ended September
30, 2002
For the nine months ended September 30, 2003, our income before a benefit
from a change in accounting principle was $510.1 million ($1.47 per diluted
unit). This amount is 15% greater than our reported net income of $444.1 million
($1.46 per diluted unit) for the same nine month period of 2002. In 2003, we
benefited from a cumulative effect adjustment of $3.5 million related to a
change in accounting for asset retirement obligations
46
pursuant to our adoption of Statement of Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations" on January 1, 2003. After the
cumulative effect adjustment, our net income for the nine month period ended
September 30, 2003 totaled $513.6 million ($1.49 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.
We reported total revenues of $5,104.1 million for the first nine months of
2003, compared with $3,015.3 million in revenues for the first nine months of
2002. Our costs and expenses were $4,504.4 million for the nine month period
ended September 30, 2003, and $2,487.7 million for the comparable period of
2002. Operating income for the nine months ended September 30, 2003, was $599.7
million, 14% over the $527.6 million in operating income reported for the nine
months ended September 30, 2002. Equity earnings from investments, less
amortization of excess costs, were $63.6 million in the first nine months of
2003 versus $66.2 million in the same period last year.
For the comparative nine month periods of 2003 and 2002, all four of our
business segments reported increases in earnings, operating income and revenues.
The increases were driven by both internal growth, resulting from our ongoing
expansion and capital improvement projects, including our Trailblazer pipeline
expansion and Mier-Monterrey pipeline construction, and by acquisitions,
including natural gas operations, terminal businesses and additional ownership
interests in oil producing field units. The most significant of these actions
was our January 31, 2002 purchase of Kinder Morgan Tejas and the subsequent
integration of its operations into our pre-existing natural gas businesses.
Kinder Morgan Tejas' natural gas operations include a 3,400-mile Texas
intrastate natural gas pipeline system and the subsequent integration of its
operations with our other natural gas pipeline assets in Texas, particularly
Kinder Morgan Texas Pipeline and Kinder Morgan North Texas Pipeline, have
improved our overall results.
Products Pipelines
Our Products Pipelines segment reported earnings of $274.6 million on
revenues of $435.6 million in the first nine months of 2003. In the same nine
month period last year, the segment reported earnings of $268.0 million on
revenues of $426.7 million. Costs and expenses totaled $174.6 million in the
first nine months of 2003 and $173.5 million in the first nine months of 2002.
Operating income for each of the nine month periods ended September 30, 2003 and
2002 was $261.0 million and $253.2 million, respectively. Earnings from our
Products Pipelines' equity investments, net of amortization of excess costs,
were $20.2 million in the first nine month period of 2003 versus $23.2 million
in the comparable period of 2002. Currency translation gains contributed to a
$0.8 million increase in other income items, and income tax expense dropped $1.0
million in the first nine months of 2003 from the same prior year period.
The $6.6 million (2%) increase in segment earnings and the $8.9 million (2%)
increase in segment revenues resulted from returns on assets owned over both
nine month periods, primarily driven by earnings from deliveries of natural gas
liquids on our North System pipeline, terminal services on our Pacific
operations and CALNEV pipeline, processing operations at our pipeline transmix
facilities and deliveries of refined petroleum products on our Central Florida
pipeline. Partially offsetting the positive overall changes in segment earnings
and revenues were decreases in earnings and revenues from our proportionate
share of the Cochin pipeline and our Cypress pipeline, as well as lower earnings
from our equity investment in the Plantation Pipe Line Company.
Earnings from our North System were up $3.6 million (47%) and revenues were
up $4.2 million (17%) in the first nine months of 2003, compared to the same
period of 2002. As described above in our quarterly discussion and analysis, the
increases were mostly due to higher revenues associated with higher average
tariff rates in the 2003 period. Throughput volumes on the North System matched
last year's totals due to cold weather in the Midwest during the first quarter
of 2003 and overall strong propane demand. Combined earnings and revenues from
our Pacific operations and CALNEV pipeline increased $5.2 million (3%) and $6.6
million (3%), respectively. The increases were primarily the result of increased
ethanol blending operations and higher revenues from CALNEV delivery volumes,
due to an almost 6% increase in average tariff rates driven by an increase in
transportation of longer-haul, higher margin barrels. Earnings from our transmix
operations increased $2.6 million (21%) in the first nine months of 2003, when
compared to the same period a year earlier. The increase was the result of a
$2.5 million (12%) increase in transmix processing revenues, due to a similar
increase in transmix processing volumes. Our transmix processing activities are
primarily performed on a "for fee" basis pursuant to a long-term contract
expiring
47
in 2010. Finally, earnings and revenues from our Central Florida pipeline in the
first nine months of 2003 increased $2.3 million (15%) and $1.3 million (5%),
respectively, from the same period in 2002. The revenue increase was primarily
due to an almost 3% increase in transport volumes due to the addition of new
customers, and the earnings increase resulted from higher revenues and favorable
adjustments to operating expenses made in the second quarter of 2003.
Partially offsetting the segment's period-to-period overall increases in
earnings and revenues were decreased earnings and revenues from the Cochin
pipeline system. Cochin's earnings decreased $5.3 million (40%) in the first
nine months of 2003, when compared to the same nine months of 2002. The decrease
was mainly due to a $6.3 million (26%) decrease in revenues, the result of both
lower delivery volumes associated with decreased propane production in western
Canada and a pipeline rupture and fire in July 2003, as referred to above in our
quarterly discussion and analysis. Additionally, earnings from our Cypress
pipeline were down $0.7 million (23%) in the comparable nine month periods of
2003 and 2002. The decrease was the result of a corresponding $0.7 million (14%)
decrease in revenues, mainly the result of customers catching up on liquids
volumes earned but not delivered in prior periods.
The segment's costs and expenses were essentially even across both nine month
periods. The $1.1 million (1%) increase in the segment's costs and expenses was
mostly due to higher depreciation charges and higher property tax expenses, both
related to capital investments made since the end of the third quarter of 2002.
The $3.0 million (13%) decrease in equity earnings and the $1.0 million (11%)
decrease in income tax expenses related to lower returns from our investment in
Plantation Pipe Line Company. Plantation's product transport delivery volumes
were down 6% in the nine months ended September 30, 2003 compared to the same
time period of 2002, when Plantation enjoyed record throughput. As discussed
above in our quarterly discussion and analysis, the decrease was primarily due
to various refinery shut-downs in the third quarter of 2003 and to a loss of
certain supply and delivery contracts to competing pipelines. The decrease in
income tax expense was directly related to Plantation's lower income.
Natural Gas Pipelines
Our Natural Gas Pipelines segment reported earnings of $233.4 million on
revenues of $4,143.8 million in the first nine months of 2003. In the first nine
months of 2002, the segment reported earnings of $200.4 million on revenues of
$2,168.1 million. The segment's costs and expenses were $3,927.9 million in the
first nine months of 2003 and $1,985.3 million in same period of 2002. Operating
income for each of the nine months ended September 30, 2003 and 2002 was $215.9
million and $182.8 million, respectively. Earnings from our Natural Gas
Pipelines' equity investments, net of amortization of excess costs, were $18.1
million in the nine month period ended September 30, 2003 and $17.6 million in
the same period a year ago. The segment also recognized income tax expense of
$1.5 million in the first nine months of 2003, and no income tax expense in the
comparable period of 2002.
The largest portion of our overall increase in consolidated net income in the
comparable nine month periods of 2003 and 2002 came from the increase in
earnings from our Natural Gas Pipelines segment. The increase was primarily the
result of our January 31, 2002 acquisition of Kinder Morgan Tejas and the
subsequent integration of Kinder Morgan Tejas with our Kinder Morgan Texas
Pipeline system, North Texas pipeline, and Mier-Monterrey pipeline. Together,
the four operations comprise our Texas intrastate natural gas pipeline group.
The acquisition, construction and subsequent integration of all of our natural
gas pipeline assets in and around the State of Texas has produced a very
strategic intrastate pipeline business combination.
The segment's $33.0 million (16%) increase in earnings in the first nine
months of 2003 compared to the first nine months of 2002 was attributable
primarily to internal growth from this intrastate pipeline group. The intrastate
pipeline group accounted for approximately $28.1 million of the total
period-to-period increase in segment earnings. Our North Texas and
Mier-Monterrey pipeline systems, both placed in service since the end of the
second quarter of 2002, reported combined earnings of $9.3 million, revenues of
$13.3 million and costs and expenses of $2.7 million in the first nine months of
2003. Also, during 2003, we received a full nine-month benefit from the
expansion of our Trailblazer pipeline system. Trailblazer's $59 million
expansion project was completed in May 2002, and in the first nine months of
2003, Trailblazer reported a $4.1 million (14%) increase in earnings and a $9.3
million (25%)
48
increase in revenues, compared to the first nine months of 2002. The increases
in earnings and revenues resulted from both an 18% increase in transport volumes
and a 7% increase in average tariff rates in the 2003 period over the 2002
period.
Overall, the segment's significant increases in period-to-period revenues and
costs and expenses related primarily to higher natural gas prices since the end
of the third quarter of 2002. Both Kinder Morgan Tejas and Kinder Morgan Texas
Pipeline purchase and sell significant volumes of natural gas, which is
transported through their pipeline systems. Our objective is to match purchases
and sales in the aggregate, thus locking-in the equivalent of a transportation
fee. This purchase and sale activity results in considerably higher revenues and
cost of sales expense compared to the interstate natural gas pipeline systems of
Kinder Morgan Interstate Gas Transmission and Trailblazer Pipeline Company. Both
KMIGT and Trailblazer charge a transportation fee for gas transmission service
but neither system has significant gas purchases and resales.
In addition to the increase in period-to-period segment costs and expenses
attributable to higher gas purchase costs, the segment reported higher
depreciation and amortization charges and higher operating and maintenance
expenses, including fuel and power costs. Depreciation expenses totaled $40.0
million, up 13% from the $35.4 million reported in the first nine months of
2002. The increase was due to the additional capital investments we have made
since the end of the third quarter of 2002 and to an additional month of
depreciation for Kinder Morgan Tejas. The increase in operating, maintenance and
fuel and power expenses were attributable to an increase in natural gas
transmission volumes. By entering into new long-term transportation, storage and
sales contracts with customers like BP and Pemex, and by extending certain
existing contracts with other customers, the segment increased total natural gas
transport volumes by 12% in the first nine months of 2003, compared to the first
nine months of 2002.
Earnings from our Natural Gas Pipelines' equity investments, net of
amortization of excess costs, were relatively stable across both nine month
periods of 2003 and 2002. The $0.5 million (3%) increase in 2003 over 2002 was
mainly related to higher equity earnings from the segment's 25% ownership
interest in Thunder Creek Gas Services, LLC. Thunder Creek had higher income
primarily as a result of higher revenues associated with an increase in gas
gathering volumes. The segment's $1.5 million income tax expense in the nine
month period of 2003 was principally related to the operations of our
Mier-Monterrey pipeline, which was placed in service in March 2003.
CO2 Pipelines
Our CO2 Pipelines segment reported earnings of $99.4 million on revenues of
$169.7 million in the first nine months of 2003. In the same prior year period,
the segment reported earnings of $69.9 million on revenues of $104.7 million.
Costs and expenses totaled $95.6 million in the first nine months of 2003 versus
$60.3 million in the comparable period of 2002. Operating income for each of the
nine months ended September 30, 2003 and 2002 was $74.1 million and $44.4
million, respectively. Equity earnings, net of amortization of excess costs,
were essentially flat across both nine month periods. The segment reported $25.3
million in equity earnings for the nine months ended September 30, 2003 and
$25.4 million in the comparable period of 2002.
The period-to-period increases in revenues and costs and expenses were
chiefly due to the higher production volumes and our increased ownership
interest in the SACROC oil field unit, as referred to above in our quarterly
discussion and analysis. The segment benefited from period-to-period increases
of 56% in oil production volumes from the SACROC unit and 7% in the average
hedged price of oil per barrel. The segment reported an overall 3% increase in
carbon dioxide delivery volumes, including deliveries made by the Centerline
carbon dioxide pipeline, which began operations in May 2003.
The $35.3 million (59%) increase in the segment's costs and expenses
primarily related to higher depreciation, depletion and amortization charges,
higher fuel and power expenses, and higher operating and maintenance expenses.
Non-cash depletion and depreciation-related charges were up $20.0 million (93%),
primarily due to capital investments and acquisitions of property interests
since the end of the third quarter of 2002, as well as a higher per barrel
depletion rate. Fuel and power expenses were up $6.2 million (48%) and operating
and maintenance expenses were up $5.2 million (27%), both primarily the result
of expanded oil field operations and acquired interests.
49
Although the segment's overall equity earnings were essentially unchanged
across both nine month periods, we realized a $0.7 million (4%) increase in
equity earnings from our investment in Cortez Pipeline Company, mainly due to
lower average debt balances and slightly lower borrowing rates. The increase
from Cortez was offset by a $0.8 million decrease in equity earnings from our
previous 15% interest in MKM Partners, L.P. Equity earnings from MKM Partners,
L.P. was lower during 2003 due to the fact that we acquired the partnership's
12.75% ownership interest in the SACROC unit effective June 1, 2003, and the
partnership was dissolved effective June 30, 2003.
Terminals
Our Terminals segment reported earnings of $148.6 million on revenues of
$355.1 million in the first nine months of 2003. In the same period last year,
the segment earned $129.7 million on revenues of $315.7 million. Costs and
expenses for each of the nine months ended September 30, 2003 and 2002 were
$202.1 million and $181.3 million, respectively. Operating income for each of
the nine months ended September 30, 2003 and 2002 was $153.0 million and $134.4
million, respectively.
The increases in segment operating results were driven by the terminal
acquisitions we have made since the beginning of 2002 and by internal growth at
certain existing terminals. Our terminal acquisitions include the businesses
described above in our quarterly discussion and analysis as well as the
acquisition of our Milwaukee bagging operations, effective May 1, 2002. These
terminal acquisitions accounted for $11.7 million of the $18.9 million
period-to-period increase in segment earnings. Combined, the acquired terminal
operations accounted for incremental revenues, costs and expenses and operating
income of $28.2 million, $16.4 million and $11.8 million, respectively.
Earnings from all liquids terminals owned during the same nine month period
of both years increased $10.3 million (12%) in 2003 compared to 2002. Revenues
from these liquids terminal operations increased $11.8 million (7%) and costs
and expenses increased $2.5 million (3%) in the first nine months of 2003,
compared to the same period last year. The increases were primarily due to the
expansion projects and higher petroleum product storage and transfer activities
at some of our largest liquids terminals as described above in our quarterly
discussion and analysis. Our Houston terminal complex, located in Pasadena and
Galena Park, Texas along the Houston Ship Channel, along with our Carteret, New
Jersey terminal on the New York Harbor and our Argo terminal near Chicago all
reported higher earnings in the first nine months of 2003 when compared to the
same period last year. Expansion projects have increased our liquids terminals'
leaseable capacity by almost 3% in the nine month period ended September 30,
2003 compared to the same period in 2002, more than offsetting the slight 1%
drop in our overall utilization percentage. The $2.5 million period-to-period
increase in costs and expenses includes a $2.0 million increase in non-cash
depreciation expense, the result of our ongoing capital spending and investment
projects.
For all bulk terminal businesses owned during the first nine month period of
both years, earnings decreased $3.1 million (7%) in 2003 compared to 2002.
Revenues were flat across both time periods as decreases in revenues from coal
transloading operations and engineering services were offset by increases in
revenues from other bulk tonnage transfers and dock services. Costs and expenses
increased $1.9 million (2%) in the first nine months of 2003, when compared to
the same period of 2002. The increase was primarily due to higher depreciation
expense associated with bulk terminal capital spending made since the end of
September 2002, largely related to capital improvements made in cement handling
operations at our Shipyard River terminal in Charleston, South Carolina.
Segment Operating Statistics
Operating statistics for the first nine months of 2003 and 2002 are as
follows (historical pro forma for acquired assets):
50
Nine Months Ended
-------------------------------
Sept. 30, 2003 Sept. 30, 2002
-------------- --------------
Products Pipelines
Gasoline (MMBbl)......................... 335.8 350.5
Diesel (MMBbl)........................... 119.1 113.1
Jet Fuel (MMBbl)......................... 82.1 86.2
------ ------
Total Refined Product Volumes (MMBbl).... 537.0 549.8
Natural Gas Liquids (MMBbl).............. 30.6 30.5
------ ------
Total Delivery Volumes (MMBbl) (1)....... 567.6 580.3
Natural Gas Pipelines (2)
Transport Volumes (Bcf) ................. 935.7 832.9
Sales Volumes (Bcf) (3).................. 677.8 679.0
CO2 Pipelines
Delivery Volumes (Bcf) (4)............... 336.1 326.8
SACROC Oil Production (MBbl/d) .......... 19.2 12.3
Realized Weighted Average Oil Price per
Bbl (5)................................. $ 24.09 $ 22.46
Terminals
Bulk Terminals
Transload Tonnage (MMtons) (6)........ 42.4 44.3
Liquids Terminals
Leaseable Capacity (MMBbl)............ 36.0 35.0
Liquids Utilization %................. 96.0% 97.0%
Note: Historical pro forma for acquired assets.
(1) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
(2) Includes Kinder Morgan Interstate Gas Transmission, Texas Intrastate
group and Trailblazer pipeline volumes.
(3) First quarter 2002 includes sales volumes under prior management,
which may not be comparable.
(4) Includes Cortez, Central Basin, Canyon Reef Carriers and Centerline
pipeline volumes.
(5) Includes all partnership crude oil properties.
(6) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs; excludes operatorship of LAXT bulk terminal.
Other
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. For the first nine
months of 2003, the negative impact of these items was partially offset by a
$3.5 million cumulative effect adjustment related to our change in accounting
for asset retirement obligations. Together, these items (including the
cumulative effect adjustment) totaled $242.4 million in the first nine month
period of 2003 and $223.9 million in the same prior year period.
Our general and administrative expenses totaled $104.4 million in the first
nine months of 2003 compared with $87.2 million in the same period last year.
The $17.2 million (20%) year-over-year increase in general and administrative
expenses primarily related to higher legal fees, higher employee benefit and
pension costs, and higher corporate and worker-related insurance expenses.
Total interest expense, net of interest income, was $134.6 million in the
first nine months of 2003 versus $129.2 million in the same year-ago period. The
$5.4 million (4%) increase in period-to-period net interest charges was due to
higher average borrowings during the first nine months of 2003, partially offset
by lower average interest rates in the first nine months of 2003 compared with
the same period last year.
Minority interest totaled $6.9 million in the first nine months of 2003,
compared to $7.5 million in the first nine months of 2002. The $0.6 million (8%)
decrease resulted primarily from our May 2002 acquisition of the remaining 33
1/3% ownership interest in Trailblazer Pipeline Company that we did not already
own, thereby eliminating the minority interest relating to Trailblazer.
51
Financial Condition
The following table illustrates the sources of our invested capital. In
addition to our results of operations, these balances are affected by our
financing activities as discussed below (dollars in thousands):
Sept. 30, 2003 Dec. 31, 2002
-------------- -------------
Long-term debt, excluding market value of interest rate swaps...... $ 3,855,803 $ 3,659,533
Minority interest.................................................. 44,144 42,033
Partners' capital.................................................. 3,569,368 3,415,929
------------- ------------
Total capitalization............................................ 7,469,315 7,117,495
Short-term debt, less cash and cash equivalents.................... 43,795 (41,088)
------------- ------------
Total invested capital.......................................... $ 7,513,110 $ 7,076,407
============= ============
Capitalization:
- --------------
Long-term debt, excluding market value of interest rate swaps.. 51.6% 51.4%
Minority interest.............................................. 0.6% 0.6%
Partners' capital.............................................. 47.8% 48.0%
----- -----
100.0% 100.0%
===== =====
Invested Capital:
- ----------------
Total debt, less cash and cash equivalents and excluding market
value of interest rate swaps.............................. 51.9% 51.1%
Partners' capital and minority interest........................ 48.1% 48.9%
----- -----
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:
- cash distributions and sustaining capital expenditures with existing cash
and cash flows from operating activities;
- expansion capital expenditures and working capital deficits with cash
retained as a result of paying quarterly distributions on i-units in
additional i-units, additional borrowings, the issuance of additional
common units or the issuance of additional i-units to KMR;
- interest payments from cash flows from operating activities; and
- debt principal payments with additional borrowings as such debt principal
payments become due or by the issuance of additional common units or the
issuance of additional i-units to KMR.
As a publicly traded limited partnership, our common units are attractive
primarily to individual investors. Individual investors represent a small
segment of the total equity capital market. We believe institutional investors
prefer shares of KMR over our common units due to tax and other regulatory
considerations. Thus, KMR makes purchases of i-units issued by us with the
proceeds from the sale of KMR shares to institutional investors.
As of September 30, 2003, our current commitments for sustaining capital
expenditures were approximately $32.5 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 2003 sustaining capital expenditure plan. All
of our capital expenditures, with the exception of sustaining capital
expenditures, are discretionary.
52
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 $507.3 million for the nine
months ended September 30, 2003, versus $546.3 million in the comparable period
of 2002. The period-to-period decrease of $39.0 million (7%) in cash flow from
operations was primarily the result of a $104.8 million decrease in cash inflows
relative to net changes in working capital items and payments of $44.9 million
in 2003 for reparations and refunds under order from the Federal Energy
Regulatory Commission.
The decrease in funds generated by working capital was mainly due to higher
settlements of related party payables during the first nine months of 2003,
primarily associated with reimbursements to KMI for general and administrative
services and for costs related to the construction of our Mier-Monterrey natural
gas pipeline. The reparation and refund payment was mandated by the FERC as part
of an East line settlement reached in 1999 between shippers and our Pacific
operations pursuant to rates charged by our Pacific operations on the interstate
portion of their products pipelines. For more information on our Pacific
operations' regulatory proceedings, see Note 3 to the Consolidated Financial
Statements included elsewhere in this report.
These decreases in cash discussed above were partially offset by a $95.4
million increase in cash from overall higher partnership income, net of non-cash
items including depreciation charges and undistributed earnings from equity
investments. Also, we realized a $13.1 million increase in cash inflows during
the first nine months of 2003 versus 2002 relative to changes in other
non-current items, principally related to lower payments in 2003 on rate case
issues, business development and project costs. Cash from investment
distributions increased $2.2 million in 2003, primarily due to higher
distributions from our 49% interest in the Red Cedar Gas Gathering Company.
Investing Activities
Net cash used in investing activities was $464.1 million for the nine month
period ended September 30, 2003, compared to $1,218.4 million in the comparable
2002 period. The $754.3 million (62%) decrease in cash used in investing
activities was primarily attributable to higher expenditures made for strategic
acquisitions in the first nine months of 2002. For the nine months ended
September 30, 2002, our acquisition outlays totaled $864.3 million, including
$723.2 million for Kinder Morgan Tejas. For the nine months ended September 30,
2003, our acquisition payments totaled $50.7 million, including $23.3 million
used to acquire an additional 12.75% ownership interest in the SACROC oil field
unit in West Texas.
Effective June 1, 2003, we acquired the MKM joint venture's 12.75% ownership
interest in the SACROC 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%. Additionally, in September 2003, we paid $10.0
million to acquire reversionary interests in the Red Cedar Gas Gathering
Company. The 4% reversionary interests were held by the Southern Ute Indian
Tribe and were scheduled to take effect September 1, 2004 and September 1, 2009.
With the elimination of these reversions, our ownership interest in Red Cedar
will be maintained at 49% in the future. For more information on our
acquisitions, see Note 2 to the Consolidated Financial Statements included
elsewhere in this report.
Offsetting the period-to-period decreases in funds used in investing
activities discussed above was a $70.7 million increase in funds used for
capital expenditures. Including expansion and maintenance projects, our capital
expenditures were $413.2 million in the first nine months of 2003 versus $342.5
million in the same year-ago period. The increase was mainly due to higher
capital investment in our CO2 Pipelines and Products Pipelines business
segments. Our sustaining capital expenditures were $62.4 million for the first
nine months of 2003 compared to $52.3 million for the first nine months of 2002.
53
We continue to expand and grow our existing businesses and have current
projects in place that will significantly add storage and throughput capacity to
our carbon dioxide flooding and terminaling operations. In October 2003, we
started construction on our $30 million investment project that involves the
construction of pipeline, compression and storage facilities to accommodate an
additional six billion cubic feet of natural gas storage capacity at Kinder
Morgan Interstate Gas Transmission's Cheyenne Market Center. The Cheyenne Market
Center offers firm natural gas storage capabilities that will allow for the
receipt, storage and subsequent re-delivery of natural gas supplies at
applicable points located in the vicinity of the Cheyenne Hub in Weld County,
Colorado and our Huntsman storage facility in Cheyenne County, Nebraska.
Financing Activities
Net cash used in financing activities amounted to $41.8 million for the nine
months ended September 30, 2003. In the same nine month period last year, our
financing activities provided $671.7 million. The $713.5 million decrease from
the comparable 2002 period was primarily the result of a $490.8 million decrease
in cash flows from overall debt financing activities and a $157.3 million
decrease in cash flows from partnership equity issuances. Both decreases were
related to our higher acquisition expenditures during 2002, as described above
in our discussion of Investing Activities. We purchased the pipeline and
terminal businesses primarily with borrowings under our commercial paper
program. We then raised funds by completing public and private debt offerings of
senior notes and by issuing additional i-units. We used the proceeds from these
debt and equity issuances to reduce our borrowings under our commercial paper
program.
During the first nine months of 2002, we closed a public offering of $750
million in principal amount of senior notes, completed a private placement of
$750 million in principal amount of senior notes to qualified institutional
buyers and retired a maturing amount of $200 million in principal amount of
senior notes. We also made payments of $55.0 million to retire the outstanding
balance on our Trailblazer Pipeline Company's two-year revolving credit facility
and used $458.4 million to reduce our commercial paper borrowings. During the
first nine months of 2003, we have borrowed an additional $286.9 million under
our commercial paper program and we have used these funds for our asset
acquisitions, capital expansion projects and other partnership activities.
The period-to-period decrease in cash flows from equity financing activities
primarily relates to the difference in cash received from our June 2003 issuance
of common units and our August 2002 issuance of i-units. In June 2003, we issued
in a public offering, 4,600,000 of our common units at a price of $39.35 per
share, less commissions and underwriting expenses. After commissions and
underwriting expenses, we received net proceeds of $173.3 million for the
issuance of these common units. In August 2002, we issued 12,478,900 i-units to
KMR at a price of $27.50 per share, less commissions and underwriting expenses.
After commissions and underwriting expenses, we received net proceeds of $331.2
million for the issuance of these i-units. We used the proceeds from each of
these issuances to reduce the borrowings under our commercial paper program.
The overall decrease in funds provided by our financing activities also
resulted from a $74.0 million increase in distributions to our partners.
Distribution to all partners increased to $500.7 million in the first nine
months of 2003 compared to $426.7 million in the same year-earlier period. The
increase in distributions was due to:
- an increase in the per unit cash distributions paid;
- an increase in the number of units outstanding; and
- an increase in the general partner incentive distributions, which resulted
from both increased cash distributions per unit and an increase in the
number of common units and i-units outstanding.
On August 14, 2003, we paid a quarterly distribution of $0.65 per unit for
the second quarter of 2003, 7% greater than the $0.61 per unit distribution paid
for the second quarter of 2002. We paid this distribution in cash to our common
unitholders and to our class B unitholders. KMR, our sole i-unitholder, received
811,878 additional i-units based on the $0.65 cash distribution per common unit.
For each outstanding i-unit that KMR held, a fraction (0.017138) of an i-unit
was issued. The fraction was determined by dividing:
54
- $0.65, the cash amount distributed per common unit
by
- $37.927, the average of KMR's shares' closing market prices for the ten
consecutive trading days preceding the date on which the shares began to
trade ex-dividend under the rules of the New York Stock Exchange.
On October 15, 2003, we declared a cash distribution for the quarterly period
ended September 30, 2003, of $0.66 per unit. The distribution will be paid on or
before November 14, 2003, to unitholders of record as of October 31, 2003. 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 $0.66 distribution per common unit. The number of i-units
distributed will be 811,625. For each outstanding i-unit that KMR holds, a
fraction of an i-unit (0.016844) will be issued. The fraction was determined by
dividing:
- $0.66, the cash amount distributed per common unit
by
- $39.184, the average of KMR's limited liability shares' closing market
prices from October 15-28, 2003, the ten consecutive trading days preceding
the date on which the shares began to trade ex-dividend under the rules of
the New York Stock Exchange.
We believe that future operating results will continue to support similar
levels of quarterly cash and i-unit distributions; however, no assurance can be
given that future distributions will continue at such levels.
Partnership Distributions
Our partnership agreement requires that we distribute 100% of available cash,
as defined in our partnership agreement, to our partners within 45 days
following the end of each calendar quarter in accordance with their respective
percentage interests. Available cash consists generally of all of our cash
receipts, including cash received by our operating partnerships, less cash
disbursements and net additions to reserves (including any reserves required
under debt instruments for future principal and interest payments) and amounts
payable to the former general partner of SFPP, L.P. in respect of its remaining
0.5% interest in SFPP.
Our general partner is granted discretion by our partnership agreement, which
discretion has been delegated to KMR, subject to the approval of our general
partner in certain cases, to establish, maintain and adjust reserves for future
operating expenses, debt service, maintenance capital expenditures, rate refunds
and distributions for the next four quarters. These reserves are not restricted
by magnitude, but only by type of future cash requirements with which they can
be associated. When KMR determines our quarterly distributions, it considers
current and expected reserve needs along with current and expected cash flows to
identify the appropriate sustainable distribution level.
Typically, our general partner and owners of our common units and Class B
units receive distributions in cash, while KMR, the sole owner of our i-units,
receives distributions in additional i-units. For each outstanding i-unit, a
fraction of an i-unit will be issued. The fraction is calculated by dividing the
amount of cash being distributed per common unit by the average closing price of
KMR's shares over the ten consecutive trading days preceding the date on which
the shares begin to trade ex-dividend under the rules of the New York Stock
Exchange. The cash equivalent of distributions of i-units will be treated as if
it had actually been distributed for purposes of determining the distributions
to our general partner. We do not distribute cash to i-unit owners but retain
the cash for use in our business.
Available cash is initially distributed 98% to our limited partners and 2% to
our general partner. These distribution percentages are modified to provide for
incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
55
- 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;
- 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;
- 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
- fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units in
cash and to owners of i-units in the equivalent number of i-units, and 50%
to our general partner.
Incentive distributions are generally defined as all cash distributions paid
to our general partner that are in excess of 2% of the aggregate value of cash
and i-units being distributed. Our general partner's incentive distribution for
the distribution that we declared for the third quarter of 2003 was $81.8
million. Our general partner's incentive distribution for the distribution that
we declared for the third quarter of 2002 was $69.5 million. Our general
partner's incentive distribution that we paid during the third quarter of 2003
to our general partner (for the second quarter of 2003) was $79.6 million. Our
general partner's incentive distribution that we paid during the third quarter
of 2002 to our general partner (for the second quarter of 2002) was $64.4
million. All partnership distributions we declare for the fourth quarter of each
year are declared and paid in the first quarter of the following year.
There have been no material changes in either certain contractural
obligations or our obligations with respect to other entities which are not
consolidated in our financial statements that would affect the disclosures
presented as of December 31, 2002 in our 2002 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:
- 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;
- economic activity, weather, alternative energy sources, conservation and
technological advances that may affect price trends and demand;
- changes in our tariff rates implemented by the Federal Energy Regulatory
Commission or the California Public Utilities Commission;
- our ability to integrate any acquired operations into our existing
operations;
- our ability to acquire new businesses and assets and to make expansions to
our facilities;
- difficulties or delays experienced by railroads, barges, trucks, ships or
pipelines in delivering products to our terminals or pipelines;
56
- our ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
- shut-downs or cutbacks at major refineries, petrochemical or chemical
plants, ports, utilities, military bases or other businesses that use or
supply our services;
- changes in laws or regulations, third party relations and approvals,
decisions of courts, regulators and governmental bodies may adversely
affect our business or our ability to compete;
- 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;
- 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;
- interruptions of electric power supply to our facilities due to natural
disasters, power shortages, strikes, riots, terrorism, war or other causes;
- acts of nature, sabotage, terrorism or other similar acts causing damage
greater than our insurance coverage limits;
- the condition of the capital markets and equity markets in the United
States;
- the political and economic stability of the oil producing nations of the
world;
- national, international, regional and local economic, competitive and
regulatory conditions and developments;
- the ability to achieve cost savings and revenue growth;
- rates of inflation;
- interest rates;
- the pace of deregulation of retail natural gas and electricity;
- foreign exchange fluctuations;
- the timing and extent of changes in commodity prices for oil, natural gas,
electricity and certain agricultural products; and
- the timing and success of business development efforts.
You should not put undue reliance on any forward-looking statements.
See Items 1 and 2 "Business and Properties - Risk Factors" of our annual
report filed on Form 10-K for the year ended December 31, 2002, for a more
detailed description of these and other factors that may affect the
forward-looking statements. When considering forward-looking statements, one
should keep in mind the risk factors described in our 2002 Form 10-K report. The
risk factors could cause our actual results to differ materially from those
contained in any forward-looking statement. We disclaim any obligation to update
the above list or to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments. Our future
results also could be adversely impacted by unfavorable results of litigation
and the coming to fruition of contingencies referred to in Note 3 to our
consolidated financial statements included elsewhere in this report.
57
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
There have been no material changes in market risk exposures that would
affect the quantitative and qualitative disclosures presented as of December 31,
2002, in Item 7A of our 2002 Form 10-K report. For more information on our risk
management activities, see Note 10 to our consolidated financial statements
included elsewhere in this report.
Item 4. Controls and Procedures.
As of the end of the quarter ended September 30, 2003, our management,
including our Chief Executive Officer and Chief Financial Officer, has evaluated
the effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934.
There are inherent limitations to the effectiveness of any system of disclosure
controls and procedures, including the possibility of human error and the
circumvention or overriding of the controls and procedures. Accordingly, even
effective disclosure controls and procedures can only provide reasonable
assurance of achieving their control objectives. Based upon and as of the date
of the evaluation, our Chief Executive Officer and our Chief Financial Officer
concluded that the design and operation of our disclosure controls and
procedures were effective in all material respects to provide reasonable
assurance that information required to be disclosed in the reports we file and
submit under the Exchange Act is recorded, processed, summarized and reported as
and when required. There has been no change in our internal control over
financial reporting during the quarter ended September 30, 2003 that has
materially affected, or is reasonably likely to materially affect, our internal
control over financial reporting.
58
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 3 to our consolidated financial statements entitled
"Litigation and Other Contingencies," which is incorporated herein by reference.
Item 2. Changes in Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Item 5. Other Information.
Corporate Governance
In October 2003, the boards of directors of KMR and our general partner took
a number of corporate governance actions, including:
- establishing the position of Lead Director and electing Mr. Perry M.
Waughtal to serve a one-year term in that position;
- establishing a separate Nominating and Governance Committee; and
- adopting a number of committee charters and policies intended to comply
with the Sarbanes-Oxley Act of 2002 and other expected Securities and
Exchange Commission and New York Stock Exchange requirements.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits
4.1 -- Certain instruments with respect to long-term debt of the Partnership
and its consolidated subsidiaries which relate to debt that does not
exceed 10% of the total assets of the Partnership and its consolidated
subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of
Regulation S-K, 17 C.F.R. ss.229.601.
11 -- Statement re: computation of per share earnings.
31.1 -- Certification by CEO pursuant to Rule 13A-14 or 15D 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 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.
59
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.
- ---------------------
(b) Reports on Form 8-K
Current report dated August 4, 2003 on Form 8-K was furnished on August 5,
2003, pursuant to Item 9 of that form. We provided notice that we, along with
Kinder Morgan, Inc., a subsidiary of which serves as our general partner, and
Kinder Morgan Management, LLC, a subsidiary of our general partner that manages
and controls our business and affairs, intended to make presentations on August
5, 2003 and August 6, 2003 at various meetings with investors, analysts and
others to discuss the second quarter 2003 and second quarter year-to-date 2003
financial results, business plans and objectives of us, Kinder Morgan, Inc. and
Kinder Morgan Management, LLC. Notice was also given that prior to the meeting,
interested parties would be able to view the materials presented at the meetings
by visiting Kinder Morgan, Inc.'s website at: http://www.kindermorgan.com/
investor/presentations.
Current report dated September 16, 2003 on Form 8-K was furnished on
September 16, 2003, pursuant to Item 9 of that form. We provided notice that we,
along with Kinder Morgan, Inc., a subsidiary of which serves as our general
partner, and Kinder Morgan Management, LLC, a subsidiary of our general partner
that manages and controls our business and affairs, intended to make
presentations on September 17, 2003, at various meetings with investors,
analysts and others, and on September 18, 2003, at the Merrill Lynch Power & Gas
Leaders Conference, to discuss the second quarter 2003 and second quarter
year-to-date 2003 financial results, business plans and objectives of us, Kinder
Morgan, Inc. and Kinder Morgan Management, LLC. Notice was also given that prior
to the meeting, interested parties would be able to view the materials presented
at the meetings by visiting Kinder Morgan, Inc.'s website at:
http://www.kindermorgan.com/ investor/presentations.
Current report dated October 21, 2003 on Form 8-K was furnished on October
21, 2003, pursuant to Item 9 of that form. We provided notice that we, along
with Kinder Morgan, Inc., a subsidiary of which serves as our general partner,
and Kinder Morgan Management, LLC, a subsidiary of our general partner that
manages and controls our business and affairs, intended to discuss and answer
questions related to our carbon dioxide business in a live webcast. Interested
parties would be able to access the webcast by visiting:
http://www.firstcallevents.com/
service/ajwz391859932gf12.html. The webcast began at 4:30 p.m. E.S.T on October
21, 2003, and is archived at Kinder Morgan, Inc.'s website at:
http://www.kindermorgan.com and at: http://www.prnewswire.com.
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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, Treasurer and Chief Financial
Officer of Kinder Morgan Management, LLC,
Delegate of Kinder Morgan G.P., Inc.
(principal financial officer and principal
accounting officer)
Date: November ___, 2003
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