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, 2006
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 a large accelerated filer,
an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of
the Securities Exchange Act of 1934). Large accelerated filer [X] Accelerated
filer [ ] Non-accelerated filer [ ]
Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X]
The Registrant had 162,779,676 common units outstanding as of October 31,
2006.
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, 2006 and 2005..................... 3
Consolidated Balance Sheets - September 30, 2006 and
December 31, 2005............................................ 4
Consolidated Statements of Cash Flows - Nine Months
Ended September 30, 2006 and 2005............................ 5
Notes to Consolidated Financial Statements................... 6
Item 2: Management's Discussion and Analysis of Financial
Condition and Results of Operations.......................... 60
Critical Accounting Policies and Estimates................... 60
Results of Operations........................................ 61
Financial Condition.......................................... 79
Information Regarding Forward-Looking Statements............. 86
Item 3: Quantitative and Qualitative Disclosures About Market Risk..... 88
Item 4: Controls and Procedures........................................ 88
PART II. OTHER INFORMATION
Item 1: Legal Proceedings.............................................. 90
Item 1A: Risk Factors................................................... 90
Item 2: Unregistered Sales of Equity Securities and Use of Proceeds.... 90
Item 3: Defaults Upon Senior Securities................................ 90
Item 4: Submission of Matters to a Vote of Security Holders............ 90
Item 5: Other Information.............................................. 90
Item 6: Exhibits....................................................... 90
Signature...................................................... 92
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Unit Amounts)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- -------------------
2006 2005 2006 2005
------ ------ ------ ------
Revenues
Natural gas sales................................... $1,516,874 $1,975,583 $4,679,236 $4,820,732
Services............................................ 532,392 470,469 1,554,052 1,369,496
Product sales and other............................. 224,167 185,202 628,234 539,313
--------- --------- --------- ---------
2,273,433 2,631,254 6,861,522 6,729,541
--------- --------- --------- ---------
Costs, Expenses and Other
Gas purchases and other costs of sales.............. 1,511,217 1,970,579 4,649,851 4,795,923
Operations and maintenance.......................... 208,816 156,486 575,352 448,621
Fuel and power...................................... 56,644 44,951 160,621 132,329
Depreciation, depletion and amortization............ 106,830 85,356 296,780 258,644
General and administrative.......................... 59,694 47,073 183,913 171,058
Taxes, other than income taxes...................... 28,005 28,198 90,859 80,249
Other expense (income).............................. -- -- (15,114) --
--------- --------- --------- ---------
1,971,206 2,332,643 5,942,262 5,886,824
--------- --------- --------- ---------
Operating Income...................................... 302,227 298,611 919,260 842,717
Other Income (Expense)
Earnings from equity investments.................... 14,032 20,512 57,203 69,422
Amortization of excess cost of equity investments... (1,416) (1,407) (4,244) (4,233)
Interest, net....................................... (88,301) (68,348) (246,109) (192,387)
Other, net.......................................... 3,339 2,880 11,179 2,208
Minority Interest..................................... (2,018) (1,806) (7,881) (6,648)
--------- --------- --------- ---------
Income Before Income Taxes............................ 227,863 250,442 729,408 711,079
Income Taxes.......................................... (4,045) (5,055) (11,820) (20,245)
--------- --------- --------- ---------
Net Income............................................ $ 223,818 $ 245,387 $ 717,588 $ 690,834
========= ========= ========= =========
General Partner's interest in Net Income.............. $ 133,881 $ 122,744 $ 393,565 $ 351,724
Limited Partners' interest in Net Income.............. 89,937 122,643 324,023 339,110
--------- --------- --------- ---------
Net Income............................................ $ 223,818 $ 245,387 $ 717,588 $ 690,834
========= ========= ========= =========
Basic Limited Partners' Net Income per Unit........... $ 0.40 $ 0.58 $ 1.45 $ 1.61
========= ========= ========= =========
Diluted Limited Partners' Net Income per Unit......... $ 0.40 $ 0.57 $ 1.45 $ 1.61
========= ========= ========= =========
Weighted average number of units used in computation
of Limited Partners' Net Income per unit:
Basic................................................. 225,809 213,192 222,810 210,001
========= ========= ========= =========
Diluted............................................... 226,155 213,496 223,144 210,199
========= ========= ========= =========
Per unit cash distribution declared................... $ 0.81 $ 0.79 $ 2.43 $ 2.33
========= ========= ========= =========
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,
------------- ------------
2006 2005
---- ----
ASSETS
Current Assets
Cash and cash equivalents..................... $ 23,953 $ 12,108
Accounts, notes and interest receivable, net
Trade...................................... 811,897 1,011,716
Related parties............................ 7,230 2,543
Inventories
Products................................... 15,924 18,820
Materials and supplies..................... 12,909 13,292
Gas imbalances
Trade...................................... 9,464 18,220
Related parties............................ 5,241 -
Gas in underground storage.................... 26,036 7,074
Other current assets.......................... 129,643 131,451
---------- ----------
1,042,297 1,215,224
---------- ----------
Property, Plant and Equipment, net.............. 9,222,800 8,864,584
Investments..................................... 429,924 419,313
Notes receivable
Trade......................................... 1,241 1,468
Related parties............................... 90,854 109,006
Goodwill........................................ 818,800 798,959
Other intangibles, net.......................... 210,074 217,020
Deferred charges and other assets............... 207,042 297,888
---------- ----------
Total Assets....................................
$12,023,032 $11,923,462
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts....................... $ 43,220 $ 30,408
Trade...................................... 677,652 996,174
Related parties............................ 739 16,676
Current portion of long-term debt............. 1,147,213 -
Accrued interest.............................. 45,384 74,886
Accrued taxes................................. 70,903 23,536
Deferred revenues............................. 15,699 10,523
Gas imbalances
Trade...................................... 9,780 22,948
Related parties............................ - 1,646
Accrued other current liabilities............. 689,840 632,088
---------- ----------
2,700,430 1,808,885
---------- ----------
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding................................ 4,386,706 5,220,887
Market value of interest rate swaps........ 44,806 98,469
---------- ----------
4,431,512 5,319,356
Deferred revenues............................. 23,494 6,735
Deferred income taxes......................... 71,225 70,343
Asset retirement obligations.................. 46,873 42,417
Other long-term liabilities and deferred credits 849,271 1,019,655
---------- ----------
5,422,375 6,458,506
---------- ----------
Commitments and Contingencies (Note 3)
Minority Interest............................... 44,666 42,331
---------- ----------
Partners' Capital
Common Units.................................. 2,778,382 2,680,352
Class B Units................................. 104,487 109,594
i-Units....................................... 1,870,072 1,783,570
General Partner............................... 125,113 119,898
Accumulated other comprehensive loss.......... (1,022,493) (1,079,674)
---------- ----------
3,855,561 3,613,740
---------- ----------
Total Liabilities and Partners' Capital......... $12,023,032 $11,923,462
========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
4
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Increase/(Decrease) in Cash and Cash Equivalents In Thousands)
(Unaudited)
Nine Months Ended
September 30,
---------------------------
2006 2005
------------ ------------
Cash Flows From Operating Activities
Net income................................................................. $ 717,588 $ 690,834
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization................................. 296,780 258,644
Amortization of excess cost of equity investments........................ 4,244 4,233
Gains and other non-cash income from the sale of property,
plant and equipment...................................................... (15,716) (635)
Earnings from equity investments......................................... (57,203) (69,422)
Distributions from equity investments...................................... 56,281 51,552
Changes in components of working capital:
Accounts receivable...................................................... 216,850 (249,056)
Other current assets..................................................... (3,775) (394)
Inventories.............................................................. 6,083 (7,172)
Accounts payable......................................................... (334,434) 222,739
Accrued interest......................................................... (29,503) (17,057)
Accrued liabilities...................................................... (2,269) (1,218)
Accrued taxes............................................................ 47,759 40,722
FERC rate reparations and refunds........................................ (19,079) --
Other, net................................................................. (4,879) (22,170)
Net Cash Provided by Operating Activities.................................... 878,727 901,600
Cash Flows From Investing Activities
Acquisitions of assets..................................................... (367,292) (289,751)
Additions to property, plant and equip. for expansion
and maintenance projects................................................... (751,346) (597,186)
Sale of property, plant and equipment, and other net
assets net of removal costs................................................ 71,532 2,987
Net proceeds from margin deposits.......................................... 1,390 --
Contributions to equity investments........................................ (106) (1,202)
Natural gas stored underground and natural gas liquids line-fill........... (12,863) (20,208)
Other...................................................................... (3,401) (211)
Net Cash Used in Investing Activities........................................ (1,062,086) (905,571)
Cash Flows From Financing Activities
Issuance of debt........................................................... 3,730,016 3,812,933
Payment of debt............................................................ (3,005,384) (3,401,190)
Repayments from loans to related party..................................... 1,097 --
Debt issue costs........................................................... (1,554) (5,723)
Increase in cash book overdrafts........................................... 12,812 6,782
Proceeds from issuance of common units..................................... 248,376 285,407
Contributions from minority interest....................................... 109,294 4,509
Distributions to partners:
Common units............................................................. (380,245) (337,994)
Class B units............................................................ (12,858) (12,115)
General Partner.......................................................... (388,350) (337,633)
Minority interest........................................................ (115,424) (8,754)
Other, net................................................................. (2,693) (2,063)
Net Cash Provided by Financing Activities.................................... 195,087 4,159
Effect of exchange rate changes on cash and cash equivalents................. 117 (188)
Increase in Cash and Cash Equivalents........................................ 11,845 --
Cash and Cash Equivalents, beginning of period............................... 12,108 --
Cash and Cash Equivalents, end of period..................................... $ 23,953 $ --
Noncash Investing and Financing Activities:
Contribution of net assets to partnership investments...................... $ 17,003 $ --
Assets acquired by the issuance of units................................... -- 49,635
Assets acquired by the assumption of liabilities........................... 3,725 68,045
The accompanying notes are an integral part of these
consolidated financial statements.
5
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Organization
General
Unless the context requires otherwise, references to "we," "us," "our" or
the "Partnership" are intended to mean Kinder Morgan Energy Partners, L.P. and
its consolidated subsidiaries. We have prepared the accompanying unaudited
consolidated financial statements under the rules and regulations of the
Securities and Exchange Commission. Under such rules and regulations, we have
condensed or omitted certain information and notes normally included in
financial statements prepared in conformity with accounting principles generally
accepted in the United States of America. We believe, however, that our
disclosures are adequate to make the information presented not misleading. The
consolidated financial statements reflect all adjustments which are solely
normal and recurring adjustments that are, in the opinion of our management,
necessary for a fair presentation of our financial results for the interim
periods. You should read these consolidated financial statements in conjunction
with our consolidated financial statements and related notes included in our
Annual Report on Form 10-K for the year ended December 31, 2005.
Kinder Morgan, Inc., Kinder Morgan G.P., 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 our business and affairs,
except that Kinder Morgan Management, LLC cannot take certain specified actions
without the approval of our general partner. Under the delegation of control
agreement, Kinder Morgan Management, LLC manages and controls our business and
affairs and the business and affairs of our operating limited partnerships and
their subsidiaries. Furthermore, in accordance with its limited liability
company agreement, Kinder Morgan Management, LLC's 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
operating partnerships and their majority-owned and controlled subsidiaries. All
significant intercompany items have been eliminated in consolidation. Certain
amounts from prior periods have been reclassified to conform to the current
presentation.
Net Income Per Unit
We compute Basic Limited Partners' Net Income per Unit by dividing our
limited partners' interest in net income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the maximum potential dilution that could occur if units whose issuance
depends on the market price of the units at a future date were considered
outstanding, or if, by application of the treasury stock method, options to
issue units were exercised, both of which would result in the issuance of
additional units that would then share in our net income.
6
2. Acquisitions, Joint Ventures and Divestitures
Acquisitions and Joint Ventures
During the first nine months of 2006, we completed or made adjustments for
the following 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 any liabilities assumed) may be adjusted to reflect
the final determined amounts during a period of time following the acquisition.
The results of operations from these acquisitions are included in our
consolidated financial statements from the acquisition date.
Kinder Morgan River Terminals LLC
Effective October 6, 2004, we acquired Global Materials Services LLC and
its consolidated subsidiaries from Mid-South Terminal Company, L.P. for
approximately $87.9 million, consisting of $31.8 million in cash and $56.1
million of assumed liabilities, including debt of $33.7 million. In the third
quarter of 2006, we made certain immaterial purchase price adjustments based on
a further evaluation of acquired income tax assets and liabilities. Global
Materials Services LLC, which we renamed Kinder Morgan River Terminals LLC,
operates a network of 21 river terminals and two rail transloading facilities
primarily located along the Mississippi River system. The network provides
loading, storage and unloading points for various bulk commodity imports and
exports. The acquisition further expanded and diversified our customer base and
complemented our existing terminal facilities located along the
lower-Mississippi River system. The acquired terminals are included in our
Terminals business segment.
Our allocation of the purchase price to assets acquired and liabilities
assumed after giving effect to the above adjustments is as follows (in
thousands):
Purchase price:
Cash paid, including transaction costs...... $31,819
Debt assumed................................ 33,677
Liabilities assumed (excluding debt)........ 22,371
------
Total purchase price........................ $87,867
======
Allocation of purchase price:
Current assets.............................. $9,855
Property, plant and equipment............... 43,191
Goodwill.................................... 20,218
Other intangibles, net...................... 12,400
Deferred charges and other assets........... 2,203
------
$87,867
======
The $20.2 million of goodwill was assigned to our Terminals business
segment, and the entire amount is expected to be deductible for tax purposes. We
believe this acquisition resulted in the recognition of goodwill primarily due
to the fact that certain advantageous factors and conditions existed that
contributed to the fair value of acquired identifiable net assets and
liabilities exceeding our acquisition price--in the aggregate, these factors
represented goodwill. The $12.4 million of other intangibles in the table above
includes $11.9 million representing the fair value of intangible customer
relationships, which encompass both the contractual life of customer contracts
plus any future customer relationship value beyond the contract life.
General Stevedores, L.P.
Effective July 31, 2005, we acquired all of the partnership interests in
General Stevedores, L.P. for an aggregate consideration of approximately $8.9
million, consisting of $2.0 million in cash, $3.4 million in common units, and
$3.5 million in assumed liabilities, including debt of $3.0 million. In August
2005, we paid the $3.0 million outstanding debt balance. General Stevedores,
L.P. owns, operates and leases barge unloading facilities located along the
Houston, Texas ship channel. Its operations primarily consist of receiving,
storing and transferring semi-finished steel products, including coils, pipe and
billets. The acquisition complemented and further expanded our existing Texas
Gulf Coast terminal facilities, and its operations are included as part of our
Terminals business segment. In the second quarter of 2006, we made our final
purchase price adjustments and the final allocation of our purchase price to
assets acquired and liabilities assumed. The adjustments included minor
revisions to acquired working capital items, and, pursuant to an
7
appraisal of acquired fixed asset and land values, an adjustment of $2.9 million
from property, plant and equipment to goodwill.
Our allocation of the purchase price to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs...... $1,995
Common units issued......................... 3,385
Debt assumed................................ 3,009
Liabilities assumed (excluding debt)........ 479
-----
Total purchase price........................ $8,868
=====
Allocation of purchase price:
Current assets.............................. $ 601
Property, plant and equipment............... 5,197
Goodwill.................................... 2,870
Other intangibles, net ..................... 200
-----
$8,868
=====
The $2.9 million of goodwill was assigned to our Terminals business segment
and the entire amount is expected to be deductible for tax purposes.
Entrega Gas Pipeline LLC
Effective February 23, 2006, Rockies Express Pipeline LLC acquired Entrega
Gas Pipeline LLC from EnCana Corporation for $244.6 million in cash. West2East
Pipeline LLC is a limited liability company and is the sole owner of Rockies
Express Pipeline LLC. We contributed 66 2/3% of the consideration for this
purchase, which corresponded to our percentage ownership of West2East Pipeline
LLC at that time. At the time of acquisition, Sempra Energy held the remaining
33 1/3% ownership interest and contributed this same proportional amount of the
total consideration.
On the acquisition date, Entegra Gas Pipeline LLC owned the Entrega
Pipeline, an interstate natural gas pipeline that will, when fully constructed,
consist of two segments: (i) a 136-mile, 36-inch diameter pipeline that extends
from the Meeker Hub in Rio Blanco County, Colorado to the Wamsutter Hub in
Sweetwater County, Wyoming and (ii) a 191-mile, 42-inch diameter pipeline that
extends from the Wamsutter Hub to the Cheyenne Hub in Weld County, Colorado,
where it will ultimately connect with the Rockies Express Pipeline, an
interstate natural gas pipeline that is currently being developed by Rockies
Express Pipeline LLC. The acquired operations are included as part of our
Natural Gas Pipelines business segment.
In the first quarter of 2006, EnCana Corporation completed construction of
the pipeline segment that extends from the Meeker Hub to the Wamsutter Hub, and
interim service began on that portion of the pipeline. Under the terms of the
purchase and sale agreement, Rockies Express Pipeline LLC will construct the
segment that extends from the Wamsutter Hub to the Cheyenne Hub. Construction on
this pipeline segment began in the second quarter of 2006, and it is anticipated
that both pipeline segments will be placed into service by January 1, 2007.
With regard to Rockies Express Pipeline LLC's acquisition of Entrega Gas
Pipeline LLC, the allocation of the purchase price to assets acquired and
liabilities assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs...... $244,572
Liabilities assumed......................... -
-------
Total purchase price........................ $244,572
=======
Allocation of purchase price:
Current assets.............................. $ -
Property, plant and equipment............... 244,572
Deferred charges and other assets .......... -
-------
$244,572
=======
In April 2006, Rockies Express Pipeline LLC merged with and into Entrega
Gas Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline
LLC. Going forward, the entire pipeline system (including the lines currently
being developed) will be known as the Rockies Express Pipeline. The combined
1,663-mile pipeline system
8
will be one of the largest natural gas pipelines ever constructed in North
America. The approximately $4.4 billion project will have the capability to
transport 1.8 billion cubic feet per day of natural gas, and binding firm
commitments have been secured for virtually all of the pipeline capacity.
On June 30, 2006, ConocoPhillips exercised its option to acquire a 25%
ownership interest in West2East Pipeline LLC (and its subsidiary Rockies Express
Pipeline LLC). On that date, a 24% ownership interest was transferred to
ConocoPhillips, and an additional 1% interest will be transferred once
construction of the entire project is completed. Through our subsidiary Kinder
Morgan W2E Pipeline LLC, we will continue to operate the project but our
ownership interest decreased to 51% of the equity in the project (down from 66
2/3%). Sempra's ownership interest in West2East Pipeline LLC decreased to 25%
(down from 33 1/3%). When construction of the entire project is completed, our
ownership interest will be reduced to 50% at which time the capital accounts of
West2East Pipeline LLC will be trued up to reflect our 50% economics in the
project. We do not anticipate any additional changes in the ownership structure
of the Rockies Express Pipeline project.
West2East Pipeline LLC qualifies as a variable interest entity as defined
by Financial Accounting Standards Board Interpretation No. 46 (Revised December
2003) (FIN 46R), "Consolidation of Variable Interest Entities-An Interpretation
of ARB No. 51," due to the fact that the total equity at risk is not sufficient
to permit the entity to finance its activities without additional subordinated
financial support provided by any parties, including equity holders.
Furthermore, following ConocoPhillips' acquisition of its ownership interest in
West2East Pipeline LLC on June 30, 2006, we receive 50% of the economics of the
Rockies Express project on an ongoing basis, and thus, effective June 30, 2006,
we were no longer considered the primary beneficiary of this entity as defined
by FIN 46R. Accordingly, on that date, we made the change in accounting for our
investment in West2East Pipeline LLC from full consolidation to the equity
method following the decrease in our ownership percentage.
Under the equity method, we record the costs of our investment within the
"Investments" line on our consolidated balance sheet and as changes in the net
assets of West2East Pipeline LLC occur (for example, earnings and dividends), we
recognize our proportional share of that change in the "Investment" account. We
also record our proportional share of any accumulated other comprehensive income
or loss within the "Accumulated other comprehensive loss" line on our
consolidated balance sheet.
Summary financial information as of September 30, 2006, for West2East
Pipeline LLC, which is accounted for under the equity method, is as follows (in
thousands; amounts represent 100% of investee information):
September 30,
Balance Sheet 2006
----------------------------- -----------------
Current assets............................ $ 935
Non-current assets........................ 594,947
Current liabilities....................... 14,098
Non-current liabilities................... 588,296
Accumulated other comprehensive income.... $ (6,512)
In addition, we have guaranteed our proportional share of West2East
Pipeline LLC's debt borrowings under a $2 billion credit facility entered into
by Rockies Express Pipeline LLC. For more information on our contingent debt,
see Note 7.
April 2006 Oil and Gas Properties
On April 7, 2006, Kinder Morgan Production Company L.P. purchased various
oil and gas properties from Journey Acquisition - I, L.P. and Journey 2000, L.P.
for an aggregate consideration of approximately $63.7 million, consisting of
$60.2 million in cash and $3.5 million in assumed liabilities. The acquisition
was effective March 1, 2006. However, we divested certain acquired properties
that are not considered candidates for carbon dioxide enhanced oil recovery,
thus reducing our total investment. As of September 30, 2006, we received
proceeds of approximately $27.0 million from the sale of these properties.
The properties are primarily located in the Permian Basin area of West
Texas and New Mexico, produce approximately 425 barrels of oil equivalent per
day, and include some fields with potential for enhanced oil recovery
9
development near our current carbon dioxide operations. The acquired operations
are included as part of our CO2 business segment. Following our acquisition, and
continuing through the remainder of 2006, we will perform technical evaluations
to confirm the carbon dioxide enhanced oil recovery potential and generate
definitive plans to develop this potential, if proven to be economic.
As of September 30, 2006, our allocation of the purchase price to assets
acquired and liabilities assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs...... $60,188
Long-term liabilities assumed............... 3,548
------
Total purchase price........................ $63,736
======
Allocation of purchase price:
Current assets.............................. $ 229
Property, plant and equipment............... 63,507
------
$63,736
======
April 2006 Terminal Assets
In April 2006, we acquired terminal assets and operations from A&L
Trucking, L.P. and U.S. Development Group in three separate transactions for an
aggregate consideration of approximately $61.9 million, consisting of $61.6
million in cash and $0.3 million in assumed liabilities.
The first transaction included the acquisition of equipment and
infrastructure on the Houston Ship Channel that loads and stores steel products.
The acquired assets complement our nearby bulk terminal facility purchased from
General Stevedores, L.P. in July 2005. The second acquisition included the
purchase of a rail terminal at the Port of Houston that handles both bulk and
liquids products. The rail terminal complements our existing Texas petroleum
coke terminal operations and maximizes the value of our existing deepwater
terminal by providing customers with both rail and vessel transportation options
for bulk products. Thirdly, we acquired the entire membership interest of Lomita
Rail Terminal LLC, a limited liability company that owns a high-volume rail
ethanol terminal in Carson, California. The terminal serves approximately 80% of
the southern California demand for reformulated fuel blend ethanol with
expandable offloading/distribution capacity, and the acquisition expanded our
existing rail transloading operations. All of the acquired assets are included
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...... $61,614
Long-term liabilities assumed............... 253
------
Total purchase price........................ $61,867
======
Allocation of purchase price:
Current assets.............................. $ 509
Property, plant and equipment............... 43,595
Goodwill.................................... 17,763
------
$61,867
======
The $17.8 million of goodwill was assigned to our Terminals business
segment and the entire amount is expected to be deductible for tax purposes.
Pro Forma Information
Pro forma information regarding consolidated income statement information
that assumes all of the acquisitions we have made and joint ventures we have
entered into since January 1, 2005, including the ones listed above, had
occurred as of January 1, 2005, is not materially different from the information
presented in our accompanying consolidated statements of income.
10
Divestitures
Effective April 1, 2006, we sold our Douglas natural gas gathering system
and our Painter Unit fractionation facility to Momentum Energy Group, LLC for
approximately $42.5 million in cash. Our investment in net assets, including all
transaction related accruals, was approximately $24.5 million, most of which
represented property, plant and equipment, and we recognized approximately $18.0
million of gain on the sale of these net assets. We used the proceeds from these
asset sales to reduce the outstanding balance on our commercial paper
borrowings.
The Douglas gathering system is comprised of approximately 1,500 miles of
4-inch to 16-inch diameter pipe that gathers approximately 26 million cubic feet
per day of natural gas from 650 active receipt points. Gathered volumes are
processed at our Douglas plant (which we retained), located in Douglas, Wyoming.
As part of the transaction, we executed a long-term processing agreement with
Momentum Energy Group, LLC which dedicates volumes from the Douglas gathering
system to our Douglas processing plant. The Painter Unit, located near Evanston,
Wyoming, consists of a natural gas processing plant and fractionator, a nitrogen
rejection unit, a natural gas liquids terminal, and interconnecting pipelines
with truck and rail loading facilities. Prior to the sale, we leased the plant
to BP, which operates the fractionator and the associated Millis terminal and
storage facilities for its own account.
Additionally, with regard to the natural gas operating activities of our
Douglas gathering system, we utilized certain derivative financial contracts to
offset our exposure to fluctuating expected future cash flows caused by periodic
changes in the price of natural gas and natural gas liquids. According to the
provisions of current accounting principles, changes in the fair value of
derivative contracts that are designated and effective as cash flow hedges of
forecasted transactions are reported in other comprehensive income (not net
income) and recognized directly in equity (included within accumulated other
comprehensive income/(loss)). Amounts deferred in this way are reclassified to
net income in the same period in which the forecast transactions are recognized
in net income. However, if a hedged transaction is no longer expected to occur
by the end of the originally specified time period, because, for example, the
asset generating the hedged transaction is disposed of prior to the occurrence
of the transaction, then the net cumulative gain or loss recognized in equity
should be transferred to net income in the current period.
Accordingly, upon the sale of our Douglas gathering system, we reclassified
a net loss of $2.9 million from "Accumulated other comprehensive loss" into net
income on those derivative contracts that effectively hedged uncertain future
cash flows associated with forecasted Douglas gathering transactions. We
included the net amount of the gain, $15.1 million, within the caption "Other
expense (income)" in our accompanying consolidated statement of income for the
nine months ended September 30, 2006. For more information on our accounting for
derivative contracts, see Note 10.
3. Litigation, Environmental and Other Contingencies
Federal Energy Regulatory Commission Proceedings
SFPP, L.P.
SFPP, L.P., referred to in this report 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, including shippers' complaints and
protests regarding interstate rates on our Pacific operations' pipeline systems.
OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a
consolidated proceeding that began in September 1992 and includes a number of
shipper complaints against certain rates and practices on SFPP's East Line (from
El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California
to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson
Station in Carson, California. The complainants in the case are El Paso
Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company,
Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products
Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing
Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.),
Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco
Corporation (now part of ConocoPhillips Company). The FERC has ruled that the
complainants have the burden of proof in this proceeding.
11
A FERC administrative law judge held hearings in 1996, and issued an
initial decision in September 1997. The initial decision held that all but one
of SFPP's West Line rates were "grandfathered" under the Energy Policy Act of
1992 and therefore deemed to be just and reasonable; it further held that
complainants had failed to prove "substantially changed circumstances" with
respect to those rates and that the rates therefore could not be challenged in
the Docket No. OR92-8 et al. proceedings, either for the past or prospectively.
However, the initial decision also made rulings generally adverse to SFPP on
certain cost of service issues relating to the evaluation of East Line rates,
which are not "grandfathered" under the Energy Policy Act. Those issues included
the capital structure to be used in computing SFPP's "starting rate base," the
level of income tax allowance SFPP may include in rates and the recovery of
civil and regulatory litigation expenses and certain pipeline reconditioning
costs incurred by SFPP. The initial decision also held SFPP's Watson Station
gathering enhancement service was subject to FERC jurisdiction and ordered SFPP
to file a tariff for that service.
The FERC subsequently reviewed the initial decision, and issued a series of
orders in which it adopted certain rulings made by the administrative law judge,
changed others and modified a number of its own rulings on rehearing. Those
orders began in January 1999, with FERC Opinion No. 435, and continued through
June 2003.
The FERC affirmed that all but one of SFPP's West Line rates are
"grandfathered" and that complainants had failed to satisfy the threshold burden
of demonstrating "substantially changed circumstances" necessary to challenge
those rates. The FERC further held that the one West Line rate that was not
grandfathered did not need to be reduced. The FERC consequently dismissed all
complaints against the West Line rates in Docket Nos. OR92-8 et al. without any
requirement that SFPP reduce, or pay any reparations for, any West Line rate.
The FERC initially modified the initial decision's ruling regarding the
capital structure to be used in computing SFPP's "starting rate base" to be more
favorable to SFPP, but later reversed that ruling. The FERC also made certain
modifications to the calculation of the income tax allowance and other cost of
service components, generally to SFPP's disadvantage.
On multiple occasions, the FERC required SFPP to file revised East Line
rates based on rulings made in the FERC's various orders. SFPP was also directed
to submit compliance filings showing the calculation of the revised rates, the
potential reparations for each complainant and in some cases potential refunds
to shippers. SFPP filed such revised East Line rates and compliance filings in
March 1999, July 2000, November 2001 (revised December 2001), October 2002 and
February 2003 (revised March 2003). Most of those filings were protested by
particular SFPP shippers. The FERC has held that certain of the rates SFPP filed
at the FERC's directive should be reduced retroactively and/or be subject to
refund; SFPP has challenged the FERC's authority to impose such requirements in
this context.
While the FERC initially permitted SFPP to recover certain of its
litigation, pipeline reconditioning and environmental costs, either through a
surcharge on prospective rates or as an offset to potential reparations, it
ultimately limited recovery in such a way that SFPP was not able to make any
such surcharge or take any such offset. Similarly, the FERC initially ruled that
SFPP would not owe reparations to any complainant for any period prior to the
date on which that party's complaint was filed, but ultimately held that each
complainant could recover reparations for a period extending two years prior to
the filing of its complaint (except for Navajo, which was limited to one month
of pre-complaint reparations under a settlement agreement with SFPP's
predecessor). The FERC also ultimately held that SFPP was not required to pay
reparations or refunds for Watson Station gathering enhancement fees charged
prior to filing a FERC tariff for that service.
In April 2003, SFPP paid complainants and other shippers reparations and/or
refunds as required by FERC's orders. In August 2003, SFPP paid shippers an
additional refund as required by FERC's most recent order in the Docket No.
OR92-8 et al. proceedings. We made aggregate payments of $44.9 million in 2003
for reparations and refunds pursuant to a FERC order.
Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond
Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for
review of FERC's Docket OR92-8 et al. orders in the United States Court of
Appeals for the District of Columbia Circuit. Certain of those petitions were
dismissed by the Court of Appeals as premature, and the remaining petitions were
held in abeyance pending completion of agency action. However, in December 2002,
the Court of Appeals returned to its active docket all petitions to review the
FERC's orders in the case
12
through November 2001 and severed petitions regarding later FERC orders. The
severed orders were held in abeyance for later consideration.
Briefing in the Court of Appeals was completed in August 2003, and oral
argument took place on November 12, 2003. On July 20, 2004, the Court of Appeals
issued its opinion in BP West Coast Products, LLC v. Federal Energy Regulatory
Commission, No. 99-1020, On Petitions for Review of Orders of the Federal Energy
Regulatory Commission (Circuit opinion), addressing in part the tariffs of SFPP,
L.P. Among other things, the court's opinion vacated the income tax allowance
portion of the FERC opinion and the order allowing recovery in SFPP's rates for
income taxes and remanded to the FERC this and other matters for further
proceedings consistent with the court's opinion. In reviewing a series of FERC
orders involving SFPP, the Court of Appeals held, among other things, that the
FERC had not adequately justified its policy of providing an oil pipeline
limited partnership with an income tax allowance equal to the proportion of its
limited partnership interests owned by corporate partners. By its terms, the
portion of the opinion addressing SFPP only pertained to SFPP, L.P. and was
based on the record in that case.
The Court of Appeals held that, in the context of the Docket No. OR92-8, et
al. proceedings, all of SFPP's West Line rates were grandfathered other than the
charge for use of SFPP's Watson Station gathering enhancement facility and the
rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded
that the FERC had a reasonable basis for concluding that the addition of a West
Line origin point at East Hynes, California did not involve a new "rate" for
purposes of the Energy Policy Act. It rejected arguments from West Line Shippers
that certain protests and complaints had challenged West Line rates prior to the
enactment of the Energy Policy Act.
The Court of Appeals also held that complainants had failed to satisfy
their burden of demonstrating substantially changed circumstances, and therefore
could not challenge grandfathered West Line rates in the Docket No. OR92-8 et
al. proceedings. It specifically rejected arguments that other shippers could
"piggyback" on the special Energy Policy Act exception permitting Navajo to
challenge grandfathered West Line rates, which Navajo had withdrawn under a
settlement with SFPP. The court remanded to the FERC the changed circumstances
issue "for further consideration" in light of the court's decision regarding
SFPP's tax allowance. While, the FERC had previously held in the OR96-2
proceeding (discussed following) that the tax allowance policy should not be
used as a stand-alone factor in determining when there have been substantially
changed circumstances, the FERC's May 4, 2005 income tax allowance policy
statement (discussed following) may affect how the FERC addresses the changed
circumstances and other issues remanded by the court.
The Court of Appeals upheld the FERC's rulings on most East Line rate
issues; however, it found the FERC's reasoning inadequate on some issues,
including the tax allowance.
The Court of Appeals held the FERC had sufficient evidence to use SFPP's
December 1988 stand-alone capital structure to calculate its starting rate base
as of June 1985; however, it rejected SFPP arguments that would have resulted in
a higher starting rate base.
The Court of Appeals accepted the FERC's treatment of regulatory litigation
costs, including the limitation of recoverable costs and their offset against
"unclaimed reparations" - that is, reparations that could have been awarded to
parties that did not seek them. The court also accepted the FERC's denial of any
recovery for the costs of civil litigation by East Line shippers against SFPP
based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix.
However, the court did not find adequate support for the FERC's decision to
allocate the limited litigation costs that SFPP was allowed to recover in its
rates equally between the East Line and the West Line, and ordered the FERC to
explain that decision further on remand.
The Court of Appeals held the FERC had failed to justify its decision to
deny SFPP any recovery of funds spent to recondition pipe on the East Line, for
which SFPP had spent nearly $6 million between 1995 and 1998. It concluded that
the Commission's reasoning was inconsistent and incomplete, and remanded for
further explanation, noting that "SFPP's shippers are presently enjoying the
benefits of what appears to be an expensive pipeline reconditioning program
without sharing in any of its costs."
The Court of Appeals affirmed the FERC's rulings on reparations in all
respects. It held the Arizona Grocery doctrine did not apply to orders requiring
SFPP to file "interim" rates, and that "FERC only established a final rate at
the completion of the OR92-8 proceedings." It held that the Energy Policy Act
did not limit complainants' ability to seek
13
reparations for up to two years prior to the filing of complaints against rates
that are not grandfathered. It rejected SFPP's arguments that the FERC should
not have used a "test period" to compute reparations that it should have offset
years in which there were underrecoveries against those in which there were
overrecoveries, and that it should have exercised its discretion against
awarding any reparations in this case.
The Court of Appeals also rejected:
o Navajo's argument that its prior settlement with SFPP's predecessor
did not limit its right to seek reparations;
o Valero's argument that it should have been permitted to recover
reparations in the Docket No. OR92-8 et al. proceedings rather than
waiting to seek them, as appropriate, in the Docket No. OR96-2 et al.
proceedings;
o arguments that the former ARCO and Texaco had challenged East Line
rates when they filed a complaint in January 1994 and should therefore
be entitled to recover East Line reparations; and
o Chevron's argument that its reparations period should begin two years
before its September 1992 protest regarding the six-inch line reversal
rather than its August 1993 complaint against East Line rates.
On September 2, 2004, BP West Coast Products, ChevronTexaco, ConocoPhillips
and ExxonMobil filed a petition for rehearing and rehearing en banc asking the
Court of Appeals to reconsider its ruling that West Line rates were not subject
to investigation at the time the Energy Policy Act was enacted. On September 3,
2004, SFPP filed a petition for rehearing asking the court to confirm that the
FERC has the same discretion to address on remand the income tax allowance issue
that administrative agencies normally have when their decisions are set aside by
reviewing courts because they have failed to provide a reasoned basis for their
conclusions. On October 4, 2004, the Court of Appeals denied both petitions
without further comment.
On November 2, 2004, the Court of Appeals issued its mandate remanding the
Docket No. OR92-8 proceedings to the FERC. SFPP and shipper parties subsequently
filed various pleadings with the FERC regarding the proper nature and scope of
the remand proceedings. On December 2, 2004, the FERC issued a Notice of Inquiry
and opened a new proceeding (Docket No. PL05-5) to consider how broadly the
court's ruling on the tax allowance issue in BP West Coast Products, LLC, v.
FERC should affect the range of entities the FERC regulates. The FERC sought
comments on whether the court's ruling applies only to the specific facts of the
SFPP proceeding, or also extends to other capital structures involving
partnerships and other forms of ownership. Comments were filed by numerous
parties, including our Rocky Mountain natural gas pipelines, in the first
quarter of 2005. On May 4, 2005, the FERC adopted a policy statement in Docket
No. PL05-5, providing that all entities owning public utility assets - oil and
gas pipelines and electric utilities - would be permitted to include an income
tax allowance in their cost-of-service rates to reflect the actual or potential
income tax liability attributable to their public utility income, regardless of
the form of ownership. Any tax pass-through entity seeking an income tax
allowance would have to establish that its partners or members have an actual or
potential income tax obligation on the entity's public utility income. The FERC
expressed the intent to implement its policy in individual cases as they arise.
The FERC's decision in Docket No. PL05-5 has been appealed to the United States
Court of Appeals for the District of Columbia, and final briefs were filed on
September 11, 2006.
On December 17, 2004, the Court of Appeals issued orders directing that the
petitions for review relating to FERC orders issued after November 2001 in
OR92-8, which had previously been severed from the main Court of Appeals docket,
should continue to be held in abeyance pending completion of the remand
proceedings before the FERC. Petitions for review of orders issued in other FERC
dockets have since been returned to the court's active docket (discussed further
below in relation to the OR96-2 proceedings).
On January 3, 2005, SFPP filed a petition for a writ of certiorari asking
the United States Supreme Court to review the Court of Appeals' ruling that the
Arizona Grocery doctrine does not apply to "interim" rates, and that "FERC only
established a final rate at the completion of the OR92-8 proceedings." BP West
Coast Products and ExxonMobil also filed a petition for certiorari, on December
30, 2004, seeking review of the Court of Appeals' ruling that there was no
pending investigation of West Line rates at the time of enactment of the Energy
Policy Act (and thus that those rates remained grandfathered). On April 6, 2005,
the Solicitor General filed a brief in opposition to both petitions on behalf of
the FERC and United States, and Navajo, ConocoPhillips, Ultramar, Valero
14
and Western Refining filed an opposition to SFPP's petition. SFPP filed a reply
to those briefs on April 18, 2005. On May 16, 2005, the Supreme Court issued
orders denying the petitions for certiorari filed by SFPP and by BP West Coast
Products and ExxonMobil.
On June 1, 2005, the FERC issued its Order on Remand and Rehearing, which
addressed issues in both the OR92-8 and OR96-2 proceedings (discussed
following).
With respect to the OR92-8 proceedings, the June 1, 2005 order ruled on
several issues that had been remanded by the Court of Appeals in BP West Coast
Products. With respect to the income tax allowance, the FERC held that its May
4, 2005 policy statement would apply in the OR92-8 and OR96-2 proceedings and
that SFPP "should be afforded an income tax allowance on all of its partnership
interests to the extent that the owners of those interests had an actual or
potential tax liability during the periods at issue." It directed SFPP and
opposing parties to file briefs regarding the state of the existing record on
those questions and the need for further proceedings. Those filings are
described below in the discussion of the OR96-2 proceedings. The FERC held that
SFPP's allowable regulatory litigation costs in the OR92-8 proceedings should be
allocated between the East Line and the West Line based on the volumes carried
by those lines during the relevant period. In doing so, it reversed its prior
decision to allocate those costs between the two lines on a 50-50 basis. The
FERC affirmed its prior decision to exclude SFPP's pipeline reconditioning costs
from the cost of service in the OR92-8 proceedings, but stated that SFPP will
have an opportunity to justify much of those reconditioning expenses in the
OR96-2 proceedings. The FERC deferred further proceedings on the
non-grandfathered West Line turbine fuel rate until completion of its review of
the initial decision in phase two of the OR96-2 proceedings. The FERC held that
SFPP's contract charge for use of the Watson Station gathering enhancement
facilities was not grandfathered and required further proceedings before an
administrative law judge to determine the reasonableness of that charge. Those
proceedings are discussed further below.
Petitions for review of the June 1, 2005 order by the United States Court
of Appeals for the District of Columbia Circuit have been filed by SFPP, Navajo,
Western Refining, BP West Coast Products, ExxonMobil, Chevron, ConocoPhillips,
Ultramar and Valero. SFPP moved to intervene in the review proceedings brought
by the other parties. The proceedings before the Court are addressed further
below.
On December 16, 2005, the FERC issued its Order on Initial Decision and on
Certain Remanded Cost Issues, which provided further guidance regarding
application of the FERC's income tax allowance policy in this case, which is
discussed below in connection with the OR96-2 proceedings. The December 16, 2005
order required SFPP to submit a revised East Line cost of service filing
following FERC's rulings regarding the income tax allowance and the ruling in
its June 1, 2005 order regarding the allocation of litigation costs. SFPP is
required to file interim East Line rates effective May 1, 2006 using the lower
of the revised OR92-8 (1994 test year) or OR96-2 (1999 test year) rates, as
adjusted for indexing through April 30, 2006. The December 16, 2005 order also
required SFPP to calculate costs-of-service for West Line turbine fuel movements
based on both a 1994 and 1999 test year and to file interim turbine fuel rates
to be effective May 1, 2006, using the lower of the two test year rates as
indexed through April 30, 2006. SFPP was further required to calculate estimated
reparations for complaining shippers consistent with the order. As described
further below, various parties filed requests for rehearing and petitions for
review of the December 16, 2005 order.
Watson Station proceedings. The FERC's June 1, 2005 Order on Remand and
Rehearing initiated a separate proceeding regarding the reasonableness of the
Watson Station charge. All Watson-related issues in Docket No. OR92-8, Docket
No. OR96-2 and other dockets were also consolidated in that proceeding. After
discovery and the filing of prepared direct testimony, the procedural schedule
was suspended while the parties pursued settlement negotiations.
On May 17, 2006, the parties entered into a settlement agreement and filed
an offer of settlement with the FERC. On August 2, 2006, the FERC approved the
settlement without modification and directed that it be implemented. Pursuant to
the settlement, SFPP filed a new tariff, which took effect September 1, 2006,
lowering SFPP's going-forward rate to $0.003 per barrel and including certain
volumetric pumping rates. SFPP also paid refunds to all shippers for the period
since April 1, 1999 through August 31, 2006. Those refunds were based upon the
difference between the Watson Station charge as filed in SFPP's prior tariffs
and the reduced charges set forth in the agreement. On September 28, 2006, SFPP
filed a refund report with the FERC, setting forth the refunds that had
15
been paid and describing how the refund calculations were made. Two of the
settling parties, BP and ExxonMobil, protested the refund report, and SFPP
responded to that protest. The FERC has yet to act on the protest. As of
September 30, 2006, SFPP had made aggregate payments, including accrued
interest, of $19.1 million.
For the period prior to April 1, 1999, the parties agreed to reserve for
briefing issues related to whether shippers are entitled to reparations. To the
extent any reparations are owed, the parties agreed on how reparations would be
calculated. Initial briefs regarding the reserved legal issues are due November
15, 2006. Reply briefs are due December 21, 2006.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at the
FERC (Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipeline
(Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were
subject to the FERC's jurisdiction under the Interstate Commerce Act, and
claimed that the rate for that service was unlawful. Several other West Line
shippers filed similar complaints and/or motions to intervene.
In an August 1997 order, the FERC held that the movements on the Sepulveda
pipeline were subject to its jurisdiction. On October 6, 1997, SFPP filed a
tariff establishing the initial interstate rate for movements on the Sepulveda
pipeline at 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.
In December 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 pipeline is just and reasonable. Hearings in this
proceeding were held in February and March 2005. SFPP asserted various defenses
against the shippers' claims for reparations and refunds, including the
existence of valid contracts with the shippers and grandfathering protection. In
August 2005, the presiding administrative law judge issued an initial decision
finding that for the period from 1993 to November 1997 (when the Sepulveda FERC
tariff went into effect) the Sepulveda rate should have been lower. The
administrative law judge recommended that SFPP pay reparations and refunds for
alleged overcollections. SFPP filed in October 2005 a brief to the FERC taking
exception to this and other portions of the initial decision. The FERC has not
yet ruled on the initial decision in this proceeding.
OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar
Diamond Shamrock Corporation filed a complaint at the FERC (Docket No. OR97-2)
challenging SFPP's West Line rates, claiming they were unjust and unreasonable
and no longer subject to grandfathering. In October 1997, ARCO, Mobil and Texaco
filed a complaint at the FERC (Docket No. OR98-1) challenging the justness and
reasonableness of all of SFPP's interstate rates, raising claims against SFPP's
East and West Line rates similar to those that have been at issue in Docket Nos.
OR92-8, et al. discussed above, but expanding them to include challenges to
SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno,
Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line. In
November 1997, Ultramar filed a similar, expanded complaint (Docket No. OR98-2).
Tosco Corporation filed a similar complaint in April 1998. The shippers seek
both reparations and prospective rate reductions for movements on all of SFPP's
lines. The FERC accepted the complaints and consolidated them into one
proceeding (Docket No. OR96-2, et al.), but held them in abeyance pending a FERC
decision on review of the initial decision in Docket Nos. OR92-8, et al.
In a companion order to Opinion No. 435, the FERC gave the complainants an
opportunity to amend their complaints in light of Opinion No. 435, which the
complainants did in January 2000. In August 2000, Navajo and Western filed
complaints against SFPP's East Line rates and Ultramar filed an additional
complaint updating its pre-existing challenges to SFPP's interstate pipeline
rates. These complaints were consolidated with the ongoing
16
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 in June
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.
On March 26, 2004, the FERC issued an order on the phase one initial
decision. The FERC's phase one order reversed the initial decision by finding
that SFPP's rates for its North and Oregon Lines should remain "grandfathered"
and amended the initial decision by finding that SFPP's West Line rates (i) to
Yuma, Tucson and Calnev, as of 1995, and (ii) to Phoenix, as of 1997, should no
longer be "grandfathered" and are not just and reasonable. The FERC upheld these
findings in its June 1, 2005 order, although it appears to have found
substantially changed circumstances as to SFPP's West Line rates on a somewhat
different basis than in the phase one order. The FERC's phase one order did not
address prospective West Line rates and whether reparations were necessary. As
discussed below, those issues have been addressed in the FERC's December 16,
2005 order on phase two issues. The FERC's phase one order also did not address
the "grandfathered" status of the Watson Station fee, noting that it would
address that issue once it was ruled on by the Court of Appeals in its review of
the FERC's Opinion No. 435 orders; as noted above, the FERC held in its June 1,
2005 order that the Watson Station fee is not grandfathered. Several of the
participants in the proceeding requested rehearing of the FERC's phase one
order. The FERC denied those requests in its June 1, 2005 order. In addition,
several participants, including SFPP, filed petitions with the United States
Court of Appeals for the District of Columbia Circuit for review of the FERC's
phase one order. On August 13, 2004, the FERC filed a motion to dismiss the
pending petitions for review of the phase one order, which Petitioners,
including SFPP, answered on August 30, 2004. On December 20, 2004, the Court of
Appeals referred the FERC's motion to the merits panel and directed the parties
to address the issues in that motion on brief, thus effectively dismissing the
FERC's motion. In the same order, the Court of Appeals granted a motion to hold
the petitions for review of the FERC's phase one order in abeyance and directed
the parties to file motions to govern future proceeding 30 days after FERC
disposition of the pending rehearing requests. In August 2005, the FERC and SFPP
jointly moved that the Court of Appeals hold the petitions for review of the
March 26, 2004 and June 1, 2005 orders in abeyance due to the pendency of
further action before the FERC on income tax allowance issues. In December 2005,
the Court of Appeals denied this motion and placed the petitions seeking review
of the two orders on the active docket. Initial briefs to the Court were filed
May 30, 2006, and final briefs were filed October 19, 2006. Oral argument has
been scheduled for December 12, 2006.
On July 24, 2006, the FERC filed with the Court of Appeals a motion for
voluntary partial remand, requesting that the portion of the March 26, 2004 and
June 1, 2005 orders in which the FERC removed grandfathering protection from
SFPP's West Line rates and affirmed such protection for the North Line and
Oregon Line rates be returned to the FERC for reconsideration in light of
arguments presented by SFPP and other parties in their initial briefs. In
response to the FERC's remand motion, SFPP filed on August 1, 2006 to reinstate
its West Line rates at the previous, grandfathered level effective August 2,
2006, and asked for FERC approval of such reinstatement on the ground that,
pending the FERC's reconsideration of its grandfathering rulings, the prior
grandfathered rate level is the lawful rate. On August 17, 2006, the Court of
Appeals denied without prejudice the FERC's motion for voluntary partial remand.
In light of this denial, on August 31, 2006, the FERC issued an order rejecting
SFPP's August 1, 2006 filing seeking reinstatement of SFPP's grandfathered West
Line rates.
The FERC's phase one order also held that SFPP failed to seek authorization
for the accounting entries necessary to reflect in SFPP's books, and thus in its
annual report to the FERC ("FERC Form 6"), the purchase price adjustment ("PPA")
arising from our 1998 acquisition of SFPP. The phase one order directed SFPP to
file for permission to reflect the PPA in its FERC Form 6 for the calendar year
1998 and each subsequent year. In its April 26, 2004 compliance filing, SFPP
noted that it had previously requested such permission and that the FERC's
regulations require an oil pipeline to include a PPA in its Form 6 without first
seeking FERC permission to do so. Several parties protested SFPP's compliance
filing. In its June 1, 2005 order, the FERC accepted SFPP's compliance filing.
17
In the June 1, 2005 order, the FERC directed SFPP to file a brief
addressing whether the records developed in the OR92-8 and OR96-2 cases were
sufficient to determine SFPP's entitlement to include an income tax allowance in
its rates under the FERC's new policy statement. On June 16, 2005, SFPP filed
its brief reviewing the pertinent records in the pending cases and applicable
law and demonstrating its entitlement to a full income tax allowance in its
interstate rates. SFPP's opponents in the two cases filed reply briefs
contesting SFPP's presentation. It is not possible to predict with certainty the
ultimate resolution of this issue, particularly given that the FERC's policy
statement and its decision in these cases have been appealed to the federal
courts.
On September 9, 2004, the presiding administrative law judge in OR96-2
issued his initial decision in the phase two portion of this proceeding,
recommending establishment of prospective rates and the calculation of
reparations for complaining shippers with respect to the West Line and East
Line, relying upon cost of service determinations generally unfavorable to SFPP.
On December 16, 2005, the FERC issued an order addressing issues remanded
by the Court of Appeals in the Docket No. OR92-8 proceeding (discussed above)
and the phase two cost of service issues, including income tax allowance issues
arising from the briefing directed by the FERC's June 1, 2005 order. The FERC
directed SFPP to submit compliance filings and revised tariffs by February 28,
2006 (as extended to March 7, 2006) which were to address, in addition to the
OR92-8 matters discussed above, the establishment of interim West Line rates
based on a 1999 test year, indexed forward to a May 1, 2006 effective date and
estimated reparations. The FERC also resolved favorably a number of
methodological issues regarding the calculation of SFPP's income tax allowance
under the May 2005 policy statement and, in its compliance filings, directed
SFPP to submit further information establishing the amount of its income tax
allowance for the years at issue in the OR92-8 and OR96-2 proceedings.
SFPP and Navajo have filed requests for rehearing of the December 16, 2005
order. ExxonMobil, BP West Coast Products, Chevron, Ultramar, and ConocoPhillips
have filed petitions for review of the December 16, 2005 order with the United
States Court of Appeals for the District of Columbia Circuit. On February 13,
2006, the FERC issued an order addressing the pending rehearing requests,
granting the majority of SFPP's requested changes regarding reparations and
methodological issues. SFPP, Navajo, and other parties have filed petitions for
review of the December 16, 2005 and February 13, 2006 orders with the United
States Court of Appeals for the District of Columbia Circuit. On July 31, 2006,
the court of appeals held the appeals of these orders in abeyance pending
further FERC action.
On March 7, 2006, SFPP filed its compliance filings and revised tariffs.
Various shippers filed protests of the tariffs. On April 21, 2006, various
parties submitted comments challenging aspects of the costs of service and rates
reflected in the compliance filings and tariffs. On April 28, 2006, the FERC
issued an order accepting SFPP's tariffs lowering its West Line and East Line
rates in conformity with the FERC's December 2005 and February 2006 orders. On
May 1, 2006, these lower tariff rates became effective. The FERC indicated that
a subsequent order would address the issues raised in the comments. On May 1,
2006, SFPP filed reply comments.
We are not able to predict with certainty the final outcome of the pending
FERC proceedings involving SFPP, should they be carried through to their
conclusion, or whether we can reach a settlement with some or all of the
complainants. The final outcome will depend, in part, on the outcomes of the
appeals of these proceedings and the OR92-8, et al. proceedings taken by SFPP,
complaining shippers, and an intervenor.
We estimated, as of December 31, 2003, that shippers' claims for
reparations totaled approximately $154 million and that prospective rate
reductions would have an aggregate average annual impact of approximately $45
million, with the reparations amount and interest increasing as the timing for
implementation of rate reductions and the payment of reparations has extended
(estimated at a quarterly increase of approximately $9 million). In accordance
with the December 16, 2005 order, rate reductions were implemented on May 1,
2006. We now assume that reparations and accrued interest thereon will be paid
no earlier than the first quarter of 2007; however, the timing, and nature, of
any rate reductions and reparations that may be ordered will likely be affected
by the final disposition of the application of the FERC's new policy statement
on income tax allowances to our Pacific operations in the FERC Docket Nos.
OR92-8, OR96-2, and IS05-230 proceedings. In 2005, we recorded an accrual of
$105.0 million for an expense attributable to an increase in our reserves
related to our rate case liability. We had previously estimated the combined
annual impact of the rate reductions and the payment of reparations sought by
shippers would be approximately 15 cents of distributable cash flow per unit.
18
Based on our review of the FERC's December 16, 2005 order and the FERC's
February 13, 2006 order on rehearing, and subject to the ultimate resolution of
these issues in our compliance filings and subsequent judicial appeals, we now
expect the total annual impact will be less than 15 cents per unit. The actual,
partial year impact on 2006 distributable cash flow is expected to be
approximately $15 million.
Chevron complaint OR02-4 and OR03-5 proceedings. On February 11, 2002,
Chevron, an intervenor in the Docket No. OR96-2, et al. proceeding, filed a
complaint against SFPP in Docket No. OR02-4 along with a motion to consolidate
the complaint with the Docket No. OR96-2, et al. proceeding. On May 21, 2002,
the FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed
a request for rehearing, which the FERC dismissed on September 25, 2002. In
October 2002, Chevron filed a request for rehearing of the FERC's September 25,
2002 Order, which the FERC denied on May 23, 2003. On July 1, 2003, Chevron
filed a petition for review of this denial at the United States Court of Appeals
for the District of Columbia Circuit.
On June 30, 2003, Chevron filed another complaint against SFPP (OR03-5) -
substantially similar to its previous complaint - and moved to consolidate the
complaint with the Docket No. OR96-2, et al. proceeding. Chevron requested that
this new complaint be treated as if it were an amendment to its complaint in
Docket No. OR02-4, which was previously dismissed by the FERC. By this request,
Chevron sought to, in effect, back-date its complaint, and claim for
reparations, to February 2002. SFPP answered Chevron's complaint on July 22,
2003, opposing Chevron's requests. On October 28, 2003, the FERC accepted
Chevron's complaint, but held it in abeyance pending the outcome of the Docket
No. OR96-2, et al. proceeding. The FERC denied Chevron's request for
consolidation and for back-dating. On November 21, 2003, Chevron filed a
petition for review of the FERC's October 28, 2003 order at the Court of Appeals
for the District of Columbia Circuit.
On August 18, 2003, SFPP filed a motion to dismiss Chevron's petition for
review in OR02-4 on the basis that Chevron lacks standing to bring its appeal
and that the case is not ripe for review. Chevron answered on September 10,
2003. SFPP's motion was pending, when the Court of Appeals, on December 8, 2003,
granted Chevron's motion to hold the case in abeyance pending the outcome of the
appeal of the Docket No. OR92-8, et al. proceeding. On January 8, 2004, the
Court of Appeals granted Chevron's motion to have its appeal of the FERC's
decision in OR03-5 consolidated with Chevron's appeal of the FERC's decision in
the OR02-4 proceeding. Following motions to dismiss by the FERC and SFPP, on
December 10, 2004, the Court dismissed Chevron's petition for review in Docket
No. OR03-5 and set Chevron's appeal of the FERC's orders in OR02-4 for briefing.
On January 4, 2005, the Court granted Chevron's request to hold such briefing in
abeyance until after final disposition of the OR96-2 proceeding. Chevron
continues to participate in the Docket No. OR96-2 et al. proceeding as an
intervenor.
Airlines OR04-3 proceeding. On September 21, 2004, America West Airlines,
Inc., Southwest Airlines, Co., Northwest Airlines, Inc. and Continental
Airlines, Inc. (collectively, the "Airlines") filed a complaint against SFPP at
the FERC. The Airlines' complaint alleges that the rates on SFPP's West Line and
SFPP's charge for its gathering enhancement service at Watson Station are not
just and reasonable. The Airlines seek rate reductions and reparations for two
years prior to the filing of their complaint. BP West Coast Products LLC and
ExxonMobil Oil Corporation, ConocoPhillips Company, Navajo Refining Company,
L.P., and ChevronTexaco Products Company all filed timely motions to intervene
in this proceeding. Valero Marketing and Supply Company filed a motion to
intervene one day after the deadline. SFPP answered the Airlines' complaint on
October 12, 2004. On October 29, 2004, the Airlines filed a response to SFPP's
answer and on November 12, 2004, SFPP replied to the Airlines' response. In
March and June 2005, the Airlines filed motions seeking expedited action on
their complaint, and in July 2005, the Airlines filed a motion seeking to sever
issues related to the Watson Station gathering enhancement fee from the OR04-3
proceeding and consolidate them in the proceeding regarding the justness and
reasonableness of that fee that the FERC docketed as part of the June 1, 2005
order. In August 2005, the FERC granted the Airlines' motion to sever and
consolidate the Watson Station fee issues.
OR05-4 and OR05-5 proceedings. On December 22, 2004, BP West Coast Products
LLC and ExxonMobil Oil Corporation filed a complaint against SFPP at the FERC,
which the FERC docketed as OR05-4. The complaint alleges that SFPP's interstate
rates are not just and reasonable, that certain rates found grandfathered by the
FERC are not entitled to such status, and, if so entitled, that "substantially
changed circumstances" have occurred, removing such protection. The complainants
seek rate reductions and reparations for two years prior to the filing of their
complaint and ask that the complaint be consolidated with the Airlines'
complaint in the OR04-3 proceeding.
19
ConocoPhillips Company, Navajo Refining Company, L.P., and Western Refining
Company, L.P. all filed timely motions to intervene in this proceeding. SFPP
answered the complaint on January 24, 2005.
On December 29, 2004, ConocoPhillips filed a complaint against SFPP at the
FERC, which the FERC docketed as OR05-5. The complaint alleges that SFPP's
interstate rates are not just and reasonable, that certain rates found
grandfathered by the FERC are not entitled to such status, and, if so entitled,
that "substantially changed circumstances" have occurred, removing such
protection. ConocoPhillips seeks rate reductions and reparations for two years
prior to the filing of their complaint. BP West Coast Products LLC and
ExxonMobil Oil Corporation, Navajo Refining Company, L.P., and Western Refining
Company, L.P. all filed timely motions to intervene in this proceeding. SFPP
answered the complaint on January 28, 2005.
On February 25, 2005, the FERC consolidated the complaints in Docket Nos.
OR05-4 and OR05-5 and held them in abeyance until after the conclusion of the
various pending SFPP proceedings, deferring any ruling on the validity of the
complaints. On March 28, 2005, BP West Coast and ExxonMobil requested rehearing
of one aspect of the February 25, 2005 order; they argued that any tax allowance
matters in these proceedings could not be decided in, or as a result of, the
FERC's inquiry into income tax allowance in Docket No. PL05-5. On June 8, 2005,
the FERC denied the request for rehearing.
Consolidated Complaints. On February 13, 2006, the FERC consolidated the
complaints in Docket Nos. OR03-5, OR05-4, and OR05-5 and set for hearing the
portions of those complaints attacking SFPP's North Line and Oregon Line rates,
which rates remain grandfathered under the Energy Policy Act of 1992. A
procedural schedule, leading to hearing in early 2007, has been established in
that consolidated proceeding. The FERC also indicated in its order that it would
address the remaining portions of these complaints in the context of its
disposition of SFPP's compliance filings in the OR92-8/OR96-2 proceedings. On
September 5, 2006, the presiding administrative law judge suspended the
procedural schedule in Docket No. OR03-5 pending a decision by the United States
Court of Appeals for the District of Columbia regarding various issues before
the court that directly impact the Docket No. OR03-5 proceeding.
North Line rate case, IS05-230 proceeding. In April 2005, SFPP filed to
increase its North Line interstate rates to reflect increased costs, principally
due to the installation of replacement pipe between Concord and Sacramento,
California. Under FERC regulations, SFPP was required to demonstrate that there
was a substantial divergence between the revenues generated by its existing
North Line rates and its increased costs. SFPP's rate increase was protested by
various shippers and accepted subject to refund by the FERC. A hearing was held
in January and February 2006, and the presiding administrative law judge issued
his initial decision on September 26, 2006.
The initial decision held that SFPP should be allowed to include in its
rate base all costs associated with relocating the Concord to Sacramento
Segment, but to include only 14/20ths of the cost of constructing the new line;
it further held that the FERC's policy statement on income tax allowance is
inconsistent with the Court's decision in BP West Coast Products, LLC v. Federal
Energy Regulatory Commission and that, therefore, SFPP should be allowed no
income tax allowance. While the initial decision held that SFPP could recover
its litigation costs, it otherwise made rulings generally adverse to SFPP on
cost of service issues. These issues included the capital structure to be used
in computing SFPP's "starting rate base," treatment of SFPP's accumulated
deferred income tax account, costs of debt and equity, as well as allocation of
overhead. Briefs on exceptions are due on October 25, 2006. The FERC has not yet
reviewed the initial decision, and it is not possible to predict the outcome of
FERC and/or appellate review.
East Line rate case, IS06-283 proceeding. In April 2006, SFPP filed to
increase its East Line interstate rates to reflect increased costs, principally
due to the installation of replacement pipe between El Paso, Texas and Tucson,
Arizona, significantly increasing the East Line's capacity. Under FERC
regulations, SFPP was required to demonstrate that there was a substantial
divergence between the revenues generated by its existing East Line rates and
its increased costs. SFPP's rate increase was protested by various shippers and
accepted subject to refund by the FERC. FERC established an investigation and
hearing before an administrative law judge. A procedural schedule has been
established, with a hearing scheduled for February 2007.
Index Increases, IS06-356, IS05-327. On May 27, 2005, SFPP filed to
increase certain rates pursuant to the FERC's indexing methodology. Various
shippers protested, and the FERC accepted and suspended all but one of
20
the filed tariffs, subject to SFPP's filing of a revised Page 700 of its FERC
Form 6 and subject to the outcome of various proceedings involving SFPP at the
FERC. BP West Coast Products and ExxonMobil Oil Corporation filed for rehearing
and challenged the revised Page 700 filed by SFPP. On December 12, 2005, the
FERC denied the request for rehearing; this decision is currently on appeal
before the Court of Appeals. Initial briefs were filed on August 25, 2006, and
final briefs are due on November 28, 2006.
On May 30, 2006, SFPP also filed to increase certain interstate rates
pursuant to the FERC's indexing methodology. This filing was protested, but the
FERC determined that SFPP's tariff filing was consistent with the FERC's
regulations. Certain shippers requested rehearing, which the FERC granted for
further consideration on August 21, 2006. The FERC's order has been appealed to
the United States Court of Appeals for the District of Columbia Circuit. On
August 31, 2006, the FERC filed a motion with the Court to hold the case in
abeyance, and SFPP and BP West Coast subsequently intervened. The Court has not
yet issued a ruling on the motions filed by the FERC, SFPP, and BP West Coast.
Calnev Pipe Line LLC
On May 22, 2006, Calnev Pipe Line LLC filed to increase its interstate
rates pursuant to the FERC's indexing methodology applicable to oil pipelines.
The filing was docketed in IS06-296. Calnev's filing was protested by
ExxonMobil, claiming that Calnev was not entitled to an indexing increase in its
rates based on its cost of service. Calnev answered the protest. On June 29,
2006, the FERC accepted and suspended the filing, subject to refund, permitting
the increased rates to go into effect on July 1, 2006. The FERC found that
Calnev's indexed rates exceeded its change in costs to a degree that warranted
establishing an investigation and hearing. However, the FERC initially directed
the parties to attempt to reach a settlement of the dispute before a FERC
settlement judge. The settlement process is proceeding.
California Public Utilities Commission Proceeding
ARCO, Mobil and Texaco filed a complaint against SFPP with the California
Public Utilities Commission on April 7, 1997. The complaint challenges rates
charged by SFPP for intrastate transportation of refined petroleum products
through its pipeline system in the State of California and requests prospective
rate adjustments. On October 1, 1997, the complainants filed testimony seeking
prospective rate reductions aggregating approximately $15 million per year.
On August 6, 1998, the CPUC issued its decision dismissing the
complainants' challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC
granted limited rehearing of its August 1998 decision for the purpose of
addressing the proper ratemaking treatment for partnership tax expenses, the
calculation of environmental costs and the public utility status of SFPP's
Sepulveda Line and its Watson Station gathering enhancement facilities. In
pursuing these rehearing issues, complainants sought prospective rate reductions
aggregating approximately $10 million per year.
On March 16, 2000, SFPP filed an application with the CPUC seeking
authority to justify its rates for intrastate transportation of refined
petroleum products on competitive, market-based conditions rather than on
traditional, cost-of-service analysis.
On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC
asserting that SFPP's California intrastate rates are not just and reasonable
based on a 1998 test year and requesting the CPUC to reduce SFPP's rates
prospectively. The amount of the reduction in SFPP rates sought by the
complainants is not discernible from the complaint.
The rehearing complaint was heard by the CPUC in October 2000, and the
April 2000 complaint and SFPP's market-based application were heard by the CPUC
in February 2001. All three matters stand submitted as of April 13, 2001, and
resolution of these submitted matters may occur at any time.
In October, 2002, the CPUC issued a resolution, referred to in this report
as the Power Surcharge 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
21
the CPUC in determining whether SFPP's overall rates for California intrastate
transportation services are reasonable. The resolution reserves the right to
require refunds, from the date of issuance of the resolution, to the extent the
CPUC's analysis of cost data to be submitted by SFPP demonstrates that SFPP's
California jurisdictional rates are unreasonable in any fashion. On February 21,
2003, SFPP submitted the cost data required by the CPUC, which submittal was
protested by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast
Products LLC, Exxon Mobil Oil Corporation and Chevron Products Company. Issues
raised by the protest, including the reasonableness of SFPP's existing
intrastate transportation rates, were the subject of evidentiary hearings
conducted in December 2003 and may be resolved by the CPUC at any time.
With regard to the CPUC complaints and the Power Surcharge Resolution, we
currently believe the complainants/protestants seek approximately $31 million in
prospective annual tariff reductions. Based upon CPUC practice and procedure
which precludes refunds or reparations in complaints in which the complainants
challenge the reasonableness of rates previously found reasonable by the CPUC
(as is the case with the two pending complaints contesting the reasonableness of
SFPP's rates) except for matters which have been expressly reserved by the CPUC
for further consideration (as is the case with respect to the reasonableness of
the rate charged for use of the Watson Station gathering enhancement
facilities), we currently believe that complainants/protestants are seeking
approximately $15 million in refunds/reparations. There is no way to quantify
the potential extent to which the CPUC could determine that SFPP's existing
California rates are unreasonable.
SFPP also has various, pending ratemaking matters before the CPUC that are
unrelated to the above-referenced complaints and the Power Surcharge Resolution.
On November 22, 2004, SFPP filed an application with the CPUC requesting a $9
million annual increase in existing intrastate rates to reflect the in-service
date of SFPP's replacement and expansion of its Concord-to-Sacramento pipeline.
The requested rate increase, which automatically became effective as of December
22, 2004 pursuant to California Public Utilities Code Section 455.3, is being
collected subject to refund, pending resolution of protests to the application
by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products
LLC, Exxon Mobil Oil Corporation and ChevronTexaco Products Company. Because no
schedule has been established by the CPUC for addressing the issues raised by
the contested rate increase application nor does any record exist upon which the
CPUC could base a decision, SFPP has no basis for estimating either the
prospective rate reductions or the potential refunds at issue or for
establishing a date by which the CPUC is likely to render a decision regarding
the application.
On January 26, 2006, SFPP filed a request for a rate increase of
approximately $5.4 million annually with the CPUC, to be effective as of March
2, 2006. Protests to SFPP's rate increase application have been filed by Tesoro
Refining and Marketing Company, BP West Coast Products LLC, ExxonMobil Oil
Corporation, Southwest Airlines Company, Valero Marketing and Supply Company,
Ultramar Inc. and Chevron Products Company, asserting that the requested rate
increase is unreasonable. As a consequence of the protests, the related rate
increases are being collected subject to refund. Because no schedule has been
established by the CPUC for addressing the issues raised by the contested rate
increase application nor does any record exist upon which the CPUC could base a
decision, SFPP has no basis for estimating either the prospective rate
reductions or the potential refunds at issue or for establishing a date by which
the CPUC is likely to render a decision regarding the application.
On August 25, 2006, SFPP filed an application to increase rates by
approximately $0.5 million annually to recovers costs incurred to comply with
revised Ultra Low Sulfur Diesel regulations and to offset the revenue loss
associated with reduction of the Watson Station Volume Deficiency Charge
(intrastate) by increasing rates on a system-wide basis by approximately $3.1
million annually to be effective as of October 5, 2006. Protests to SFPP's rate
increase application have been filed by Tesoro Refining and Marketing Company,
BP West Coast Products LLC, ExxonMobil Oil Corporation, Southwest Airlines
Company, Valero Marketing and Supply Company, Ultramar Inc. and Chevron Products
Company, asserting that the requested rate increase is unreasonable. As a
consequence of the protests, the related rate increases are being collected
subject to refund. Because no schedule has been established by the CPUC for
addressing the issues raised by the contested rate increase application, nor
does any record exist upon which the CPUC could base a decision, SFPP has no
basis for estimating either the prospective rate reductions, or the potential
refunds at issue, or for establishing a date by which the CPUC is likely to
render a decision regarding the application.
22
All of the referenced pending matters before the CPUC have been
consolidated and assigned to a single Administrative Law Judge who has indicated
his intention to refer the matters to mediation under CPUC procedures applicable
to alternative dispute resolution processes.
With regard to the Power Surcharge Resolution, the November 2004 rate
increase application, the January 2006 rate increase application, and the August
2006 rate increase application, SFPP believes the submission of the required,
representative cost data required by the CPUC indicates that SFPP's existing
rates for California intrastate services remain reasonable and that no rate
reductions or 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.
Other Regulatory Matters
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 or that such challenges will not have a material adverse effect on our
business, financial position, results of operations or cash flows. 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 a material
adverse effect on our business, financial position, results of operations or
cash flows.
Carbon Dioxide Litigation
Kinder Morgan CO2 Company, L.P., Kinder Morgan G.P., Inc., and Cortez
Pipeline Company were among the named defendants in Shores, et al. v. Mobil Oil
Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas
filed December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil
Corp., et al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed
March 29, 2001). These cases were originally filed as class actions on behalf of
classes of overriding royalty interest owners (Shores) and royalty interest
owners (Bank of Denton) for damages relating to alleged underpayment of
royalties on carbon dioxide produced from the McElmo Dome Unit. Although classes
were initially certified at the trial court level, appeals resulted in the
decertification and/or abandonment of the class claims. On February 22, 2005,
the trial judge dismissed both cases for lack of jurisdiction. Some of the
individual plaintiffs in these cases re-filed their claims in new lawsuits
(discussed below).
On May 13, 2004, William Armor, one of the former plaintiffs in the Shores
matter whose claims were dismissed by the Court of Appeals for improper venue,
filed a new case alleging the same claims for underpayment of royalties against
the same defendants previously sued in the Shores case, including Kinder Morgan
CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. Armor v. Shell Oil
Company, et al, No. 04-03559 (14th Judicial District Court, Dallas County, Texas
filed May 13, 2004). Defendants filed their answers and special exceptions on
June 4, 2004. The case is currently set for trial on June 11, 2007.
On May 20, 2005, Josephine Orr Reddy and Eastwood Capital, Ltd., two of the
former plaintiffs in the Bank of Denton matter, filed a new case in Dallas state
district court alleging the same claims for underpayment of royalties. Reddy and
Eastwood Capital, Ltd. v. Shell Oil Company, et al., No. 05-5021 (193rd Judicial
District Court, Dallas County, Texas filed May 20, 2005). The defendants include
Kinder Morgan CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. On June
23, 2005, the plaintiff in the Armor lawsuit filed a motion to transfer and
consolidate the Reddy lawsuit with the Armor lawsuit. On June 28, 2005, the
court in the Armor lawsuit granted the motion to transfer and consolidate and
ordered that the Reddy lawsuit be transferred and consolidated into the Armor
lawsuit. The defendants filed their answer and special exceptions on August 10,
2005. The consolidated Armor/Reddy case is currently set for trial on June 11,
2007.
Shell CO2 Company, Ltd., predecessor in interest to Kinder Morgan CO2
Company, L.P., is among the named counter-claim defendants in Shell Western E&P
Inc. v. Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial
District Court, Harris County, Texas filed June 17, 1998) (the "Bailey State
Court Action"). The counter-claim plaintiffs are overriding royalty interest
owners in the McElmo Dome Unit and have sued seeking damages for underpayment of
royalties on carbon dioxide produced from the McElmo Dome Unit. In the Bailey
23
State Court Action, the counter-claim plaintiffs asserted claims for
fraud/fraudulent inducement, real estate fraud, negligent misrepresentation,
breach of fiduciary duty, breach of contract, negligence, negligence per se,
unjust enrichment, violation of the Texas Securities Act, and open account. The
trial court in the Bailey State Court Action granted a series of summary
judgment motions filed by the counter-claim defendants on all of the
counter-plaintiffs' counter-claims except for the fraud-based claims. In 2004,
one of the counter-plaintiffs (Gerald Bailey) amended his counter-suit to allege
purported claims as a private relator under the False Claims Act and antitrust
claims. The federal government elected to not intervene in the False Claims Act
counter-suit. On March 24, 2005, Bailey filed a notice of removal, and the case
was transferred to federal court. Shell Western E&P Inc. v. Gerald O. Bailey and
Bridwell Oil Company, No. H-05-1029 (S.D. Tex., Houston Division removed March
24, 2005) (the "Bailey Houston Federal Court Action"). Also on March 24, 2005,
Bailey filed an instrument under seal in the Bailey Houston Federal Court Action
that was later determined to be a motion to transfer venue of that case to the
federal district court of Colorado, in which Bailey and two other plaintiffs
filed another suit against Kinder Morgan CO2 Company, L.P. asserting claims
under the False Claims Act. The Houston federal district judge ordered that
Bailey take steps to have the False Claims Act case pending in Colorado
transferred to the Bailey Houston Federal Court Action, and also suggested that
the claims of other plaintiffs in other carbon dioxide litigation pending in
Texas should be transferred to the Bailey Houston Federal Court Action. In
response to the court's suggestion, the case of Gary Shores et al. v. ExxonMobil
Corp. et al., No. 05-1825 (S.D. Tex., Houston Division) was consolidated with
the Bailey Houston Federal Court Action on July 18, 2005. That case, in which
the plaintiffs assert claims for McElmo Dome royalty underpayment, includes
Kinder Morgan CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., and Cortez
Pipeline Company as defendants. Bailey requested the Houston federal district
court to transfer the Bailey Houston Federal Court Action to the federal
district court of Colorado. Bailey also filed a petition for writ of mandamus in
the Fifth Circuit Court of Appeals, asking that the Houston federal district
court be required to transfer the case to the federal district court of
Colorado. On June 3, 2005, the Fifth Circuit Court of Appeals denied Bailey's
petition for writ of mandamus. On June 22, 2005, the Fifth Circuit denied
Bailey's petition for rehearing en banc. On September 14, 2005, Bailey filed a
petition for writ of certiorari in the United States Supreme Court, which the
U.S. Supreme Court denied on November 28, 2005. On November 21, 2005, the
federal district court in Colorado transferred Bailey's False Claims Act case
pending in Colorado to the Houston federal district court. On November 30, 2005,
Bailey filed a petition for mandamus seeking to vacate the transfer. The Tenth
Circuit Court of Appeals denied the petition on December 19, 2005. The U.S.
Supreme Court denied Bailey's petition for writ of certiorari. The Houston
federal district court subsequently realigned the parties in the Bailey Houston
Federal Court Action. Pursuant to the Houston federal district court's order,
Bailey and the other realigned plaintiffs have filed amended complaints in which
they assert claims for fraud/fraudulent inducement, real estate fraud, negligent
misrepresentation, breach of fiduciary and agency duties, breach of contract and
covenants, violation of the Colorado Unfair Practices Act, civil theft under
Colorado law, conspiracy, unjust enrichment, and open account. Bailey also
asserted claims as a private relator under the False Claims Act and for
violation of federal and Colorado antitrust laws. The realigned plaintiffs seek
actual damages, treble damages, punitive damages, a constructive trust and
accounting, and declaratory relief. The Shell and Kinder Morgan defendants,
along with Cortez Pipeline Company and ExxonMobil defendants, have filed motions
for summary judgment on all claims. No current trial date is set.
On March 1, 2004, Bridwell Oil Company, one of the named
defendants/realigned plaintiffs in the Bailey actions, filed a new matter in
which it asserts claims that are virtually identical to the claims it asserts
against Shell CO2 Company, Ltd. in the Bailey lawsuit. Bridwell Oil Co. v. Shell
Oil Co. et al, No. 160,199-B (78th Judicial District Court, Wichita County,
Texas filed March 1, 2004). The defendants in this action include Kinder Morgan
CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., various Shell entities,
ExxonMobil entities, and Cortez Pipeline Company. On June 25, 2004, defendants
filed answers, special exceptions, pleas in abatement, and motions to transfer
venue back to the Harris County District Court. On January 31, 2005, the Wichita
County judge abated the case pending resolution of the Bailey State Court
Action. The case remains abated.
On April 7, 2006, Harry Ptasynski, one of the plaintiffs in the Colorado
federal action filed by Bailey under the False Claims Act (which was transferred
to the Bailey Houston Federal Court Action as described above), filed suit
against Kinder Morgan G.P., Inc. in Colorado federal district court. Harry
Ptasynski v. Kinder Morgan G.P., Inc., No. 06-CV-00651 (LTB) (U.S. District
Court for the District of Colorado). Ptasynski, who holds an overriding royalty
interest at McElmo Dome, asserted claims for civil conspiracy, violation of the
Colorado Organized Crime Control Act, violation of Colorado antitrust laws,
violation of the Colorado Unfair Practices Act, breach of fiduciary duty and
confidential relationship, violation of the Colorado Payment of Proceeds Act,
fraudulent concealment,
24
breach of contract and implied duties to market and good faith and fair dealing,
and civil theft and conversion. Ptasynski sought actual damages, treble damages,
forfeiture, disgorgement, and declaratory and injunctive relief. The Colorado
court transferred the case to Houston federal district court, and Ptasynski
subsequently sought to non-suit the case. The Houston federal district court
granted Ptasynski's request to non-suit. Prior to non-suiting the case,
Ptasynski filed an appeal in the Tenth Circuit seeking to overturn the Colorado
court's order transferring the case to Houston federal district court. That
appeal is currently pending.
Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company were among the
named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al.,
No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case
involved claims by overriding royalty interest owners in the McElmo Dome and Doe
Canyon Units seeking damages for underpayment of royalties on carbon dioxide
produced from the McElmo Dome Unit, failure to develop carbon dioxide reserves
at the Doe Canyon Unit, and failure to develop hydrocarbons at both McElmo Dome
and Doe Canyon. The plaintiffs also possess a small working interest at Doe
Canyon. Plaintiffs claimed breaches of contractual and potential fiduciary
duties owed by the defendants and also alleged other theories of liability
including breach of covenants, civil theft, conversion, fraud/fraudulent
concealment, violation of the Colorado Organized Crime Control Act, deceptive
trade practices, and violation of the Colorado Antitrust Act. In addition to
actual or compensatory damages, plaintiffs sought treble damages, punitive
damages, and declaratory relief relating to the Cortez Pipeline tariff and the
method of calculating and paying royalties on McElmo Dome carbon dioxide. The
Court denied plaintiffs' motion for summary judgment concerning alleged
underpayment of McElmo Dome overriding royalties on March 2, 2005. In August
2006, plaintiffs and defendants reached a settlement of all claims. Pursuant to
the settlement, the case was dismissed with prejudice on September 27, 2006.
Cortez Pipeline Company and Kinder Morgan CO2 Company, L.P., successor in
interest to Shell CO2 Company, Ltd., were among the named defendants in CO2
Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November
28, 2005. The arbitration arose from a dispute over a class action settlement
agreement which became final on July 7, 2003 and disposed of five lawsuits
formerly pending in the U.S. District Court, District of Colorado. The
plaintiffs in such lawsuits primarily included overriding royalty interest
owners, royalty interest owners, and small share working interest owners who
alleged underpayment of royalties and other payments on carbon dioxide produced
from the McElmo Dome Unit in southwest Colorado. The settlement imposed certain
future obligations on the defendants in the underlying litigation. The plaintiff
in the arbitration is an entity that was formed as part of the settlement for
the purpose of monitoring compliance with the obligations imposed by the
settlement agreement. The plaintiff alleged that, in calculating royalty and
other payments, defendants used a transportation expense in excess of what is
allowed by the settlement agreement, thereby causing alleged underpayments of
approximately $12 million. The plaintiff also alleged that Cortez Pipeline
Company should have used certain funds to further reduce its debt, which, in
turn, would have allegedly increased the value of royalty and other payments by
approximately $0.5 million. Defendants denied that there was any breach of the
settlement agreement. The arbitration panel issued various preliminary
evidentiary rulings. The arbitration hearing took place in Albuquerque, New
Mexico on June 26-30, 2006. On August 7, 2006, the arbitration panel issued its
opinion finding that defendants did not breach the settlement agreement. The
arbitration opinion remains subject to further proceedings to confirm, vacate,
or modify the opinion.
J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD,
individually and on behalf of all other private royalty and overriding royalty
owners in the Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v.
Kinder Morgan CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court,
Union County New Mexico)
This case involves a purported class action against Kinder Morgan CO2
Company, L.P. alleging that it has failed to pay the full royalty and overriding
royalty ("royalty interests") on the true and proper settlement value of
compressed carbon dioxide produced from the Bravo Dome Unit in the period
beginning January 1, 2000. The complaint purports to assert claims for violation
of the New Mexico Unfair Practices Act, constructive fraud, breach of contract
and of the covenant of good faith and fair dealing, breach of the implied
covenant to market, and claims for an accounting, unjust enrichment, and
injunctive relief. The purported class is comprised of current and former
owners, during the period January 2000 to the present, who have private property
royalty interests burdening the oil and gas leases held by the defendant,
excluding the Commissioner of Public Lands, the United States of America, and
those private royalty interests that are not unitized as part of the Bravo Dome
Unit. The plaintiffs allege that they were members of a class previously
certified as a class action by the United States District Court for the District
25
of New Mexico in the matter Doris Feerer, et al. v. Amoco Production Company, et
al., USDC N.M. Civ. No. 95-0012 (the "Feerer Class Action"). Plaintiffs allege
that Kinder Morgan CO2 Company's method of paying royalty interests is contrary
to the settlement of the Feerer Class Action. Kinder Morgan CO2 Company filed a
motion to compel arbitration of this matter pursuant to the arbitration
provisions contained in the Feerer Class Action settlement agreement, which
motion was denied by the trial court. Kinder Morgan appealed that ruling to the
New Mexico Court of Appeals. Oral arguments took place before the New Mexico
Court of Appeals on March 23, 2006, and the New Mexico Court of Appeals affirmed
the district court's order on August 8, 2006. Kinder Morgan filed a petition for
writ of certiorari in the New Mexico Supreme Court. The New Mexico Supreme Court
granted the petition on October 11, 2006.
In addition to the matters listed above, various audits and administrative
inquiries concerning Kinder Morgan CO2 Company L.P.'s royalty and tax payments
on carbon dioxide produced from the McElmo Dome Unit are currently ongoing.
These audits and inquiries involve various federal agencies, the State of
Colorado, the Colorado oil and gas commission, and Colorado county taxing
authorities.
Commercial Litigation Matters
Union Pacific Railroad Company Easements
SFPP, L.P. and Union Pacific Railroad Company (the successor to Southern
Pacific Transportation Company and referred to in this report as UPRR) are
engaged in two proceedings to determine the extent, if any, to which the rent
payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR
should be adjusted pursuant to existing contractual arrangements for each of the
ten year periods beginning January 1, 1994 and January 1, 2004 (Southern Pacific
Transportation Company vs. Santa Fe Pacific Corporation, SFP Properties, Inc.,
Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al., Superior Court of the
State of California for the County of San Francisco, filed August 31, 1994; and
Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P.,
Kinder Morgan Operating L.P. "D", Kinder Morgan G.P., Inc., et al., Superior
Court of the State of California for the County of Los Angeles, filed July 28,
2004).
With regard to the first proceeding, covering the ten year period beginning
January 1, 1994, the trial court, on July 16, 2003, set the rent for years 1994
- - 2003 at approximately $5.0 million per year as of January 1, 1994, subject to
annual inflation increases throughout the ten year period. On February 23, 2005,
the California Court of Appeals affirmed the trial court's ruling, except that
it reversed a small portion of the decision and remanded it back to the trial
court for determination. On remand, the trial court held that there was no
adjustment to the rent relating to the portion of the decision that was
reversed, but awarded Southern Pacific Transportation Company interest on rental
amounts owing as of May 7, 1997.
In April 2006, we paid UPRR $15.3 million in satisfaction of our rental
obligations through December 31, 2003. However, we do not believe that the
assessment of interest awarded Southern Pacific Transportation Company on rental
amounts owing as of May 7, 1997 was proper, and we sought appellate review of
the interest award. In July 2006, the Court of Appeals disallowed the award of
interest.
In addition, SFPP, L.P. and UPRR are engaged in a second 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 UPRR should be adjusted pursuant to
existing contractual arrangements for the ten year period beginning January 1,
2004 (Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP,
L.P., Kinder Morgan Operating L.P. "D", Kinder Morgan G.P., Inc., et al.,
Superior Court of the State of California for the County of Los Angeles, filed
July 28, 2004). SFPP was served with this lawsuit on August 17, 2004. SFPP
expects that the trial in this matter will occur in late 2006.
SFPP and UPRR are also engaged in multiple disputes over the circumstances
under which SFPP must pay for a relocation of its pipeline within the UPRR right
of way and the safety standards that govern relocations. SFPP believes that it
must pay for relocation of the pipeline only when so required by the railroad's
common carrier operations, and in doing so, it need only comply with standards
set forth in the federal Pipeline Safety Act in conducting relocations. In July
2006, a trial before a judge regarding the circumstances under which we must pay
for relocations concluded, and a decision from the judge is expected in the
fourth quarter of 2006. In addition,
26
UPRR contends that it has complete discretion to cause the pipeline to be
relocated at SFPP's expense at any time and for any reason, and that SFPP must
comply with the more expensive American Railway Engineering and
Maintenance-of-Way standards. Each party is seeking declaratory relief with
respect to its positions regarding relocations.
It is difficult to quantify the effects of the outcome of these cases on
SFPP because SFPP does not know UPRR's plans for projects or other activities
that would cause pipeline relocations. Even if SFPP is successful in advancing
its positions, significant relocations for which SFPP must nonetheless bear the
expense (i.e. for railroad purposes, with the standards in the federal Pipeline
Safety Act applying) would have an adverse effect on our financial position and
results of operations. These effects would be even greater in the event SFPP is
unsuccessful in one or more of these litigations.
RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et
al. (Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District).
On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with
the First Supplemental Petition filed by RSM Production Corporation on behalf of
the County of Zapata, State of Texas and Zapata County Independent School
District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition
to 15 other defendants, including two other Kinder Morgan affiliates. Certain
entities we acquired in the Kinder Morgan Tejas acquisition are also defendants
in this matter. The Petition alleges that these taxing units relied on the
reported volume and analyzed heating content of natural gas produced from the
wells located within the appropriate taxing jurisdiction in order to properly
assess the value of mineral interests in place. The suit further alleges that
the defendants undermeasured the volume and heating content of that natural gas
produced from privately owned wells in Zapata County, Texas. The Petition
further alleges that the County and School District were deprived of ad valorem
tax revenues as a result of the alleged undermeasurement of the natural gas by
the defendants. On December 15, 2001, the defendants filed motions to transfer
venue on jurisdictional grounds. On June 12, 2003, plaintiff served discovery
requests on certain defendants. On July 11, 2003, defendants moved to stay any
responses to such discovery.
United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil
Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado).
This action was filed on June 9, 1997 pursuant to the federal False Claims
Act and involves allegations of mismeasurement of natural gas produced from
federal and Indian lands. The Department of Justice has decided not to intervene
in support of the action. The complaint is part of a larger series of similar
complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately
330 other defendants). Certain entities we acquired in the Kinder Morgan Tejas
acquisition are also defendants in this matter. An earlier single action making
substantially similar allegations against the pipeline industry was dismissed by
Judge Hogan of the U.S. District Court for the District of Columbia on grounds
of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed
individual complaints in various courts throughout the country. In 1999, these
cases were consolidated by the Judicial Panel for Multidistrict Litigation, and
transferred to the District of Wyoming. The multidistrict litigation matter is
called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions
to dismiss were filed and an oral argument on the motion to dismiss occurred on
March 17, 2000. On July 20, 2000, the United States of America filed a motion to
dismiss those claims by Grynberg that deal with the manner in which defendants
valued gas produced from federal leases, referred to as valuation claims. Judge
Downes denied the defendant's motion to dismiss on May 18, 2001. The United
States' motion to dismiss most of plaintiff's valuation claims has been granted
by the court. Grynberg has appealed that dismissal to the 10th Circuit, which
has requested briefing regarding its jurisdiction over that appeal.
Subsequently, Grynberg's appeal was dismissed for lack of appellate
jurisdiction. Discovery to determine issues related to the Court's subject
matter jurisdiction arising out of the False Claims Act is complete. Briefing
has been completed and oral arguments on jurisdiction were held before the
Special Master on March 17 and 18, 2005. On May 7, 2003, Grynberg sought leave
to file a Third Amended Complaint, which adds allegations of undermeasurement
related to carbon dioxide production. Defendants have filed briefs opposing
leave to amend. Neither the Court nor the Special Master has ruled on Grynberg's
Motion to Amend.
27
On May 13, 2005, the Special Master issued his Report and Recommendations
to Judge Downes in the In Re Natural Gas Royalties Qui Tam Litigation, Docket
No. 1293. The Special Master found that there was a prior public disclosure of
the mismeasurement fraud Grynberg alleged, and that Grynberg was not an original
source of the allegations. As a result, the Special Master recommended dismissal
of the Kinder Morgan defendants on jurisdictional grounds. On June 27, 2005,
Grynberg filed a motion to modify and partially reverse the Special Master's
recommendations and the Defendants filed a motion to adopt the Special Master's
recommendations with modifications. An oral argument was held on December 9,
2005 on the motions concerning the Special Master's recommendations.
On October 20, 2006, the United States District Court, for the District of
Wyoming, issued its Order on Report and Recommendations of Special Master. In
its Order, the Court upheld the dismissal of the claims against the Kinder
Morgan defendants on jurisdictional grounds, finding that the Grynberg's claims
are based upon public disclosures and that Grynberg does not qualify as an
original source. It is probable that Grynberg will appeal this Order to the 10th
Circuit Court of Appeals.
Weldon Johnson and Guy Sparks, individually and as Representative of Others
Similarly Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2 (Circuit
Court, Miller County Arkansas).
On October 8, 2004, plaintiffs filed the above-captioned matter against
numerous defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan
Energy Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder
Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.;
Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC;
and MidCon Corp. (the "Kinder Morgan Defendants"). The complaint purports to
bring a class action on behalf of those who purchased natural gas from the
CenterPoint defendants from October 1, 1994 to the date of class certification.
The complaint alleges that CenterPoint Energy, Inc., by and through its
affiliates, has artificially inflated the price charged to residential consumers
for natural gas that it allegedly purchased from the non-CenterPoint defendants,
including the above-listed Kinder Morgan entities. The complaint further alleges
that in exchange for CenterPoint's purchase of such natural gas at above market
prices, the non-CenterPoint defendants, including the above-listed Kinder Morgan
entities, sell natural gas to CenterPoint's non-regulated affiliates at prices
substantially below market, which in turn sells such natural gas to commercial
and industrial consumers and gas marketers at market price. The complaint
purports to assert claims for fraud, unlawful enrichment and civil conspiracy
against all of the defendants, and seeks relief in the form of actual, exemplary
and punitive damages, interest, and attorneys' fees. The parties have recently
concluded jurisdictional discovery and various defendants have filed motions
arguing that the Arkansas courts lack personal jurisdiction over them. The Court
has not yet ruled on these motions. 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.
Federal Investigation at Cora and Grand Rivers Coal Facilities
On June 22, 2005, we announced that the Federal Bureau of Investigation is
conducting an investigation related to our coal terminal facilities located in
Rockwood, Illinois and Grand Rivers, Kentucky. The investigation involves
certain coal sales from our Cora, Illinois and Grand Rivers, Kentucky coal
terminals that occurred from 1997 through 2001. During this time period, we sold
excess coal from these two terminals for our own account, generating less than
$15 million in total net sales. Excess coal is the weight gain that results from
moisture absorption into existing coal during transit or storage and from scale
inaccuracies, which are typical in the industry. During the years 1997 through
1999, we collected, and, from 1997 through 2001, we subsequently sold, excess
coal for our own account, as we believed we were entitled to do under
then-existing customer contracts.
We have conducted an internal investigation of the allegations and
discovered no evidence of wrongdoing or improper activities at these two
terminals. Furthermore, we have contacted customers of these terminals during
the applicable time period and have offered to share information with them
regarding our excess coal sales. Over the five year period from 1997 to 2001, we
moved almost 75 million tons of coal through these terminals, of which less than
1.4 million tons were sold for our own account (including both excess coal and
coal purchased on the open market). We have not added to our inventory of excess
coal since 1999 and we have not sold coal for our own account since 2001, except
for minor amounts of scrap coal. In September 2005 and subsequent thereto, we
28
responded to a subpoena in this matter by producing a large volume of documents,
which, we understand, are being reviewed by the FBI and auditors from the
Tennessee Valley Authority, which is a customer of the Cora and Grand Rivers
terminals. We believe that the federal authorities are also investigating coal
inventory practices at one or more of our other terminals. While we have no
indication of the direction of this additional investigation, our records do not
reflect any sales of excess coal from our other terminals, and we are not aware
of any wrongdoing or improper activities at our terminals. We are cooperating
fully with federal law enforcement authorities in this investigation, and expect
several of our officers and employees to be interviewed formally by federal
authorities. We do not expect that the resolution of the investigation will have
a material adverse impact on our business, financial position, results of
operations or cash flows.
Queen City Railcar Litigation
Claims asserted by residents and businesses. On August 28, 2005, a railcar
containing the chemical styrene began leaking styrene gas in Cincinnati, Ohio
while en route to our Queen City Terminal. The railcar was sent by the Westlake
Chemical Corporation from Louisiana, transported by Indiana & Ohio Railway, and
consigned to Westlake at its dedicated storage tank at Queen City Terminals,
Inc., a subsidiary of Kinder Morgan Bulk Terminals, Inc. The railcar leak
resulted in the evacuation of many residents and the alleged temporary closure
of several businesses in the Cincinnati area. Within three weeks of the
incident, seven separate class action complaints were filed in the Hamilton
County Court of Common Pleas, including case numbers: A0507115, A0507120,
A0507121, A0507149, A0507322, A0507332, and A0507913. In addition, a complaint
was filed by the city of Cincinnati, described further below.
On September 28, 2005, the court consolidated the complaints under
consolidated case number A0507913. Concurrently, thirteen designated class
representatives filed a Master Class Action Complaint against Westlake Chemical
Corporation, Indiana and Ohio Railway Corporation, Queen City Terminals, Inc.,
Kinder Morgan Liquids Terminals, LLC, Kinder Morgan GP, Inc. and Kinder Morgan
Energy Partners, L.P. (collectively, referred to in this report as the
defendants), in the Hamilton County Court of Common Pleas, case number A0507105.
The complaint alleges negligence, absolute nuisance, nuisance, trespass,
negligence per se, and strict liability against all defendants stemming from the
styrene leak. The complaint seeks compensatory damages in excess of $25,000,
punitive damages, pre and post-judgment interest, and attorney fees. The claims
against the Indiana and Ohio Railway and Westlake are based generally on an
alleged failure to deliver the railcar in a timely manner which allegedly caused
the styrene to become unstable and leak from the railcar. The plaintiffs allege
that we had a legal duty to monitor the movement of the railcar en route to our
terminal and guarantee its timely arrival in a safe and stable condition.
On October 28, 2005, we filed an answer denying the material allegations of
the complaint. On December 1, 2005, the plaintiffs filed a motion for class
certification. On December 12, 2005, we filed a motion for an extension of time
to respond to plaintiffs' motion for class certification in order to conduct
discovery regarding class certification. On February 10, 2006, the court granted
our motion for additional time to conduct class discovery.
In June, 2006, the parties reached an agreement to partially settle the
class action suit. On June 29, 2006, the plaintiffs filed an unopposed motion
for conditional certification of a settlement class. The settlement provides for
a fund of $2.0 million to distribute to residents within the evacuation zone
("Zone 1") and residents immediately adjacent to the evacuation zone ("Zone 2").
Persons in Zones 1 and 2 reside within approximately one mile from the site of
the incident. The court preliminarily approved the partial class action
settlement on July 7, 2006. Kinder Morgan Energy Partners agreed to participate
in and fund a minor percentage of the settlement. A fairness hearing occurred on
August 18, 2006 for the purpose of establishing final approval of the partial
settlement. The Court approved the settlement, entered a final judgment, and
certified a settlement class for Zones 1 and 2. The bar date for claims has
passed and Plaintiffs' counsel reports that they will be paying claims in the
immediate future. Certain claims by other residents and businesses remain
pending. Specifically, the settlement and final judgment does not apply to
purported class action claims by residents in outlying geographic zones more
than one mile from the site of the incident. Defendants deny liability to such
other residents in outlying geographic zones and intend to vigorously defend
such claims. In addition, the non-Kinder Morgan defendants have agreed to settle
remaining claims asserted by businesses and will obtain a release of such claims
favoring all defendants, including Kinder Morgan and its affiliates, subject to
the retention by all defendants of their claims against each other for
contribution and indemnity. Kinder Morgan expects that a claim will be asserted
by other defendants against Kinder Morgan seeking contribution or indemnity for
any settlements funded exclusively by other defendants, and Kinder Morgan
expects to vigorously defend against any such claims.
29
Claims asserted by the city of Cincinnati. On September 6, 2005, the city
of Cincinnati, the plaintiff, filed a complaint on behalf of itself and in
parens patriae against Westlake, Indiana and Ohio Railway, Kinder Morgan Liquids
Terminals, LLC, Queen City Terminals, Inc. and Kinder Morgan GP, Inc. in the
Court of Common Pleas, Hamilton County, Ohio, case number A0507323. Plaintiff's
complaint arose out of the same railcar incident reported immediately above. The
plaintiff's complaint alleges public nuisance, negligence, strict liability, and
trespass. The complaint seeks compensatory damages in excess of $25,000,
punitive damages, pre and post-judgment interest, and attorney fees. On
September 28, 2005, Kinder Morgan filed a motion to dismiss the parens patriae
claim. On December 15, 2005, the Kinder Morgan defendants filed a motion for
summary judgment seeking dismissal of the remaining aspects of the city's
complaint. The issues have been thoroughly briefed, and oral argument will be
heard on December 8, 2006. The parties agreed to stay discovery until after the
hearing, if necessary. No trial date has been established.
Leukemia Cluster Litigation
We are a party to several lawsuits in Nevada that allege that the
plaintiffs have developed leukemia as a result of exposure to harmful
substances. Based on the information available to date, our own preliminary
investigation, and the positive results of investigations conducted by State and
Federal agencies, we believe that the claims against us in these matters are
without merit and intend to defend against them vigorously. The following is a
summary of these cases.
Marie Snyder, et al v. City of Fallon, United States Department of the
Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas
Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District
Court, District of Nevada)("Snyder"); Frankie Sue Galaz, et al v. United States
of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy
Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No.
cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)("Galaz
I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial District Court,
State of Nevada, County of Washoe) ("Galaz II"); Frankie Sue Galaz, et al v. The
United States of America, the City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC (United States District
Court, District of Nevada)("Galaz III")
On July 9, 2002, we were served with a purported complaint for class action
in the Snyder case, in which the plaintiffs, on behalf of themselves and others
similarly situated, assert that a leukemia cluster has developed in the City of
Fallon, Nevada. The complaint alleges that the plaintiffs have been exposed to
unspecified "environmental carcinogens" at unspecified times in an unspecified
manner and are therefore "suffering a significantly increased fear of serious
disease." The plaintiffs seek a certification of a class of all persons in
Nevada who have lived for at least three months of their first ten years of life
in the City of Fallon between the years 1992 and the present who have not been
diagnosed with leukemia.
The complaint purports to assert causes of action for nuisance and "knowing
concealment, suppression, or omission of material facts" against all defendants,
and seeks relief in the form of "a court-supervised trust fund, paid for by
defendants, jointly and severally, to finance a medical monitoring program to
deliver services to members of the purported class that include, but are not
limited to, testing, preventative screening and surveillance for conditions
resulting from, or which can potentially result from exposure to environmental
carcinogens," incidental damages, and attorneys' fees and costs.
The defendants responded to the complaint by filing motions to dismiss on
the grounds that it fails to state a claim upon which relief can be granted. On
November 7, 2002, the United States District Court granted the motion to dismiss
filed by the United States, and further dismissed all claims against the
remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs
filed a motion for reconsideration and leave to amend, which was denied by the
court on December 30, 2002. Plaintiffs filed a notice of appeal to the United
States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit
affirmed the dismissal of this case.
30
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 filed a notice of appeal to the United States Court
of Appeals for the 9th Circuit. On November 17, 2003, the 9th Circuit dismissed
the appeal, upholding the District Court's dismissal of the case.
On June 20, 2003, plaintiffs filed an additional complaint for class action
(the "Galaz II" matter) asserting the same claims in Nevada State trial court on
behalf of the same purported class against virtually the same defendants,
including us (and excluding the United States Department of the Navy). On
September 30, 2003, the Kinder Morgan defendants filed a motion to dismiss the
Galaz II Complaint along with a motion for sanctions. On April 13, 2004,
plaintiffs' counsel voluntarily stipulated to a dismissal with prejudice of the
entire case in State Court. The court has accepted the stipulation and the case
was dismissed on April 27, 2004.
Also on June 20, 2003, the plaintiffs in the previously filed Galaz matters
(now dismissed) filed yet another complaint for class action in the United
States District Court for the District of Nevada (the "Galaz III" matter)
asserting the same claims in United States District Court for the District of
Nevada on behalf of the same purported class against virtually the same
defendants, including us. The Kinder Morgan defendants filed a motion to dismiss
the Galaz III matter on August 15, 2003. On October 3, 2003, the plaintiffs
filed a motion for withdrawal of class action, which voluntarily drops the class
action allegations from the matter and seeks to have the case proceed on behalf
of the Galaz family only. On December 5, 2003, the District Court granted the
Kinder Morgan defendants' motion to dismiss, but granted plaintiff leave to file
a second amended complaint. Plaintiff filed a second amended complaint on
December 13, 2003, and a third amended complaint on January 5, 2004. The Kinder
Morgan defendants filed a motion to dismiss the third amended complaint on
January 13, 2004. The motion to dismiss was granted with prejudice on April 30,
2004. On May 7, 2004, plaintiff filed a notice of appeal in the United States
Court of Appeals for the 9th Circuit. On March 31, 2006, the 9th Circuit
affirmed the District Court's dismissal of the case. On April 27, 2006,
plaintiff filed a motion for an en banc review of this decision by the full 9th
Circuit Court of Appeals. This motion was denied by the 9th Circuit Court of
Appeals on May 25, 2006.
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. 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 (ultra hazardous acts), and aiding and abetting, and
seek unspecified special, general and punitive damages. The Jernee case has been
consolidated for pretrial purposes with the Sands case (see below). Plaintiffs
have filed a third amended complaint and all defendants filed motions to dismiss
all causes of action excluding plaintiffs' cause of action for negligence.
Defendants also filed motions to strike portions of the complaint. By order
dated May 5, 2006, the Court granted defendants' motions to dismiss as to the
counts purporting to assert claims for fraud, but denied defendants' motions to
dismiss as to the remaining counts, as well as defendants' motions to strike.
Defendant Kennametal, Inc. has filed a third-party complaint naming the United
States and the United States Navy (the "United States") as additional
defendants. In response, the United States removed the case to the United States
District Court for the District of Nevada and filed a motion to dismiss the
third-party complaint, which motion is currently pending. Plaintiff has also
filed a motion to dismiss the United States and/or to remand the case back to
state court. Briefing on these motions is currently underway.
31
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. The Kinder Morgan defendants were served with
the complaint on January 10, 2004. 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 (ultra hazardous acts), and aiding
and abetting, and seek unspecified special, general and punitive damages. The
Sands case has been consolidated for pretrial purposes with the Jernee case (see
above). Plaintiffs have filed a third amended complaint and all defendants filed
motions to dismiss all causes of action excluding plaintiffs' cause of action
for negligence. Defendants also filed motions to strike portions of the
complaint. By order dated May 5, 2006, the Court granted defendants' motions to
dismiss as to the counts purporting to assert claims for fraud, but denied
defendants' motions to dismiss as to the remaining counts, as well as
defendants' motions to strike. Defendant Kennametal, Inc. has filed a
third-party complaint naming the United States and the United States Navy (the
"United States") as additional defendants. In response, the United States
removed the case to the United States District Court for the District of Nevada
and filed a motion to dismiss the third-party complaint, which motion is
currently pending. Plaintiff has also filed a motion to dismiss the United
States and/or to remand the case back to state court. Briefing on these motions
is currently underway.
Pipeline Integrity and Releases
Meritage Homes Corp., Monterey Homes Construction, Inc., and Monterey Homes
Arizona, Inc. v. Kinder Morgan Energy Partners, L.P. and SFPP Limited
Partnership, No. CIV 05 021 TUCCKJ, United States District Court, Arizona.
On January 28, 2005, Meritage Homes Corp. and its above-named affiliates
filed a complaint in the above-entitled action against Kinder Morgan Energy
Partners, L.P. and SFPP, L.P. The plaintiffs are homebuilders who constructed a
subdivision known as Silver Creek II located in Tucson, Arizona. Plaintiffs
allege that, as a result of a July 30, 2003 pipeline rupture and accompanying
release of petroleum products, soil and groundwater adjacent to, on and
underlying portions of Silver Creek II became contaminated. Plaintiffs allege
that they have incurred and continue to incur costs, damages and expenses
associated with the delay of closings of home sales within Silver Creek II and
damage to their reputation and goodwill as a result of the rupture and release.
Plaintiffs' complaint purports to assert claims for negligence, breach of
contract, trespass, nuisance, strict liability, subrogation and indemnity, and
negligence per se. Plaintiffs seek "no less than $1.5 million in compensatory
damages and necessary response costs," a declaratory judgment, interest,
punitive damages and attorneys' fees and costs. The parties have executed a
settlement agreement and release of all claims and counterclaims in the above
captioned matter. On August 14, 2006, the case was dismissed with prejudice.
Walnut Creek, California Pipeline Rupture
On November 9, 2004, Mountain Cascade, Inc., a third-party contractor on a
water main installation project hired by East Bay Municipal Utility District
("EBMUD"), struck and ruptured an underground petroleum pipeline owned and
operated by SFPP, L.P. in Walnut Creek, California. An explosion occurred
immediately following the rupture that resulted in five fatalities and several
injuries to employees or contractors of Mountain Cascade. The explosion and fire
also caused other property damage.
On May 5, 2005, the California Division of Occupational Safety and Health
("CalOSHA") issued two civil citations against us relating to this incident
assessing civil fines of $140,000 based upon our alleged failure to mark the
location of the pipeline properly prior to the excavation of the site by the
contractor. CalOSHA, with the assistance of the Contra Costa County District
Attorney's office, is continuing to investigate the facts and
32
circumstances surrounding the incident for possible criminal violations. In
addition, on June 27, 2005, the Office of the California State Fire Marshal,
Pipeline Safety Division ("CSFM") issued a Notice of Violation against us which
also alleges that we did not properly mark the location of the pipeline in
violation of state and federal regulations. The CSFM assessed a proposed civil
penalty of $500,000. The location of the incident was not our work site, nor did
we have any direct involvement in the water main replacement project. We believe
that SFPP acted in accordance with applicable law and regulations, and further
that according to California law, excavators, such as the contractor on the
project, must take the necessary steps (including excavating with hand tools) to
confirm the exact location of a pipeline before using any power operated or
power driven excavation equipment. Accordingly, we disagree with certain of the
findings of CalOSHA and the CSFM, and we have appealed the civil penalties
while, at the same time, continuing to work cooperatively with CalOSHA and the
CSFM to resolve these matters.
As a result of the accident, fifteen separate lawsuits have been filed.
Each of these lawsuits are currently coordinated in Contra Costa County Superior
Court. There are also several cross-complaints for indemnity between the
co-defendants in the coordinated lawsuits. The majority of the cases are
personal injury and wrongful death actions. These are: Knox, et al. v.. Mountain
Cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-00281); Farley v. Mountain
Cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-01573); Reyes, et al. v.
East Bay Municipal Utility District, et al. (Alameda Sup. Ct. Case No.
RG-05-207720); Arias, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case No.
RG-05-195567); Angeles, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case
No. RG-05-195680); Ramos, et al. v. East Bay Municipal Utility District, et al.
(Contra Costa County Superior Court Case No. C05-01840); Taylor, et al. v. East
Bay Municipal Utility District, et al. (Contra Costa County Superior Court Case
No. C05-02306); Becerra v. Kinder Morgan Energy Partners, L.P., et al., (Contra
Costa County Superior Court Case No. C05-02451); Im, et al. v. Kinder Morgan,
Inc. et al. (Contra Costa County Superior Court Case No. C05-02077); Paasch, et
al. v. East Bay Municipal Utility District, et al. (Contra Costa County Superior
Court Case No. C05-01844); and Fuentes et al. v. Kinder Morgan, et al. (Contra
Costa County Superior Court Case No. C05-02286). These complaints all allege,
among other things, that SFPP/Kinder Morgan failed to properly field mark the
area where the accident occurred. All of these plaintiffs seek compensatory and
punitive damages. These complaints also allege that the general contractor who
struck the pipeline, Mountain Cascade, Inc. ("MCI"), and EBMUD were at fault for
negligently failing to locate the pipeline. Some of these complaints also name
various engineers on the project for negligently failing to draw up adequate
plans indicating the bend in the pipeline. A number of these actions also name
Comforce Technical Services as a defendant. Comforce supplied SFPP with
temporary employees/independent contractors who performed line marking and
inspections of the pipeline on behalf of SFPP. Some of these complaints also
named various governmental entities--such as the City of Walnut Creek, Contra
Costa County, and the Contra Costa Flood Control and Water Conservation
District--as defendants.
Two of the suits are related to alleged damage to a residence near the
accident site. These are: USAA v. East Bay Municipal Utility District, et al.,
(Contra Costa County Superior Court Case No. C05-02128); and Chabot v. East Bay
Municipal Utilities District, et al., (Contra Costa Superior Court Case No.
C05-02312). The remaining two suits are by MCI and the welding subcontractor,
Matamoros. These are: Matamoros v. Kinder Morgan Energy Partners, L.P., et al.,
(Contra Costa County Superior Court Case No. C05-02349); and Mountain Cascade,
Inc. v. Kinder Morgan Energy Partners, L.P., et al, (Contra Costa County
Superior Court Case No. C-05-02576). Like the personal injury and wrongful death
suits, these lawsuits allege that SFPP/Kinder Morgan failed to properly mark its
pipeline, causing damage to these plaintiffs. The Chabot and USAA plaintiffs
allege property damage, while MCI and Matamoros Welding allege damage to their
business as a result of SFPP/Kinder Morgan's alleged failures, as well as
indemnity and other common law and statutory tort theories of recovery.
Based upon our investigation of the cause of the rupture of SFPP, LP's
petroleum pipeline by Mountain Cascade, Inc. and the resulting explosion and
fire, we have denied liability for the resulting deaths, injuries and damages,
are vigorously defending against such claims, and seeking contribution and
indemnity from the responsible parties. The parties are currently engaged in
discovery and court ordered mediation.
Cordelia, California
On April 28, 2004, SFPP, L.P. discovered a spill of diesel fuel into a
marsh near Cordelia, California from a section of SFPP's 14-inch Concord to
Sacramento, California pipeline. Estimates indicated that the size of the spill
was approximately 2,450 barrels. Upon discovery of the spill and notification to
regulatory agencies, a unified response was implemented with the United States
Coast Guard, the California Department of Fish and Game, the
33
Office of Spill Prevention and Response and SFPP. The damaged section of the
pipeline was removed and replaced, and the pipeline resumed operations on May 2,
2004. SFPP has completed recovery of diesel from the marsh and has completed an
enhanced biodegradation program for removal of the remaining constituents bound
up in soils. The property has been turned back to the owners for its stated
purpose. There will be ongoing monitoring under the oversight of the California
Regional Water Quality Control Board until the site conditions demonstrate there
are no further actions required.
SFPP is currently in negotiations with the United States Environmental
Protection Agency, the United States Fish & Wildlife Service, the California
Department of Fish & Game and the San Francisco Regional Water Quality Control
Board regarding potential civil penalties and natural resource damages
assessments. Since the April 2004 release in the Suisun Marsh area near
Cordelia, California, SFPP has cooperated fully with federal and state agencies
and has worked diligently to remediate the affected areas. As of December 31,
2005, the remediation was substantially complete.
Oakland, California
In February 2005, we were contacted by the U.S. Coast Guard regarding a
potential release of jet fuel in the Oakland, California area. Our northern
California team responded and discovered that one of our product pipelines had
been damaged by a third party, which resulted in a release of jet fuel which
migrated to the storm drain system and the Oakland estuary. We have coordinated
the remediation of the impacts from this release, and are investigating the
identity of the third party who damaged the pipeline in order to obtain
contribution, indemnity, and to recover any damages associated with the rupture.
The United States Environmental Protection Agency, the San Francisco Bay
Regional Water Quality Control Board, the California Department of Fish and
Game, and possibly the County of Alameda are asserting civil penalty claims with
respect to this release. We are currently in settlement negotiations with these
agencies. We will vigorously contest any unsupported, duplicative or excessive
civil penalty claims, but hope to be able to resolve the demands by each
governmental entity through out-of-court settlements.
Donner Summit, California
In April 2005, our SFPP pipeline in Northern California, which transports
refined petroleum products to Reno, Nevada, experienced a failure in the line
from external damage, resulting in a release of product that affected a limited
area adjacent to the pipeline near the summit of Donner Pass. The release was
located on land administered by the Forest Service, an agency within the U.S.
Department of Agriculture. Initial remediation has been conducted in the
immediate vicinity of the pipeline. All agency requirements have been met and
the site will be closed upon completion of the remediation. We have received
civil penalty claims on behalf of the United States Environmental Protection
Agency, the California Department of Fish and Game, and the Lahontan Regional
Water Quality Control Board. We are currently in settlement negotiations with
these agencies. We will vigorously contest any unsupported, duplicative or
excessive civil penalty claims, but hope to be able to resolve the demands by
each governmental entity through out-of-court settlements.
Baker, California
In November 2004, near Baker, California, our CALNEV Pipeline experienced a
failure in its pipeline from external damage, resulting in a release of gasoline
that affected approximately two acres of land in the high desert administered by
The Bureau of Land Management, an agency within the U.S. Department of the
Interior. Remediation has been conducted and continues for product in the soils.
All agency requirements have been met and the site will be closed upon
completion of the soil remediation. The State of California Department of Fish &
Game has alleged a small natural resource damage claim that is currently under
review. CALNEV expects to work cooperatively with the Department of Fish & Game
to resolve this claim.
Henrico County, Virginia
On April 17, 2006, Plantation Pipeline, which transports refined petroleum
products across the southeastern United States and which is 51.17% owned and
operated by us, experienced a pipeline release of turbine fuel from its 12-inch
pipeline. The release occurred in a residential area and impacted adjacent
homes, yards and common areas, as well as a nearby stream. The released product
did not ignite and there were no deaths or injuries. Plantation
34
estimates the amount of product released to be approximately 553 barrels.
Immediately following the release, the pipeline was shut down and emergency
remediation activities were initiated. Remediation and monitoring activities are
ongoing under the supervision of the United States Environmental Protection
Agency (referred to in this report as the EPA) and the Virginia Department of
Environmental Quality. Repairs to the pipeline were completed on April 19, 2006
with the approval of the United States Department of Transportation, Pipeline
and Hazardous Materials Safety Administration, referred to in this report as the
PHMSA, and pipeline service resumed on April 20, 2006. On April 20, 2006, the
PHMSA issued a Corrective Action Order which, among other things, requires that
Plantation maintain a 20% reduction in the operating pressure along the pipeline
between the Richmond and Newington, Virginia pump stations while the cause is
investigated and a remediation plan is proposed and approved by PHMSA. The cause
of the release is related to an original pipe manufacturing seam defect.
Dublin, California
In June 2006, near Dublin, California, our SFPP pipeline, which transports
refined petroleum products to San Jose, California, experienced a failure,
resulting in a release of product that affected a limited area along a
recreation path known as the Iron Horse Trail. Product impacts were primarily
limited to backfill of utilities crossing the pipeline. The release was located
on land administered by Alameda County, California. Remediation and monitoring
activities are ongoing under the supervision of The State of California
Department of Fish & Game. The cause of the release was outside force damage. We
are currently investigating potential recovery against third parties.
Soda Springs, California
In August 2006, our SFPP pipeline, which transports refined petroleum
products to Reno, Nevada, experienced a failure near Soda Springs, California,
resulting in a release of product that affected a limited area along Interstate
Highway 80. Product impacts were primarily limited to soil in an area between
the pipeline and Interstate Highway 80. The release was located on land
administered by Nevada County, California. Remediation and monitoring activities
are ongoing under the supervision of The State of California Department of Fish
& Game and Nevada County. The cause of the release is currently under
investigation.
Proposed Office of Pipeline Safety Civil Penalty and Compliance Order
On July 15, 2004, the U.S. Department of Transportation's Pipeline and
Hazardous Materials Safety Administration (PHMSA) issued a Proposed Civil
Penalty and Proposed Compliance Order concerning alleged violations of certain
federal regulations concerning our products pipeline integrity management
program. The violations alleged in the proposed order are based upon the results
of inspections of our integrity management program at our products pipelines
facilities in Orange, California and Doraville, Georgia conducted in April and
June of 2003, respectively. PHMSA sought to have us implement a number of
changes to our integrity management program and also to impose a proposed civil
penalty of approximately $0.3 million. An administrative hearing was held on
April 11 and 12, 2005, and a final order was issued on June 26, 2006. We have
already addressed most of the concerns identified by PHMSA and continue to work
with them to ensure that our integrity management program satisfies all
applicable regulations. However, we are seeking clarification for portions of
this order and have received an extension of time to allow for discussions.
Along with the extension, we reserved our right to seek reconsideration if
needed. We have established a reserve for the $0.3 million proposed civil
penalty, and this matter is not expected to have a material impact on our
business, financial position, results of operations or cash flows.
General
Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions. Furthermore, to the extent an assessment of
the matter is possible, if it is probable that a liability has been incurred and
the amount of loss can be reasonably estimated, we believe that we have
established an adequate reserve to cover potential liability. We also believe
that these matters will not have a material adverse effect on our business,
financial position, results of operations or cash flows.
35
Environmental Matters
Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids
Terminals, Inc. and ST Services, Inc.
On April 23, 2003, Exxon Mobil Corporation filed a 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 the 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 obligation we may owe to ST Services for environmental
remediation of MTBE at the terminal. The complaint seeks any and all damages
related to remediating MTBE at the terminal, and, according to the New Jersey
Spill Compensation and Control Act, treble damages may be available for actual
dollars incorrectly spent by the successful party in the lawsuit for remediating
MTBE at the terminal. The parties have completed limited discovery. In October
2004, the judge assigned to the case dismissed himself from the case based on a
conflict, and the new judge has ordered the parties to participate in mandatory
mediation. The parties participated in a mediation on November 2, 2005 but no
resolution was reached regarding the claims set out in the lawsuit. At this
time, the parties are considering another mediation session but no date is
confirmed.
The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.; Kinder
Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC;
Continental Oil Company; Chevron Corporation, California Superior Court, County
of Los Angeles, Case No. NC041463.
We are and some of our subsidiaries are defendants in a lawsuit filed in
2005 captioned The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.;
Kinder Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC;
Continental Oil Company; Chevron Corporation, California Superior Court, County
of Los Angeles, Case No. NC041463. The suit involves claims for environmental
cleanup costs and rent at the former Los Angeles Marine Terminal in the Port of
Los Angeles. Plaintiff alleges that terminal cleanup costs could approach $18
million; however, Kinder Morgan believes that the clean up costs should be
substantially less and that cleanup costs must be apportioned among all the
parties to the litigation. Plaintiff also alleges that it is owed approximately
$2.8 million in past rent and an unspecified amount for future rent; however, we
believe that previously paid rents paid will offset some of the Plaintiff's rent
claim and that we have certain defenses to the payment of rent allegedly owed.
The lawsuit is set for trial in October 2007. We will vigorously defend these
matters and believe that the outcome will not have a material adverse effect on
us
Other Environmental
Our Kinder Morgan Transmix Company has been in discussions with the United
States Environmental Protection Agency regarding allegations by the EPA that it
violated certain provisions of the Clean Air Act and the Resource Conservation &
Recovery Act. Specifically, the EPA claims that we failed to comply with certain
sampling protocols at our Indianola, Pennsylvania transmix facility in violation
of the Clean Air Act's provisions governing fuel. The EPA further claims that we
improperly accepted hazardous waste at our transmix facility in Indianola.
Finally, the EPA claims that we failed to obtain batch samples of gasoline
produced at our Hartford (Wood River), Illinois facility in 2004. In addition to
injunctive relief that would require us to maintain additional oversight of our
quality assurance program at all of our transmix facilities, the EPA is seeking
monetary penalties of $0.6 million.
36
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, among others, 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 law and 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 several governmental proceedings involving
groundwater and soil remediation efforts under administrative orders or related
state remediation programs issued by various regulatory authorities related to
compliance with environmental regulations associated with our assets. We have
established a reserve to address the costs associated with the cleanup.
We are also involved with and have been identified as a potentially
responsible party in several federal and state superfund sites. Environmental
reserves have been established for those sites where our contribution is
probable and reasonably estimable. In addition, we are from time to time
involved in civil proceedings relating to damages alleged to have occurred as a
result of accidental leaks or spills of refined petroleum products, natural gas
liquids, natural gas and carbon dioxide.
See "--Pipeline Integrity and Ruptures" above for information with respect
to the environmental impact of recent ruptures of some of our pipelines.
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. However, we are not able to reasonably estimate when the eventual
settlements of these claims will occur. Many factors may change in the future
affecting our reserve estimates, such as regulatory changes, groundwater and
land use near our sites, and changes in cleanup technology. As of September 30,
2006, we have accrued an environmental reserve of $65.2 million.
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. Asset Retirement Obligations
We account for our legal obligations associated with the retirement of
long-lived assets pursuant to Statement of Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides
accounting and reporting guidance for legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction
or normal operation of a long-lived asset.
SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. 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.
37
In our CO2 business segment, we are required to plug and abandon oil and
gas wells that have been removed from service and to remove our surface wellhead
equipment and compressors. As of September 30, 2006, we have recognized asset
retirement obligations in the aggregate amount of $46.6 million relating to
these requirements at existing sites within our CO2 business segment.
In our Natural Gas Pipelines business segment, if we were to cease
providing utility services, we would be required to remove surface facilities
from land belonging to our customers and others. Our Texas intrastate natural
gas pipeline group has various condensate drip tanks and separators located
throughout its natural gas pipeline systems, as well as inactive gas processing
plants, laterals and gathering systems which are no longer integral to the
overall mainline transmission systems, and asbestos-coated underground pipe
which is being abandoned and retired. Our Kinder Morgan Interstate Gas
Transmission system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of September 30, 2006, we have recognized
asset retirement obligations in the aggregate amount of $1.7 million relating to
the businesses within our Natural Gas Pipelines business segment.
We have included $1.4 million of our total asset retirement obligations as
of September 30, 2006 with "Accrued other current liabilities" in our
accompanying consolidated balance sheet. The remaining $46.9 million obligation
is reported separately as a non-current liability. No assets are legally
restricted for purposes of settling our asset retirement obligations. A
reconciliation of the beginning and ending aggregate carrying amount of our
asset retirement obligations for each of the nine months ended September 30,
2006 and 2005 is as follows (in thousands):
Nine Months Ended September 30,
-------------------------------
2006 2005
-------------- -------------
Balance at beginning of period......... $ 43,227 $ 38,274
Liabilities incurred................. 4,950 521
Liabilities settled.................. (1,762) (1,497)
Accretion expense.................... 1,853 807
Revisions in estimated cash flows.... -- (522)
------- --------
Balance at end of period............... $ 48,268 $ 37,583
======= =======
5. Distributions
On August 14, 2006, we paid a cash distribution of $0.81 per unit to our
common unitholders and our Class B unitholders for the quarterly period ended
June 30, 2006. KMR, our sole i-unitholder, received 1,131,777 additional i-units
based on the $0.81 cash distribution per common unit. The distributions were
declared on July 19, 2006, payable to unitholders of record as of July 31, 2006.
On October 18, 2006, we declared a cash distribution of $0.81 per unit for
the quarterly period ended September 30, 2006. The distribution will be paid on
November 14, 2006, to unitholders of record as of October 31, 2006. 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 $0.81 distribution
per common unit. The number of i-units distributed will be 1,160,520. For each
outstanding i-unit that KMR holds, a fraction of an i-unit (0.018981) will be
issued. The fraction was determined by dividing:
o $0.81, the cash amount distributed per common unit
by
o $42.675, the average of KMR's shares' closing market prices from
October 13-26, 2006, 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.
38
6. Intangibles
Goodwill
For our investments in affiliated entities that are included in our
consolidation, the excess cost over underlying fair value of net assets is
referred to as goodwill and reported separately as "Goodwill" in our
accompanying consolidated balance sheets. Goodwill is not subject to
amortization but must be tested for impairment at least annually. Following is
information related to our goodwill (in thousands):
September 30, December 31,
2006 2005
------------- ------------
Goodwill
Gross carrying amount....... $ 832,942 $813,101
Accumulated amortization.... (14,142) (14,142)
-------- --------
Net carrying amount......... 818,800 798,959
======== =======
Changes in the carrying amount of our goodwill for the nine months ended
September 30, 2006 are summarized as follows (in thousands):
Products Natural Gas
Pipeline Pipelines CO2 Terminals Total
-------- --------- --- --------- -----
Balance as of December 31, 2005...... $263,182 $288,435 $46,101 $201,241 $798,959
Acquisitions....................... - - - 17,763 17,763
Purchase price adjustments......... - - - 2,078 2,078
Impairments........................ - - - - -
------- ------- ------ ------- -------
Balance as of September 30, 2006..... $263,182 $288,435 $46,101 $221,082 $818,800
======= ======= ====== ======= =======
In addition, pursuant to ABP No. 18, any premium paid by an investor, which
is analogous to goodwill, must be identified. For the investments we account for
under the equity method of accounting, this premium or excess cost over
underlying fair value of net assets is referred to as equity method goodwill.
Equity method goodwill is not subject to amortization but rather to impairment
testing in accordance with Accounting Principles Board Opinion No. 18, "The
Equity Method of Accounting for Investments in Common Stock." 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. Therefore, in addition to our annual impairment test of
goodwill, we periodically reevaluate the amount at which we carry the excess of
cost over fair value of net assets accounted for under the equity method. As of
both September 30, 2006 and December 31, 2005, we have reported $138.2 million
in equity method goodwill within the caption "Investments" in our accompanying
consolidated balance sheets.
We also periodically reevaluate the difference between the fair value of
net assets accounted for under the equity method and our proportionate share of
the underlying book value (that is, the investee's net assets per its financial
statements) of the investee at date of acquisition. In almost all instances,
this differential, relating to the discrepancy between our share of the
investee's recognized net assets at book values and at current fair values,
represents our share of undervalued depreciable assets, and since those assets
(other than land) are subject to depreciation, we amortize this portion of our
investment cost against our share of investee earnings. We reevaluate this
differential, as well as the amortization period for such undervalued
depreciable assets, to determine whether current events or circumstances warrant
adjustments to our carrying value and/or revised estimates of useful lives in
accordance with APB Opinion No. 18. The caption "Investments" in our
accompanying consolidated balance sheets includes excess fair value of net
assets over book value costs of $178.6 million as of September 30, 2006 and
$181.7 million as of December 31, 2005.
Other Intangibles
Excluding goodwill, our other intangible assets include lease value,
contracts, customer relationships and agreements. These intangible assets have
definite lives, are being amortized on a straight-line basis over their
estimated useful lives, and are reported separately as "Other intangibles, net"
in our accompanying consolidated balance sheets. Following is information
related to our intangible assets subject to amortization (in thousands):
39
September 30, December 31,
2006 2005
------------- ------------
Lease value
Gross carrying amount......... $ 6,592 $ 6,592
Accumulated amortization...... (1,274) (1,168)
-------- --------
Net carrying amount........... 5,318 5,424
-------- --------
Contracts and other
Gross carrying amount......... 224,550 221,250
Accumulated amortization...... (19,794) (9,654)
-------- --------
Net carrying amount........... 204,756 211,596
-------- --------
Total Other intangibles, net.... $ 210,074 $ 217,020
======== ========
Amortization expense on our intangiblesconsisted of the following (in
thousands):
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2006 2005 2006 2005
-------------- -------------- -------------- --------------
Lease value............ $ 35 $ 35 $ 106 $ 106
Contracts and other.... 3,372 3,487 10,140 4,318
------- ------- -------- -------
Total amortization..... $ 3,407 $ 3,522 $ 10,246 $ 4,424
======= ======= ======== =======
As of September 30, 2006, our weighted average amortization period for our
intangible assets was approximately 18.9 years. Our estimated amortization
expense for these assets for each of the next five fiscal years is approximately
$13.3 million, $13.2 million, $12.0 million, $11.9 million and $11.8 million,
respectively.
7. Debt
Our outstanding short-term debt as of September 30, 2006 was $1,147.2
million. The balance consisted of:
o $887.6 million of commercial paper borrowings;
o $250.0 million in principal amount of 5.35% senior notes due August
15, 2007;
o a $5.8 million portion of 5.23% senior notes (our subsidiary, Kinder
Morgan Texas Pipeline, L.P., is the obligor on the notes);
o a $5.0 million portion of 7.84% senior notes (our subsidiary, Central
Florida Pipe Line LLC, is the obligor on the notes); and
o an offset of $1.2 million (which represents the net of other
borrowings and the accretion of discounts on our senior note
issuances).
The weighted average interest rate on all of our borrowings was
approximately 6.44% during the third quarter of 2006 and 5.40% during the third
quarter of 2005.
Credit Facility
Effective August 28, 2006, we terminated our $250 million unsecured
nine-month bank credit facility due November 21, 2006, and we increased our
existing five-year bank credit facility from $1.60 billion to $1.85 billion. The
five-year unsecured bank credit facility remains due August 18, 2010; however,
the bank facility can now be amended to allow for borrowings up to $2.1 billion.
There were no borrowings under our five-year credit facility as of December 31,
2005 or as of September 30, 2006.
Our five-year credit facility is with a syndicate of financial
institutions, and Wachovia Bank, National Association is the administrative
agent. The amount available for borrowing under our credit facility as of
September 30, 2006 was reduced by:
40
o our outstanding commercial paper borrowings ($887.6 million as of
September 30, 2006);
o a combined $353 million in five letters of credit that support our
hedging of commodity price risks associated with the sale of natural
gas, natural gas liquids and crude oil;
o a combined $49 million in two letters of credit that support
tax-exempt bonds;
o a $19.9 million letter of credit that supports the construction of our
Kinder Morgan Louisiana Pipeline (a natural gas pipeline); and
o a combined $16.2 million in other letters of credit supporting other
obligations of us and our subsidiaries.
Interest Rate Swaps
Information on our interest rate swaps is contained in Note 10.
Commercial Paper Program
As of December 31, 2005, our commercial paper program provided for the
issuance of up to $1.6 billion of commercial paper. In April 2006, we increased
our commercial paper program by $250 million to provide for the issuance of up
to $1.85 billion. Borrowings under our commercial paper program reduce the
borrowings allowed under our credit facility. As of September 30, 2006, we had
$887.6 million of commercial paper outstanding with an average interest rate of
5.42%.
Contingent Debt
We apply the provisions of Financial Accounting Standards Board
Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements
for Guarantees, Including Indirect Guarantees of Indebtedness of Others" to our
agreements that contain guarantee or indemnification clauses. These disclosure
provisions expand those required by SFAS No. 5, "Accounting for Contingencies,"
by requiring a guarantor to disclose certain types of guarantees, even if the
likelihood of requiring the guarantor's performance is remote. The following is
a description of our contingent debt agreements.
Cortez Pipeline Company Debt
Pursuant to a certain Throughput and Deficiency Agreement, the partners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% partner; a
subsidiary of Exxon Mobil Corporation - 37% partner; and Cortez Vickers Pipeline
Company - 13% partner) are required, on a several, percentage ownership basis,
to contribute capital to Cortez Pipeline Company in the event of a cash
deficiency. The Throughput and Deficiency Agreement contractually supports the
borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez
Pipeline Company, by obligating the partners 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
partners further severally guarantee, on a percentage ownership basis, the
obligations of the Cortez Pipeline Company partners under the Throughput and
Deficiency Agreement.
Due to our indirect ownership of Cortez Pipeline Company through Kinder
Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez
Capital Corporation. Shell Oil Company shares our several guaranty obligations
jointly and severally; however, we are obligated to indemnify Shell for
liabilities it incurs in connection with such guaranty. With respect to Cortez's
long-term revolving credit facility, Shell will be released of its guaranty
obligations on December 31, 2006. Furthermore, with respect to Cortez's
short-term commercial paper program and Series D notes, we must use commercially
reasonable efforts to have Shell released of its guaranty obligations by
December 31, 2006. If we are unable to obtain Shell's release in respect of the
Series D Notes by that date, we are required to provide Shell with collateral (a
letter of credit, for example) to secure our indemnification obligations to
Shell.
41
As of September 30, 2006, the debt facilities of Cortez Capital Corporation
consisted of:
o $75 million of Series D notes due May 15, 2013;
o a $125 million short-term commercial paper program; and
o a $125 million five-year committed revolving credit facility due
December 22, 2009 (to support the above-mentioned $125 million
commercial paper program).
As of September 30, 2006, Cortez Capital Corporation had $76.2 million of
commercial paper outstanding with an average interest rate of 5.31%, the average
interest rate on the Series D notes was 7.14%, and there were no borrowings
under the credit facility.
Red Cedar Gathering Company Debt
In October 1998, Red Cedar 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
Gathering Company. The Senior Notes are also guaranteed by us and the other
owner of Red Cedar Gathering Company, jointly and severally. The principal is to
be repaid in seven equal installments beginning on October 31, 2004 and ending
on October 31, 2010. As of September 30, 2006, $39.3 million in principal amount
of Senior Notes were outstanding.
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. The bond
indenture is for 30 years and allows the bonds to remain outstanding until
December 1, 2020. 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. Principal
payments on the bonds are made on the first of December each year, and
corresponding reductions are made to the letter of credit. As of September 30,
2006, this letter of credit had an outstanding balance under our credit facility
of $24.9 million.
Rockies Express Pipeline LLC Debt
On April 28, 2006, Rockies Express Pipeline LLC entered into a $2.0 billion
five-year, unsecured revolving credit facility due April 28, 2011. This credit
facility supports a $2.0 billion commercial paper program that was established
in May 2006, and borrowings under the commercial paper program reduce the
borrowings allowed under the credit facility; this facility can be amended to
allow for borrowings up to $2.5 billion. Borrowings under the Rockies Express
credit facility and commercial paper program will be primarily used to finance
the construction of the Rockies Express interstate natural gas pipeline and to
pay related expenses, and the borrowings will not reduce the borrowings allowed
under our credit facility described above in "--Credit Facility."
In addition, pursuant to certain guaranty agreements, all three member
owners of West2East Pipeline LLC (and its subsidiary Rockies Express Pipeline,
LLC) have agreed to guarantee borrowings under the Rockies Express credit
facility and under the Rockies Express commercial paper program severally in the
same proportion as their percentage ownership of the member interests in Rockies
Express Pipeline LLC. The three member owners and their respective ownership
interests consist of the following: our subsidiary Kinder Morgan W2E Pipeline
LLC - 51%, Sempra Energy - 25%, and ConocoPhillips - 24%. As of September 30,
2006, Rockies Express Pipeline LLC had $583.5 million of commercial paper
outstanding, and there were no borrowings under its five-year credit
42
facility. Accordingly, as of September 30, 2006, our contingent share of Rockies
Express' debt was $297.6 million (51% of total commercial paper borrowings).
Certain Relationships and Related Transactions
In conjunction with our acquisition of Natural Gas Pipelines assets from
KMI on December 31, 1999 and 2000, KMI agreed to indemnify us and our general
partner with respect to approximately $522.7 million of our debt. In conjunction
with our acquisition of all of the partnership interests in TransColorado Gas
Transmission Company from two wholly-owned subsidiaries of KMI on November 1,
2004, KMI agreed to indemnify us and our general partner with respect to
approximately $210.8 million of our debt. Thus, as of September 30, 2006, KMI
has agreed to indemnify us and our general partner with respect to a total of
approximately $733.5 million of our debt. KMI would be obligated to perform
under this indemnity only if our assets were insufficient to satisfy our
obligations.
For additional information regarding our debt facilities, see Note 9 to our
consolidated financial statements included in our Form 10-K for the year ended
December 31, 2005.
8. Partners' Capital
As of September 30, 2006 and December 31, 2005, our partners' capital
consisted of the following limited partner units:
September 30, December 31,
2006 2005
------------- ------------
Common units....................... 162,779,676 157,005,326
Class B units...................... 5,313,400 5,313,400
i-units............................ 61,141,156 57,918,373
----------- -----------
Total limited partner units...... 229,234,232 220,237,099
=========== ===========
The total limited partner units represent our limited partners' interest
and an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights.
As of September 30, 2006, our common unit totals consisted of 148,423,941
units held by third parties, 12,631,735 units held by KMI and its consolidated
affiliates (excluding our general partner), and 1,724,000 units held by our
general partner. As of December 31, 2005, our common unit total consisted of
142,649,591 units held by third parties, 12,631,735 units held by KMI and its
consolidated affiliates (excluding our general partner) and 1,724,000 units held
by our general partner.
On August 15, 2006, we issued, in a public offering, 5,000,000 of our
common units at a price of $44.80 per unit, less commissions and underwriting
expenses. At the time of the offering, we granted the underwriters a 30-day
option to purchase up to an additional 750,000 common units from us on the same
terms and conditions, and we issued the additional 750,000 common units on
August 23, 2006 upon the underwriters' exercise of this option. After
commissions and underwriting expenses, we received net proceeds of approximately
$248.0 million for the issuance of these 5,750,000 common units, and we used the
proceeds to reduce the borrowings under our commercial paper program.
On both September 30, 2006 and December 31, 2005, all of our 5,313,400
Class B units were held entirely by a wholly-owned subsidiary of KMI. The Class
B units are similar to our common units except that they are not eligible for
trading on the New York Stock Exchange. All of our Class B units were issued to
a wholly-owned subsidiary of KMI in December 2000.
On both September 30, 2006 and December 31, 2005, all of our i-units were
held entirely by KMR. Our i-units are a separate class of limited partner
interests in us and are not publicly traded. In accordance with its limited
liability company agreement, KMR's activities are restricted to being a limited
partner in us, and to controlling and managing our business and affairs and the
business and affairs of our operating limited partnerships and their
subsidiaries. Through the combined effect of the provisions in our partnership
agreement and the provisions of
43
KMR's limited liability company agreement, the number of outstanding KMR shares
and the number of i-units will at all times be equal.
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
a value based on the cash payment on the common unit.
The cash equivalent of distributions of i-units will be treated as if it
had actually been distributed for purposes of determining the distributions to
our general partner. We will not distribute the cash to the holders of our
i-units but will retain the cash for use in our business. If additional units
are distributed to the holders of our common units, we will issue an equivalent
amount of i-units to KMR based on the number of i-units it owns. Based on the
preceding, KMR received a distribution of 1,131,777 i-units from us on August
14, 2006. These additional i-units distributed were based on the $0.81 per unit
distributed to our common unitholders on that date.
For the purposes of maintaining partner capital accounts, our partnership
agreement specifies that items of income and loss shall be allocated among the
partners, other than owners of i-units, in accordance with their percentage
interests. Normal allocations according to percentage interests are made,
however, only after giving effect to any priority income allocations in an
amount equal to the incentive distributions that are allocated 100% to our
general partner. Incentive distributions are generally defined as all cash
distributions paid to our general partner that are in excess of 2% of the
aggregate value of cash and i-units being distributed.
Incentive distributions allocated to our general partner are determined by
the amount quarterly distributions to unitholders exceed certain specified
target levels. Our distribution of $0.81 per unit paid on August 14, 2006 for
the second quarter of 2006 required an incentive distribution to our general
partner of $129.0 million. Our distribution of $0.78 per unit paid on August 12,
2005 for the second quarter of 2005 required an incentive distribution to our
general partner of $115.7 million. The increased incentive distribution to our
general partner paid for the second quarter of 2006 over the distribution paid
for the second quarter of 2005 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 2006 of $0.81 per unit
will result in an incentive distribution to our general partner of approximately
$133.0 million. This compares to our distribution of $0.79 per unit and
incentive distribution to our general partner of approximately $121.5 million
for the third quarter of 2005.
9. Comprehensive Income
SFAS No. 130, "Accounting for Comprehensive Income," requires that
enterprises report a total for comprehensive income. For each of the three and
nine month periods ended September 30, 2006, and September 30, 2005, the
difference between our net income and our comprehensive income resulted from
unrealized gains or losses on derivative contracts utilized for hedging purposes
and from foreign currency translation adjustments. For more information on our
hedging activities, see Note 10. Our total comprehensive income was as follows
(in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- --------------------
2006 2005 2006 2005
-------- -------- -------- --------
Net income................................... $223,818 $245,387 $717,588 $ 690,834
Foreign currency translation adjustments..... 72 8 456 (596)
Change in fair value of derivatives
used for hedging purposes.................... 203,572 (259,826) (281,295) (1,016,695)
Reclassification of change in fair
value of derivatives to net income........... 118,868 141,361 338,020 287,032
-------- -------- -------- ---------
Total other comprehensive
income/(loss)................................ 322,512 (118,457) 57,181 (730,259)
-------- -------- -------- ---------
Comprehensive income/(loss).................. $546,330 $126,930 $774,769 $ (39,425)
======== ======== ======== =========
44
10. Risk Management
Certain of our business activities expose us to risks associated with
unfavorable changes in the market price of natural gas, natural gas liquids and
crude oil. We also have exposure to interest rate risk as a result of the
issuance of our fixed rate debt obligations. Pursuant to our management's
approved risk management policy, we use derivative contracts to hedge or reduce
our exposure to these risks, and we account for these hedging transactions
according to the provisions of SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" and associated amendments, collectively,
SFAS No. 133.
Energy Commodity Price Risk Management
We are exposed to risks associated with unfavorable changes in the market
price of natural gas, natural gas liquids and crude oil as a result of the
forecasted purchase or sale of these products. Such changes are often caused by
shifts in the supply and demand for these commodities, as well as their
locations. Our energy commodity derivative contracts act as a hedging (offset)
mechanism against the volatility of energy commodity prices by allowing us to
transfer this price risk to counterparties who are able and willing to bear it.
Hedging effectiveness and ineffectiveness
These contracts are used to offset the risk associated with an anticipated
future cash flow of a transaction that is expected to occur but whose value is
uncertain, therefore the resulting hedges are designated and qualified as cash
flow hedges in accordance with SFAS No. 133. For cash flow hedges, the portion
of the change in the value of derivative contracts that is effective in
offsetting undesired changes in expected cash flows (the effective portion) is
reported as a component of other comprehensive income (outside current earnings,
net income), but only to the extent that they can later offset the undesired
changes in expected cash flows during the period in which the hedged cash flows
affect earnings. Other comprehensive income consists of those financial items
that are included in "accumulated other comprehensive income/loss" on the
balance sheet but not included within net income on the statement of income.
Thus, in highly effective cash flow hedges, where there is no ineffectiveness,
other comprehensive income changes by exactly as much as the change in the value
of the derivative contacts and there is no impact on earnings.
To the contrary, the portion of the change in the value of derivative
contracts that is not effective in offsetting undesired changes in expected cash
flows (the ineffective portion), as well as any component excluded from the
computation of the effectiveness of the derivative contracts, is required to be
recognized currently in earnings. Accordingly, as a result of ineffective
hedges, we recognized a gain of $0.5 million and a loss of $1.3 million,
respectively, during the three and nine month periods ended September 30, 2006,
and losses of $1.9 million and $2.3 million, respectively, during the three and
nine month periods ended September 30, 2005. All of the gains and losses we
recognized as a result of ineffective hedges are reported within the captions
"Natural gas sales," "Gas purchases and other costs of sales," and "Product
sales and other" in our accompanying consolidated statements of income. For each
of the three and nine months ended September 30, 2006 and 2005, we did not
exclude any component of the derivative contracts' gain or loss from the
assessment of hedge effectiveness.
When the hedged sales and purchases take place and we record them into
earnings, or when a determination is made that a forecasted transaction will no
longer occur by the end of the originally specified time period or within an
additional two-month period of time thereafter, the gains and losses from the
effective portion of the change in the value of the derivative contracts are
removed from "accumulated other comprehensive income/loss" on the balance sheet
and reclassified into earnings. During the three and nine month periods ended
September 30, 2006, we reclassified $118.9 million and $338.0 million,
respectively, of "Accumulated other comprehensive loss" into earnings, and
during the three and nine month periods ended September 30, 2005, we
reclassified $141.3 million and $287.0 million, respectively, of "Accumulated
other comprehensive loss" into earnings.
With the exception of the $2.9 million loss resulting from the
discontinuance of cash flow hedges related to the sale of our Douglas gathering
assets (described in Note 2), none of the reclassification of Accumulated other
comprehensive loss into earnings during the first nine months of 2006 or 2005
resulted from the discontinuance of
45
cash flow hedges due to a determination that the forecasted transactions would
no longer occur by the end of the originally specified time period or within an
additional two-month period of time thereafter, but rather resulted from the
hedged forecasted transactions actually affecting earnings (for example, when
the forecasted sales and purchases actually occurred). Approximately $437.4
million of our "Accumulated other comprehensive loss" balance of $1,022.5
million as of September 30, 2006 is expected to be reclassified into earnings
during the next twelve months.
Fair Value of Energy Commodity Derivative Contracts
Derivative contracts represent rights or obligations that meet the
definitions of assets or liabilities and should be reported in financial
statements. Furthermore, SFAS No. 133 requires derivative contracts to be
reflected as assets or liabilities at their fair market values and current
market values should be used to track changes in derivative holdings; that is,
mark-to-market valuation should be employed. The fair value of our energy
commodity derivative contracts reflect 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 energy commodity derivative
contracts that we use, including: commodity futures and options contracts, fixed
price swaps, and basis swaps.
The fair values of our energy commodity derivative contracts are included
in our accompanying consolidated balance sheets within "Other current assets,"
"Deferred charges and other assets," "Accrued other current liabilities," "Other
long-term liabilities and deferred credits," and, as of December 31, 2005 only,
"Accounts payable-Related parties." The following table summarizes the fair
values of our energy commodity derivative contracts associated with our
commodity price risk management activities and included on our accompanying
consolidated balance sheets as of September 30, 2006 and December 31, 2005 (in
thousands):
September 30, December 31,
2006 2005
------------- ------------
Derivatives-net asset/(liability)
Other current assets...................... $ 115,347 $ 109,437
Deferred charges and other assets......... 17,977 47,682
Accounts payable-Related parties.......... -- (16,057)
Accrued other current liabilities......... (553,330) (507,306)
Other long-term liabilities and
deferred credits.......................... $ (602,900) $ (727,929)
Our over-the-counter swaps and options are contracts we entered into with
counterparties outside centralized trading facilities such as a futures, options
or stock exchange. These contracts are with a number of parties, all of which
had investment grade credit ratings as of September 30, 2006. We both owe money
and are owed money under these derivative contracts. 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 contracts 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.
In addition, in conjunction with the purchase of exchange-traded derivative
contracts or when the market value of our derivative contracts with specific
counterparties exceeds established limits, we are required to provide collateral
to our counterparties, which may include posting letters of credit or placing
cash in margin accounts. As of September 30, 2006, we had five outstanding
letters of credit totaling $353 million in support of our hedging of commodity
price risks associated with the sale of natural gas, natural gas liquids and
crude oil. As of December 31, 2005, we had five outstanding letters of credit
totaling $534 million in support of our hedging of commodity price risks.
As of September 30, 2006, we had no cash margin deposits associated with
our commodity contract positions and over-the-counter swap partners; however,
our counterparties associated with our commodity contract positions and
over-the-counter swap agreements had margin deposits with us totaling $1.4
million, and we reported this amount within "Accrued other liabilities" in our
accompanying consolidated balance sheet as of September 30,
46
2006. As of December 31, 2005, we had no cash margin deposits associated with
our commodity contract positions and over-the-counter swap partners.
Interest Rate Risk Management
In order to maintain a cost effective capital structure, it is our policy
to borrow funds using a mix of fixed rate debt and variable rate debt. As of
both September 30, 2006 and December 31, 2005, we were a party to interest rate
swap agreements with notional principal amounts of $2.1 billion. We entered into
these agreements for the purposes of:
o hedging the interest rate risk associated with our fixed rate debt
obligations; and
o transforming a portion of the underlying cash flows related to our
long-term fixed rate debt securities into variable rate debt in order
to achieve our desired mix of fixed and variable rate debt.
Since the fair value of fixed rate debt varies with changes in the market
rate of interest, we enter into swaps to receive fixed and pay variable
interest. Such swaps result in future cash flows that vary with the market rate
of interest, and therefore hedge against changes in the fair value of our fixed
rate debt due to market rate changes.
As of September 30, 2006, a notional principal amount of $2.1 billion of
these agreements effectively converts the interest expense associated with the
following series of our senior notes from fixed rates to variable rates based on
an interest rate of LIBOR plus a spread:
o $200 million principal amount of our 5.35% senior notes due August 15,
2007;
o $250 million principal amount of our 6.30% senior notes due February
1, 2009;
o $200 million principal amount of our 7.125% senior notes due March 15,
2012;
o $250 million principal amount of our 5.0% senior notes due December
15, 2013;
o $200 million principal amount of our 5.125% senior notes due November
15, 2014;
o $300 million principal amount of our 7.40% senior notes due March 15,
2031;
o $200 million principal amount of our 7.75% senior notes due March 15,
2032;
o $400 million principal amount of our 7.30% senior notes due August 15,
2033; and
o $100 million principal amount of our 5.80% senior notes due March 15,
2035.
These swap agreements have termination dates that correspond to the
maturity dates of the related series of senior notes, therefore, as of September
30, 2006, the maximum length of time over which we have hedged a portion of our
exposure to the variability in the value of this debt due to interest rate risk
is through March 15, 2035.
The swap agreements related to our 7.40% senior notes contain mutual
cash-out provisions at the then-current economic value every seven years. The
swap agreements related to our 7.125% senior notes contain cash-out provisions
at the then-current economic value in March 2009. The swap agreements related to
our 7.75% senior notes and our 7.30% senior notes contain mutual cash-out
provisions at the then-current economic value every five or seven years.
Hedging effectiveness and ineffectiveness
Our interest rate swaps have been designated as fair value hedges as
defined by SFAS No. 133. According to the provisions of SFAS No. 133, when
derivative contracts are used to hedge the fair value of an asset, liability, or
firm commitment, then reporting changes in the fair value of the hedged item as
well as in the value of the derivative
47
contract is appropriate, 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.
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 by SFAS No. 133 for fair value hedges of
a fixed rate asset or liability using an interest rate swap. 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 under the swaps. Interest expense is accrued monthly and paid
semi-annually. When there is no ineffectiveness in the hedging relationship,
employing the shortcut method results in the same net effect on earnings,
accrual and payment of interest, net effect of changes in interest rates, and
level-yield amortization of hedge accounting adjustments as produced by
explicitly amortizing the hedge accounting adjustments on the debt.
Fair Value of Interest Rate Swap Agreements
The differences between the fair value and the original carrying value
associated with our interest rate swap agreements, that is, the derivative
contracts' changes in fair value, are included within "Deferred charges and
other assets" and "Other long-term liabilities and deferred credits" in our
accompanying consolidated balance sheets. The offsetting entry to adjust the
carrying value of the debt securities whose fair value was being hedged is
recognized as "Market value of interest rate swaps" on our accompanying
consolidated balance sheets.
The following table summarizes the net fair value of our interest rate swap
agreements associated with our interest rate risk management activities and
included on our accompanying consolidated balance sheets as of September 30,
2006 and December 31, 2005 (in thousands):
September 30, December 31,
2006 2005
------------- ------------
Derivatives-net asset/(liability)
Deferred charges and other assets................. $ 67,444 $ 112,386
Other long-term liabilities and deferred credits.. (22,638) (13,917)
--------- ---------
Market value of interest rate swaps............. $ 44,806 $ 98,469
========= =========
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 contracts 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. As of September 30, 2006, all
of our interest rate swap agreements were with counterparties with investment
grade credit ratings.
Other
Certain of our business activities expose us to foreign currency
fluctuations. However, due to the limited size of this exposure, we do not
believe the risks associated with changes in foreign currency will have a
material adverse effect on our business, financial position, results of
operations or cash flows. As a result, we do not significantly hedge our
exposure to fluctuations in foreign currency.
11. Reportable Segments
We divide our operations into four reportable business segments:
o Products Pipelines;
o Natural Gas Pipelines;
o CO2; and
48
o Terminals.
We evaluate performance principally based on each segments' earnings before
depreciation, depletion and amortization, which exclude general and
administrative expenses, third-party debt costs and interest expense,
unallocable interest income and minority interest. Our reportable segments are
strategic business units that offer different products and services. Each
segment is managed separately because each segment involves different products
and marketing strategies.
Our Products Pipelines segment derives its revenues primarily from the
transportation and terminaling of refined petroleum products, including
gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas
Pipelines segment derives its revenues primarily from the sale, transmission,
storage and gathering of natural gas. Our CO2 segment derives its revenues
primarily from the production, sale, and transportation of crude oil from fields
in the Permian Basin of West Texas, the transportation and marketing of carbon
dioxide used as a flooding medium for recovering crude oil from mature oil
fields, and the production and sale of natural gas and natural gas liquids. Our
Terminals segment derives its revenues primarily from the transloading and
storing of refined petroleum products and dry and liquid bulk products,
including coal, petroleum coke, cement, alumina, salt, and chemicals.
Financial information by segment follows (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2006 2005 2006 2005
---------- ---------- ---------- ----------
Revenues(a)
Products Pipelines
Revenues from external customers....... $ 207,726 $ 181,903 $ 577,273 $ 527,818
Intersegment revenues.................. - - - -
Natural Gas Pipelines
Revenues from external customers....... 1,650,427 2,108,788 5,082,183 5,198,337
Intersegment revenues.................. - - - -
CO2
Revenues from external customers....... 192,303 163,079 552,783 488,271
Intersegment revenues.................. - - - -
Terminals
Revenues from external customers....... 222,977 177,484 649,283 515,115
Intersegment revenues.................. 174 - 539 -
----------- ----------- ----------- -----------
Total segment revenues.................... 2,273,607 2,631,254 6,862,061 6,729,541
Less: Total intersegment revenues......... (174) - (539) -
----------- ----------- ----------- -----------
Total consolidated revenues............. $ 2,273,433 $ 2,631,254 $ 6,861,522 $ 6,729,541
=========== =========== =========== ===========
Operating expenses(b)
Products Pipelines........................ $ 94,609 $ 60,613 $ 234,149 $ 169,739
Natural Gas Pipelines..................... 1,519,129 1,996,737 4,693,969 4,863,524
CO2....................................... 68,888 48,546 194,212 152,389
Terminals................................. 122,230 94,318 354,892 271,470
----------- ----------- ----------- -----------
Total consolidated operating expenses... $ 1,804,856 $ 2,200,214 $ 5,477,222 $ 5,457,122
=========== =========== =========== ===========
Other expense (income)(c)
Products Pipelines........................ $ - $ - $ - $ -
Natural Gas Pipelines..................... - - (15,114) -
CO2....................................... - - - -
Terminals................................. - - - -
----------- ----------- ----------- -----------
Total consolidated other
expense (income)........................ $ - $ - $ (15,114) $ -
=========== =========== =========== ===========
Depreciation, depletion and amortization
Products Pipelines........................ $ 20,820 $ 19,849 $ 61,541 $ 59,071
Natural Gas Pipelines..................... 15,959 15,205 47,938 45,779
CO2....................................... 50,731 34,658 132,021 111,822
Terminals................................. 19,320 15,644 55,280 41,972
----------- ----------- ----------- -----------
Total consol. depreciation, depletion
and amortization........................ $ 106,830 $ 85,356 $ 296,780 $ 258,644
=========== =========== =========== ===========
49
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2006 2005 2006 2005
---------- ---------- ---------- ----------
Earnings from equity investments(d)
Products Pipelines........................ $ 514 $ 6,256 $ 11,067 $ 21,706
Natural Gas Pipelines..................... 10,062 8,705 31,833 25,733
CO2....................................... 3,380 5,533 14,113 21,932
Terminals................................. 76 18 190 51
--------- --------- ---------- ----------
Total consolidated equity earnings...... $ 14,032 $ 20,512 $ 57,203 $ 69,422
========= ========= ========== ==========
Amortization of excess cost of equity
investments
Products Pipelines........................ $ 841 $ 832 $ 2,521 $ 2,512
Natural Gas Pipelines..................... 71 70 210 208
CO2....................................... 504 505 1,513 1,513
Terminals................................. - - - -
--------- --------- ---------- ----------
Total consol. amortization of excess
cost of investments..................... $ 1,416 $ 1,407 $ 4,244 $ 4,233
========= ========= ========== ==========
Interest income
Products Pipelines........................ $ 1,123 $ 1,147 $ 3,358 $ 3,445
Natural Gas Pipelines..................... - 193 150 530
CO2....................................... - - - -
Terminals................................. - - - -
Total segment interest income........... 1,123 1,340 3,508 3,975
Unallocated interest income............... 238 109 1,599 374
--------- --------- ---------- ----------
Total consolidated interest income...... $ 1,361 $ 1,449 $ 5,107 $ 4,349
========= ========= ========== ==========
Other, net - income (expense)(e)
Products Pipelines........................ $ 1,583 $ 633 $ 7,783 $ 998
Natural Gas Pipelines..................... 376 1,367 725 1,509
CO2....................................... 324 (6) 336 (6)
Terminals................................. 1,056 886 2,335 (293)
--------- --------- ---------- ----------
Total consolidated other, net - income
(expense)............................... $ 3,339 $ 2,880 $ 11,179 $ 2,208
========= ========= ========== ==========
Income tax benefit (expense)(f)
Products Pipelines........................ $ 584 $ (2,171) $ (3,288) $ (8,209)
Natural Gas Pipelines..................... (973) (361) (900) (1,899)
CO2....................................... (57) (151) (181) (263)
Terminals................................. (3,599) (2,372) (7,451) (9,874)
--------- --------- ---------- ----------
Total consolidated income tax benefit
(expense)............................... $ (4,045) $ (5,055) $ (11,820) $ (20,245)
========= ========= ========== ==========
Segment earnings
Products Pipelines........................ $ 95,260 $ 106,474 $ 297,982 $ 314,436
Natural Gas Pipelines..................... 124,733 106,680 386,988 314,699
CO2....................................... 75,827 84,746 239,305 244,210
Terminals................................. 79,134 66,054 234,724 191,557
--------- --------- ---------- ----------
Total segment earnings(g)............... 374,954 363,954 1,158,999 1,064,902
Interest and corporate administrative
expenses(h)............................... (151,136) (118,567) (441,411) (374,068)
--------- --------- ---------- ----------
Total consolidated net income........... $ 223,818 $ 245,387 $ 717,588 $ 690,834
========= ========= ========== ==========
Segment earnings before depreciation,
depletion, amortization and amortization
of excess cost of equity investments(i)
Products Pipelines........................ $ 116,921 $ 127,155 $ 362,044 $ 376,019
Natural Gas Pipelines..................... 140,763 121,955 435,136 360,686
CO2....................................... 127,062 119,909 372,839 357,545
Terminals................................. 98,454 81,698 290,004 233,529
--------- --------- ---------- ----------
Total segment earnings before DD&A...... 483,200 450,717 1,460,023 1,327,779
Total consol. depreciation, depletion and
amortization.............................. (106,830) (85,356) (296,780) (258,644)
Total consol. amortization of excess cost
of investments............................ (1,416) (1,407) (4,244) (4,233)
Interest and corporate administrative
expenses.................................. (151,136) (118,567) (441,411) (374,068)
--------- --------- ---------- ----------
Total consolidated net income .......... $ 223,818 $ 245,387 $ 717,588 $ 690,834
========= ========= ========== ==========
50
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2006 2005 2006 2005
---------- ---------- ---------- ----------
Capital expenditures(j)
Products Pipelines......................... $ 30,685 $ 82,592 $ 151,927 $ 180,309
Natural Gas Pipelines...................... 18,725 31,707 228,294 64,854
CO2........................................ 75,304 92,603 208,396 219,545
Terminals.................................. 65,392 48,675 162,729 132,478
---------- ---------- ---------- ----------
Total consolidated capital expenditures.. $ 190,106 $ 255,577 $ 751,346 $ 597,186
========== ========== ========== ==========
September 30, December 31,
2006 2005
------------- ------------
Assets
Products Pipelines............ $ 3,895,385 $ 3,873,939
Natural Gas Pipelines......... 3,896,528 4,139,969
CO2........................... 1,859,407 1,772,756
Terminals..................... 2,243,150 2,052,457
------------ ------------
Total segment assets.......... 11,894,470 11,839,121
Corporate assets(k)........... 128,562 84,341
------------ ------------
Total consolidated assets..... $ 12,023,032 $ 11,923,462
============ ============
- --------
(a) Nine month 2006 amounts include a reduction of $1,819 to our CO2 business
segment from a loss on derivative contracts used to hedge forecasted crude
oil sales.
(b) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes. Nine month 2006 amounts include expenses of $13,458 to our Products
Pipelines business segment and $1,500 to our Natural Gas Pipelines business
segment associated with environmental liability adjustments, and a $6,244
reduction in expense to our Natural Gas Pipelines business segment due to
the release of a reserve related to a natural gas purchase/sales contract.
Three and nine month 2005 amounts include a $5,000 increase in expense to
our Products Pipelines business segment associated with a North System
liquids inventory reconciliation adjustment.
(c) Nine month 2006 amount represents a $15,114 gain to our Natural Gas
Pipelines business segment from the combined sale of our Douglas natural
gas gathering system and our Painter Unit fractionation facility.
(d) Nine month 2006 amounts include a $4,861 increase in expense to our
Products Pipelines business segment associated with environmental liability
adjustments on Plantation Pipe Line Company.
(e) Nine month 2006 amounts include a $5,700 increase in income to our Products
Pipelines business segment from the settlement of transmix processing
contracts.
(f) Nine month 2006 amounts include a $1,871 decrease in expense to our
Products Pipelines business segment associated with the tax effect on
expenses from environmental liability adjustments made by Plantation Pipe
Line Company and described in footnote (d).
(g) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses, other
expense (income), depreciation, depletion and amortization, and
amortization of excess cost of equity investments.
(h) Includes unallocated interest income, interest and debt expense, general
and administrative expenses and minority interest expense.
(i) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses and other
expense (income).
(j) Includes sustaining capital expenditures of $15,576 and $42,845 for the
three months ended September 30, 2006 and 2005, respectively, and includes
sustaining capital expenditures of $76,229 and $95,801 for the nine months
ended September 30, 2006 and 2005, respectively. Sustaining capital
expenditures are defined as capital expenditures which do not increase the
capacity of an asset.
(k) Includes cash, cash equivalents, margin and restricted deposits, certain
unallocable deferred charges, and risk management assets related to the
market value of interest rate swaps.
51
We do not attribute interest and debt expense to any of our reportable
business segments. For the three months ended September 30, 2006 and 2005, we
reported (in thousands) total consolidated interest expense of $89,662 and
$69,797, respectively. For the nine months ended September 30, 2006 and 2005, we
reported (in thousands) total consolidated interest expense of $251,216 and
$196,736, respectively.
12. Pensions and Other Post-retirement Benefits
In connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk
Terminals, Inc. in 1998, we acquired certain liabilities for pension and
post-retirement benefits. We provide medical and life insurance benefits to
current employees, their covered dependents and beneficiaries of SFPP and Kinder
Morgan Bulk Terminals. We also provide the same benefits to former salaried
employees of SFPP. Additionally, we will continue to fund these costs for those
employees currently in the plan during their retirement years. SFPP's
post-retirement benefit plan is frozen, and no additional participants may join
the plan.
The noncontributory defined benefit pension plan covering the former
employees of Kinder Morgan Bulk Terminals is the Kinder Morgan, Inc. Retirement
Plan. The benefits under this plan are based primarily upon years of service and
final average pensionable earnings; however, benefit accruals were frozen as of
December 31, 1998.
Net periodic benefit costs for the SFPP post-retirement benefit plan
includes the following components (in thousands):
Other Post-retirement Benefits
--------------------------------------------------------------------
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2006 2005 2006 2005
-------------- -------------- -------------- --------------
Net periodic benefit cost
Service cost........................... $ 3 $ 2 $ 8 $ 6
Interest cost.......................... 68 77 202 231
Amortization of prior service cost..... (29) (29) (88) (87)
Actuarial (gain)....................... (114) (127) (340) (381)
Net periodic benefit cost.............. $ (72) $ (77) $ (218) $ (231)
Our net periodic benefit cost for the third quarter and the first nine
months of 2006 were credits of $72,000 and $218,000, respectively, which
resulted in increases to income, largely due to the amortization of an
unrecognized net actuarial gain and to the amortization of a negative prior
service cost, primarily related to the following:
o there were changes to the plan for both 2004 and 2005 which reduced
liabilities, creating a negative prior service cost that is being
amortized each year; and
o there was a significant drop in 2004 in the number of retired
participants reported as pipeline retirees by Burlington Northern
Santa Fe, which holds a 0.5% special limited partner interest in SFPP,
L.P.
As of September 30, 2006, we estimate our overall net periodic
post-retirement benefit cost for the year 2006 will be an annual credit of
approximately $0.3 million. This amount could change in the remaining months of
2006 if there is a significant event, such as a plan amendment or a plan
curtailment, which would require a remeasurement of liabilities.
13. Related Party Transactions
Plantation Pipe Line Company
We own a 51.17% equity interest in Plantation Pipe Line Company. An
affiliate of ExxonMobil owns the remaining 48.83% interest. In July 2004,
Plantation repaid a $10 million note outstanding and $175 million in outstanding
commercial paper borrowings with funds of $190 million borrowed from its owners.
We loaned Plantation $97.2 million, which corresponds to our 51.17% ownership
interest, in exchange for a seven year note receivable bearing interest at the
rate of 4.72% per annum. The note provides for semiannual payments of principal
52
and interest on December 31 and June 30 each year beginning on December 31, 2004
based on a 25 year amortization schedule, with a final principal payment of
$157.9 million due July 20, 2011. We funded our loan of $97.2 million with
borrowings under our commercial paper program. An affiliate of ExxonMobil owns
the remaining 48.83% equity interest in Plantation and funded the remaining
$92.8 million on similar terms.
As of December 31, 2005, the principal amount receivable from this note was
$94.2 million. We included $2.2 million of this balance within "Accounts, notes
and interest receivable, net-Related parties" on our accompanying consolidated
balance sheets, and we included the remaining $92.0 million balance within
"Notes receivable-Related parties."
In June 2006, Plantation paid to us $1.1 million in principal amount under
the note, and as of September 30, 2006, the principal amount receivable from
this note was $93.1 million. We included $2.2 million of this balance within
"Accounts, notes and interest receivable, net-Related parties" on our
consolidated balance sheet as of September 30, 2006, and we included the
remaining $90.9 million balance as "Notes receivable-Related parties."
Coyote Gas Treating, LLC
Coyote Gas Treating, LLC is a joint venture that was organized in December
1996. It is referred to as Coyote Gulch in this report. The sole asset owned by
Coyote Gulch is a 250 million cubic feet per day natural gas treating facility
located in La Plata County, Colorado. Prior to the contribution of our ownership
interest in Coyote Gulch to Red Cedar Gathering on September 1, 2006, discussed
below, we were the managing partner and owned a 50% equity interest in Coyote
Gulch.
In June 2001, Coyote repaid the $34.2 million in outstanding borrowings
under its 364-day credit facility with funds borrowed from its owners. We loaned
Coyote $17.1 million, which corresponded to our 50% ownership interest, in
exchange for a one-year note receivable bearing interest payable monthly at
LIBOR plus a margin of 0.875%. On June 30, 2002 and June 30, 2003, the note was
extended for one year. On June 30, 2004, the term of the note was made
month-to-month. In 2005, we reduced our investment in the note by $0.1 million
to account for our share of investee losses in excess of the carrying value of
our equity investment in Coyote, and as of December 31, 2005, we included the
principal amount of $17.0 million related to this note within "Notes
Receivable-Related Parties" on our consolidated balance sheet.
In March 2006, the owners of Coyote Gulch agreed to a resolution that would
transfer Coyote Gulch's notes payable to members' equity. According to the
provisions of this resolution, we then contributed the principal amount of $17.0
million related to our note receivable to our equity investment in Coyote Gulch.
In the third quarter of 2006, the Southern Ute Indian Tribe acquired the
remaining 50% ownership interest in Coyote Gulch from Enterprise Field Services
LLC. The acquisition was made effective March 1, 2006. On September 1, 2006, we
and the Southern Ute Tribe agreed to a resolution that would transfer all of the
members' equity in Coyote Gulch to the members' equity of Red Cedar Gathering, a
joint venture organized in August 1994 and referred to in this report as Red
Cedar. Red Cedar owns and operates natural gas gathering, compression and
treating facilities in the Ignacio Blanco Field in La Plata County, Colorado,
and is owned 49% by us and 51% by the Southern Ute Tribe. Under the terms of a
five-year operating lease agreement that became effective January 1, 2002, Red
Cedar also operates the gas treating facility owned by Coyote Gulch and is
responsible for all operating and maintenance expenses and capital costs.
According to the provisions of the September 1, 2006 resolution, we and the
Southern Ute Tribe contributed the value of our respective 50% ownership
interests in Coyote Gulch to Red Cedar, and as a result, Coyote Gulch became a
wholly owned subsidiary of Red Cedar. The value of our 50% equity contribution
from Coyote Gulch to Red Cedar on September 1, 2006 was $16.7 million, and this
amount remains included within "Investments" on our consolidated balance sheet
as of September 30, 2006.
53
14. Regulatory Matters
Accounting for Integrity Testing Costs
On November 5, 2004, the FERC issued a Notice of Proposed Accounting
Release that would require FERC jurisdictional entities to recognize costs
incurred in performing pipeline assessments that are a part of a pipeline
integrity management program as maintenance expense in the period incurred. The
proposed accounting ruling was in response to the FERC's finding of diverse
practices within the pipeline industry in accounting for pipeline assessment
activities. The proposed ruling would standardize these practices. Specifically,
the proposed ruling clarifies the distinction between costs for a "one-time
rehabilitation project to extend the useful life of the system," which could be
capitalized, and costs for an "on-going inspection and testing or maintenance
program," which would be accounted for as maintenance and charged to expense in
the period incurred.
On June 30, 2005, the FERC issued an order providing guidance to the
industry on accounting for costs associated with pipeline integrity management
requirements. The order is effective prospectively from January 1, 2006. Under
the order, the costs to be expensed as incurred include those to:
o prepare a plan to implement the program;
o identify high consequence areas;
o develop and maintain a record keeping system; and
o inspect affected pipeline segments.
The costs of modifying the pipeline to permit in-line inspections, such as
installing pig launchers and receivers, are to be capitalized, as are certain
costs associated with developing or enhancing computer software or to add or
replace other items of plant.
The Interstate Natural Gas Association of America, referred to in this
report as INGAA, sought rehearing of the FERC's June 30, 2005 order. The FERC
denied INGAA's request for rehearing on September 19, 2005. On December 15,
2005, INGAA filed with the United States Court of Appeals for the District of
Columbia Circuit, in Docket No. 05-1426, a petition for review asking the court
whether the FERC lawfully ordered that interstate pipelines subject to FERC rate
regulation and related accounting rules must treat certain costs incurred in
complying with the Pipeline Safety Improvement Act of 2002, along with related
pipeline testing costs, as expenses rather than capital items for purposes of
complying with the FERC's regulatory accounting regulations. On May 10, 2006,
the court issued an order establishing a briefing schedule. Under the schedule,
INGAA filed its initial brief on June 23, 2006. Both the FERC's and INGAA's
reply briefs have been filed.
Due to the implementation of this FERC order on January 1, 2006, which
caused our FERC-regulated natural gas pipelines to expense certain pipeline
integrity management program costs that would have been capitalized, our Kinder
Morgan Interstate Gas Transmission system, referred to in this report as KMIGT,
expects an increase of approximately $0.9 million in operating expenses in 2006
compared to 2005. Also, beginning in the third quarter of 2006, our Texas
intrastate natural gas pipeline group and the operations included in our
Products Pipelines and CO2 business segments began recognizing certain costs
incurred as part of their pipeline integrity management program as operating
expense in the period incurred, and in addition, recorded an expense for costs
previously capitalized during the first six months of 2006. For the year 2006
compared to 2005, we expect this change to result in operating expense increases
of approximately $1.8 million for our Texas intrastate gas group, $26.8 million
for our Products Pipelines business segment, and $1.4 million for our CO2
business segment. Combined, this change did not have any material effect to
prior periods and is not expected to have a material impact on our financial
position, results of operations, or cash flows for the 2006 annual period. In
addition, due to the fact that these amounts will not be capitalized but instead
charged to expense, we expect our 2006 sustaining capital expenditures to be
reduced by similar amounts.
Selective Discounting
On November 22, 2004, the FERC issued a notice of inquiry seeking comments
on its policy of selective discounting. Specifically, the FERC is asking parties
to submit comments and respond to inquiries regarding the
54
FERC's practice of permitting pipelines to adjust their ratemaking throughput
downward in rate cases to reflect discounts given by pipelines for competitive
reasons - when the discount is given to meet competition from another gas
pipeline. Comments were filed by numerous entities, including Natural Gas
Pipeline Company of America (a Kinder Morgan, Inc. affiliate), on March 2, 2005.
Several reply comments have subsequently been filed. By an order issued on May
31, 2005, the FERC reaffirmed its existing policy on selective discounting by
interstate pipelines without change. Several entities filed for rehearing;
however, by an order issued on November 17, 2005, the FERC denied all requests
for rehearing. On January 9, 2006, a petition for judicial review of the FERC's
May 31, 2005 and November 17, 2005 orders was filed by the Northern Municipal
District Group/Midwest Region Gas Task Force Association.
Notice of Proposed Rulemaking - Market Based Storage Rates
On December 22, 2005, the FERC issued a notice of proposed rulemaking to
amend its regulations by establishing two new methods for obtaining market based
rates for underground natural gas storage services. First, the FERC proposed to
modify its market power analysis to better reflect competitive alternatives to
storage. Doing so would allow a storage applicant to include other storage
services as well as non-storage products such as pipeline capacity, local
production, or liquefied natural gas supply in its calculation of market
concentration and its analysis of market share. Secondly, the FERC proposed to
modify its regulations to permit the FERC to allow market based rates for new
storage facilities even if the storage provider is unable to show that it lacks
market power. Such modifications would be allowed provided the FERC finds that
the market based rates are in the public interest, are necessary to encourage
the construction of needed storage capacity, and that customers are adequately
protected from the abuse of market power.
On June 19, 2006, FERC issued Order No. 678 allowing for broader
market-based pricing of storage services. The rule expands the alternatives that
can be considered in evaluating competition, provides that market-based pricing
may be available even when market power is present (if market-based pricing is
needed to stimulate development), and treats expansions of existing storage
facilities similar to new storage facilities. The order became effective July
27, 2006. Several parties have filed for rehearing of this Order.
Natural Gas Pipeline Expansion Filings
Rockies Express Pipeline
On May 31, 2006, in FERC Docket No. CP06-354-000, Rockies Express Pipeline
LLC filed an application for authorization to construct and operate certain
facilities comprising its proposed "Rockies Express-West Project." This project
is the first planned segment extension of the Rockies Express' currently
certificated facilities, which includes (i) a 136-mile pipeline segment
currently in operation from the Meeker Hub in Colorado to the Wamsutter Hub in
Wyoming, and (ii) a 191-mile segment currently under construction and expected
to be in service by January 1, 2007, from Wamsutter to the Cheyenne Hub located
in Weld County, Colorado. The Rockies Express-West Project will be comprised of
approximately 713 miles of 42-inch diameter pipeline extending from the Cheyenne
Hub to an interconnection with Panhandle Eastern Pipe Line located in Audrain
County, Missouri. The segment extension proposes to transport approximately 1.5
billion cubic feet per day of natural gas across the following five states:
Wyoming, Colorado, Nebraska, Kansas and Missouri. The project will also include
certain improvements to existing Rockies Express facilities located to the west
of the Cheyenne Hub.
On September 21, 2006, the FERC issued a favorable preliminary
determination on all non-environmental issues of the project, approving Rockies
Express' application (i) to construct and operate the 713 miles of new natural
gas transmission facilities from the Cheyenne Hub and (ii) to lease capacity on
Questar Overthrust Pipeline Company, which will extend the Rockies Express
system 140 miles west from Wamsutter to the Opal Hub in Wyoming. Pending
completion of the FERC environmental review and the issuance of a certificate,
the project is expected to begin service on January 1, 2008. Rockies Express
will file a separate application in the future for its proposed "Rockies
Express-East Project," which will extend the pipeline from eastern Missouri to
the Clarington Hub in eastern Ohio.
55
TransColorado Pipeline
On June 23, 2006, in FERC Docket No. CP06-401-000, TransColorado Gas
Transmission Company filed an application for authorization to construct and
operate certain facilities comprising its proposed "Blanco-Meeker Expansion
Project." Upon implementation, this project will facilitate the transportation
of up to approximately 250 million cubic feet per day of natural gas from the
Blanco Hub area in San Juan County, New Mexico through TransColorado's existing
interstate pipeline for delivery to the Rockies Express Pipeline at an existing
point of interconnection located in the Meeker Hub in Rio Blanco County,
Colorado.
Kinder Morgan Louisiana Pipeline
On September 8, 2006, in FERC Docket No. CP06-449-000, we filed an
application with the FERC requesting approval to construct and operate our
Kinder Morgan Louisiana Pipeline. The pipeline will extend approximately 135
miles from Cheniere's Sabine Pass liquefied natural gas terminal in Cameron
Parish, Louisiana, to various delivery points in Louisiana and will provide
interconnects with many other natural gas pipelines, including KMI's Natural Gas
Pipeline Company of America. The project is supported by fully subscribed
capacity and long-term customer commitments with Chevron and Total. The entire
approximately $500 million project is expected to be in service in the second
quarter of 2009.
FERC Order No. 2004
On July 20, 2006, the FERC accepted our interstate pipelines' May 19, 2005
compliance filing under Order No. 2004, the order adopting standards of conduct
that govern the relationships between natural gas transmission providers and all
their marketing and energy affiliates.
15. Recent Accounting Pronouncements
SFAS No. 123R
On December 16, 2004, the Financial Accounting Standards Board issued SFAS
No. 123R (revised 2004), "Share-Based Payment." This Statement amends SFAS No.
123, "Accounting for Stock-Based Compensation," and requires companies to
expense the value of employee stock options and similar awards. Significant
provisions of SFAS No. 123R include the following:
o share-based payment awards result in a cost that will be measured at
fair value on the awards' grant date, based on the estimated number of
awards that are expected to vest. Compensation cost for awards that
vest would not be reversed if the awards expire without being
exercised;
o when measuring fair value, companies can choose an option-pricing
model that appropriately reflects their specific circumstances and the
economics of their transactions;
o companies will recognize compensation cost for share-based payment
awards as they vest, including the related tax effects. Upon
settlement of share-based payment awards, the tax effects will be
recognized in the income statement or additional paid-in capital; and
o public companies are allowed to select from three alternative
transition methods - each having different reporting implications.
For us, this Statement became effective January 1, 2006. However, we have
not granted common unit options or made any other share-based payment awards
since May 2000, and as of December 31, 2005, all outstanding options to purchase
our common units were fully vested. Therefore, the adoption of this Statement
did not have an effect on our consolidated financial statements due to the fact
that we have reached the end of the requisite service period for any
compensation cost resulting from share-based payments made under our common unit
option plan.
56
SFAS No. 154
On June 1, 2005, the FASB issued SFAS No. 154, "Accounting Changes and
Error Corrections." This Statement replaces Accounting Principles Board Opinion
No. 20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes in
Interim Financial Statements." SFAS No. 154 applies to all voluntary changes in
accounting principle, and changes the requirements for accounting for and
reporting of a change in accounting principle.
SFAS No. 154 requires retrospective application to prior periods' financial
statements of a voluntary change in accounting principle unless it is
impracticable. In contrast, APB No. 20 previously required that most voluntary
changes in accounting principle be recognized by including in net income of the
period of the change the cumulative effect of changing to the new accounting
principle. The FASB believes the provisions of SFAS No. 154 will improve
financial reporting because its requirement to report voluntary changes in
accounting principles via retrospective application, unless impracticable, will
enhance the consistency of financial information between periods.
The provisions of this Statement are effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005
(January 1, 2006 for us). The Statement does not change the transition
provisions of any existing accounting pronouncements, including those that are
in a transition phase as of the effective date of this Statement. Adoption of
this Statement did not have any immediate effect on our consolidated financial
statements, and we will apply this guidance prospectively.
EITF 04-5
In June 2005, the Emerging Issues Task Force reached a consensus on Issue
No. 04-5, or EITF 04-5, "Determining Whether a General Partner, or the General
Partners as a Group, Controls a Limited Partnership or Similar Entity When the
Limited Partners Have Certain Rights." EITF 04-5 provides guidance for purposes
of assessing whether certain limited partners rights might preclude a general
partner from controlling a limited partnership.
For general partners of all new limited partnerships formed, and for
existing limited partnerships for which the partnership agreements are modified,
the guidance in EITF 04-5 is effective after June 29, 2005. For general partners
in all other limited partnerships, the guidance is effective no later than the
beginning of the first reporting period in fiscal years beginning after December
15, 2005 (January 1, 2006, for us). The adoption of EITF 04-5 did not have an
effect on our consolidated financial statements.
SFAS No. 155
On February 16, 2006, the FASB issued SFAS No. 155, "Accounting for Certain
Hybrid Financial Instruments." This Statement amends SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities" and SFAS No. 140, "Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities." The Statement improves the financial reporting of certain hybrid
financial instruments by requiring more consistent accounting that eliminates
exemptions and provides a means to simplify the accounting for these
instruments. Specifically, it allows financial instruments that have embedded
derivatives to be accounted for as a whole (eliminating the need to bifurcate
the derivative from its host) if the holder elects to account for the whole
instrument on a fair value basis.
The provisions of this Statement are effective for all financial
instruments acquired or issued after the beginning of an entity's first fiscal
year that begins after September 15, 2006 (January 1, 2007 for us). Adoption of
this Statement should not have any immediate effect on our consolidated
financial statements, and we will apply this guidance prospectively.
SFAS No. 156
On March 17, 2006, the FASB issued SFAS No. 156, "Accounting for Servicing
of Financial Assets." This Statement amends SFAS No. 140 and simplifies the
accounting for servicing assets and liabilities, such as those
57
common with mortgage securitization activities. Specifically, this Statement
addresses the recognition and measurement of separately recognized servicing
assets and liabilities, and provides an approach to simplify efforts to obtain
hedge-like (offset) accounting by permitting a servicer that uses derivative
financial instruments to offset risks on servicing to report both the derivative
financial instrument and related servicing asset or liability by using a
consistent measurement attribute--fair value.
An entity should adopt this Statement as of the beginning of its first
fiscal year that begins after September 15, 2006 (January 1, 2007 for us).
Adoption of this Statement should not have any immediate effect on our
consolidated financial statements, and we will apply this guidance
prospectively.
EITF 06-3
On June 28, the FASB ratified the consensuses reached by the Emerging
Issues Task Force on EITF 06-3, "How Taxes Collected from Customers and Remitted
to Governmental Authorities Should Be Presented in the Income Statement (That
is, Gross versus Net Presentation)." According to the provisions of EITF 06-3:
o taxes assessed by a governmental authority that are directly imposed
on a revenue-producing transaction between a seller and a customer may
include, but are not limited to, sales, use, value added, and some
excise taxes; and
o that the presentation of such taxes on either a gross (included in
revenues and costs) or a net (excluded from revenues) basis is an
accounting policy decision that should be disclosed pursuant to
Accounting Principles Board Opinion No. 22 (as amended) "Disclosure of
Accounting Policies." In addition, for any such taxes that are
reported on a gross basis, a company should disclose the amounts of
those taxes in interim and annual financial statements for each period
for which an income statement is presented if those amounts are
significant. The disclosure of those taxes can be done on an aggregate
basis.
EITF 06-3 should be applied to financial reports for interim and annual
reporting periods beginning after December 15, 2006 (January 1, 2007 for us).
Because the provisions of EITF 06-3 require only the presentation of additional
disclosures, we do not expect the adoption of EITF 06-3 to have an effect on our
consolidated financial statements.
FIN 48
In June 2006, the FASB issued Interpretation (FIN) No. 48, "Accounting for
Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109." This
interpretation clarifies the accounting for uncertainty in income taxes
recognized in an enterprise's financial statements in accordance with SFAS No.
109, "Accounting for Income Taxes." This Interpretation prescribes a recognition
threshold and measurement attribute for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a tax return. It
also provides guidance on derecognition, classification, interest and penalties,
accounting in interim periods, disclosure, and transition. This Interpretation
is effective for fiscal years beginning after December 15, 2006 (January 1, 2007
for us). We are currently reviewing the effects of this Interpretation.
SAB 108
In September 2006, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 108. This Bulletin requires a "dual approach" for
quantifications of errors using both a method that focuses on the income
statement impact, including the cumulative effect of prior years' misstatements,
and a method that focuses on the period-end balance sheet. SAB No. 108 will be
effective for us as of January 1, 2007. The adoption of this Bulletin is not
expected to have a material impact on our consolidated financial statements.
SFAS No. 157
On September 15, 2006, the FASB issued SFAS No. 157, "Fair Value
Measurements." This Statement defines fair value in generally accepted
accounting principles, and expands disclosures about fair value measurements. It
addresses how companies should measure fair value when they are required to use
a fair value measure for
58
recognition or disclosure purposes under generally accepted accounting
principles and, as a result, there is now a common definition of fair value to
be used throughout generally accepted accounting principles.
This Statement applies to other accounting pronouncements that require or
permit fair value measurements; the Board having previously concluded in those
accounting pronouncements that fair value is the relevant measurement attribute.
Accordingly, this Statement does not require any new fair value measurements;
however, for some entities the application of this Statement will change current
practice. The changes to current practice resulting from the application of this
Statement relate to the definition of fair value, the methods used to measure
fair value, and the expanded disclosures about fair value measurements.
This Statement is effective for financial statements issued for fiscal
years beginning after November 15, 2007 (January 1, 2008 for us), and interim
periods within those fiscal years. This Statement is to be applied prospectively
as of the beginning of the fiscal year in which this Statement is initially
applied, with certain exceptions. The disclosure requirements of this Statement
are to be applied in the first interim period of the fiscal year in which this
Statement is initially applied. We are currently reviewing the effects of this
Statement.
SFAS No. 158
On September 29, 2006, the FASB issued SFAS No. 158, "Employers' Accounting
for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB
Statement Nos. 87, 88, 106 and 132(R)." This Statement requires an employer to:
o recognize the overfunded or underfunded status of a defined benefit
pension plan or postretirement benefit plan (other than a
multiemployer plan) as an asset or liability in its statement of
financial position;
o measure a plan's assets and its obligations that determine its funded
status as of the end of the employer's fiscal year (with limited
exceptions), and to disclose in the notes to financial statements
additional information about certain effects on net periodic benefit
cost for the next fiscal year that arise from delayed recognition of
the gains or losses, prior service costs or credits, and transition
assets or obligations; and
o recognize changes in the funded status of a plan in the year in which
the changes occur through comprehensive income.
Past accounting standards only required an employer to disclose the
complete funded status of its plans in the notes to the financial statements.
Recognizing the funded status of a company's benefit plans as a net liability or
asset on its balance sheet will require an offsetting adjustment to "Accumulated
other comprehensive income/loss" in shareholders' equity ("Partners' Capital"
for us). SFAS No. 158 does not change how pensions and other postretirement
benefits are accounted for and reported in the income statement--companies will
continue to follow the existing guidance in previous accounting standards.
Accordingly, the amounts to be recognized in "Accumulated other comprehensive
income/loss" representing unrecognized gains/losses, prior service
costs/credits, and transition assets/obligations will continue to be amortized
under the existing guidance. Those amortized amounts will continue to be
reported as net periodic benefit cost in the income statement. Prior to SFAS No.
158, those unrecognized amounts were only disclosed in the notes to the
financial statements.
According to the provisions of this Statement, an employer with publicly
traded equity securities is required to initially recognize the funded status of
a defined benefit pension plan or postretirement benefit plan and to provide the
required disclosures as of the end of the fiscal year ending after December 15,
2006 (December 31, 2006 for us). In the year that the recognition provisions of
this Statement are initially applied, an employer is required to disclose, in
the notes to the annual financial statements, the incremental effect of applying
this Statement on individual line items in the year-end statement of financial
position. The requirement to measure plan assets and benefit obligations as of
the date of the employer's fiscal year-end statement of financial position is
effective for fiscal years ending after December 15, 2008 (December 31, 2008 for
us). In the year that the measurement date provisions of this Statement are
initially applied, a business entity is required to disclose the separate
adjustments of retained earnings ("Partners' Capital" for us) and "Accumulated
other comprehensive income/loss" from applying this Statement. While earlier
application of the recognition of measurement date provisions is allowed, we
have opted not to adopt this part of the Statement early.
59
We will apply the guidance of SFAS No. 158 prospectively; retrospective
application of this Statement is not permitted. We are currently reviewing the
effects of this Statement, but we do not expect the adoption of this Statement
to have a material effect on our statement of financial position as of December
31, 2006. Currently, based on the most recent measurement of our benefit plan
assets and obligations, we expect the incremental impact on our December 31,
2006 statement of financial position from adopting the recognition provisions of
this Statement to be as follows (amounts are approximations): a $6.1 million
decrease in total liabilities, and a $6.1 million increase in partners' capital
("Accumulated other comprehensive income/loss.")
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
The following discussion and analysis of our financial condition and
results of operations provides you with a narrative on our financial results. It
contains a discussion and analysis of the results of operations for each segment
of our business, followed by a discussion and analysis of our financial
condition. You should read the following discussion and analysis in conjunction
with:
o our accompanying interim consolidated financial statements and related
notes (included elsewhere in this report), and
o our consolidated financial statements, related notes and management's
discussion and analysis of financial condition and results of
operations included in our Annual Report on Form 10-K for the year
ended December 31, 2005.
Critical Accounting Policies and Estimates
Accounting standards require information in financial statements about the
risks and uncertainties inherent in significant estimates, and the application
of generally accepted accounting principles involves the exercise of varying
degrees of judgment. Certain amounts included in or affecting our consolidated
financial statements and related disclosures must be estimated, requiring us to
make certain assumptions with respect to values or conditions that cannot be
known with certainty at the time the financial statements are prepared. These
estimates and assumptions affect the amounts we report for our assets and
liabilities, our revenues and expenses during the reporting period, and our
disclosure of contingent assets and liabilities at the date of our financial
statements.
We routinely evaluate these estimates, utilizing historical experience,
consultation with experts and other methods we consider reasonable in the
particular circumstances. Nevertheless, actual results may differ significantly
from our estimates. Any effects on our business, financial position or results
of operations resulting from revisions to these estimates are recorded in the
period in which the facts that give rise to the revision become known. In
preparing our consolidated financial statements and related disclosures,
examples of certain areas that require more judgment relative to others include
our use of estimates in determining:
o the economic useful lives of our assets;
o the fair values used to determine possible asset impairment charges;
o reserves for environmental claims, legal fees, transportation rate
cases and other litigation liabilities;
o provisions for uncollectible accounts receivables;
o exposures under contractual indemnifications; and
o various other recorded or disclosed amounts.
Further information about us and information regarding our accounting
policies and estimates that we consider to be "critical" can be found in our
Annual Report on Form 10-K for the year ended December 31, 2005. There have
60
not been any significant changes in these policies and estimates during the
three and nine months ended September 30, 2006.
Results of Operations
Consolidated
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- -------------------
2006 2005 2006 2005
---- ---- ---- ----
(In thousands)
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments
Products Pipelines........................................... $ 116,921 $ 127,155 $ 362,044 $ 376,019
Natural Gas Pipelines........................................ 140,763 121,955 435,136 360,686
CO2.......................................................... 127,062 119,909 372,839 357,545
Terminals.................................................... 98,454 81,698 290,004 233,529
--------- --------- ---------- ----------
Segment earnings before depreciation, depletion and
amortization expense and amortization of excess cost of
equity investments(a).......................................... 483,200 450,717 1,460,023 1,327,779
Depreciation, depletion and amortization expense............. (106,830) (85,356) (296,780) (258,644)
Amortization of excess cost of equity investments............ (1,416) (1,407) (4,244) (4,233)
Interest and corporate administrative expenses(b)............ (151,136) (118,567) (441,411) (374,068)
--------- --------- ---------- ----------
Net income....................................................... $ 223,818 $ 245,387 $ 717,588 $ 690,834
========= ========= ========== ==========
- -----------
(a) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses and other
expense (income). Operating expenses include natural gas purchases and
other costs of sales, operations and maintenance expenses, fuel and power
expenses and taxes, other than income taxes.
(b) Includes unallocated interest income, interest and debt expense, general
and administrative expenses (including unallocated litigation and
environmental expenses) and minority interest expense.
Our consolidated net income for the quarterly period ended September
30, 2006 was $223.8 million ($0.40 per diluted unit), compared to $245.4 million
($0.57 per diluted unit) for the quarterly period ended September 30, 2005. Our
consolidated net income was negatively impacted in the third quarter of 2006 by
(i) an $18.1 million decrease in net income from our Products Pipelines business
segment, consisting of an approximate $11.6 million decrease related to a change
that transferred certain pipeline integrity management costs from sustaining
capital expenditures to expense and an approximate $6.5 million decrease related
to pipeline integrity costs expensed in the third quarter of 2006 and (ii) a
$16.1 million decrease in net income from our CO2 business segment, related to
higher depreciation expenses that were largely caused by a higher
unit-of-production depreciation rate as a result of a reduction in reserves at
our SACROC oil field unit. However, due to the fact that we deduct our
sustaining capital expenditures from our net income to determine distributable
cash flow, and that depreciation, depletion and amortization expenses do not
affect cash and are therefore added to our net income to determine distributable
cash flow, these two items negatively impacted our overall distributable cash
flow for the third quarter of 2006 by only $3.5 million. The difference
primarily relates to our share of Plantation Pipe Line's third quarter 2006
pipeline integrity expenses, which were included in our net income under the
equity method of accounting but excluded from our consolidated sustaining
capital expenditures.
Net income for the nine months ended September 30, 2006 was $717.6 million
($1.45 per diluted unit), compared to $690.8 million ($1.61 per diluted unit)
for the first nine months of 2005. We earned total revenues of $2,273.4 million
and $2,631.3 million, respectively, in the three month periods ended September
30, 2006 and 2005, and revenues of $6,861.5 million and $6,729.5 million,
respectively, in the nine month periods ended September 30, 2006 and 2005.
We declared a cash distribution of $0.81 per unit for the third quarter of
2006 (an annualized rate of $3.24). This distribution is almost 3% higher than
the $0.79 per unit distribution we made for the third quarter of 2005. Our
general partner and our common and Class B unitholders receive quarterly
distributions in cash, while KMR, the sole owner of our i-units, receives
quarterly distributions in additional i-units. The value of the quarterly
per-share distribution of i-units is based on the value of the quarterly
per-share cash distribution made to our common and Class B unitholders.
61
Our annual published budget calls for cash distributions of $3.28 per unit
for 2006; however, no assurance can be given that we will be able to achieve
this level of distribution. Our budget does not take into account any
transportation rate reductions or capital costs associated with financing the
payment of reparations sought by shippers on our Pacific operations' interstate
pipelines, which we now estimate will be approximately $15 million in 2006. We
currently expect to distribute between $3.24 and $3.28 per unit for 2006. For
more information on our Pacific operations' regulatory proceedings, see Note 3
to our consolidated financial statements included elsewhere in this report.
Segment earnings before depreciation, depletion and amortization expenses
Because our partnership agreement requires us to distribute 100% of our
available cash to our partners on a quarterly basis (available cash consists
primarily of all our cash receipts, less cash disbursements and changes in
reserves), we consider each period's earnings before all non-cash depreciation,
depletion and amortization expenses, including amortization of excess cost of
equity investments, to be an important measure of our success in maximizing
returns to our partners. We also use this measure of profit and loss (segment
earnings before depreciation, depletion and amortization expenses) internally
for evaluating segment performance and deciding how to allocate resources to our
four reportable business segments. For the third quarters of 2006 and 2005, our
total segment earnings before depreciation, depletion and amortization totaled
$483.2 million and $450.7 million, respectively, and for the first nine months
of 2006 and 2005, our total segment earnings before depreciation, depletion and
amortization totaled $1,460.0 million and $1,327.8 million, respectively. As
discussed below in "--Products Pipelines," our total segment earnings before
depreciation, depletion and amortization expenses in both the third quarter and
first nine months of 2006 were negatively impacted by $18.1 million due to a
change related to the expensing of pipeline integrity costs.
On a consolidated basis, throughout the first nine months of 2006, we
increased our segment earnings before depreciation, depletion and amortization
expenses in 2006, relative to 2005, by capitalizing on:
o improved sales margins on renewal and incremental natural gas sale
contracts and higher earnings from natural gas storage and processing
activities, largely from our Texas intrastate natural gas pipeline
group;
o strong natural gas gathering operations from the Red Cedar Gathering
Company, our 49%-owned equity investee;
o the sales of carbon dioxide, crude oil and natural gas plant liquids
products at higher average prices, and transporting higher volumes of
carbon dioxide for use in enhanced oil recovery operations; and
o incremental contributions from bulk and liquids terminal operations
acquired since the third quarter of 2005.
Products Pipelines
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- -------------------
2006 2005 2006 2005
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 207,726 $ 181,903 $ 577,273 $ 527,818
Operating expenses(a)...................................... (94,609) (60,613) (234,149) (169,739)
Earnings from equity investments(b)........................ 514 6,256 11,067 21,706
Interest income and Other, net-income (expense)(c)......... 2,706 1,780 11,141 4,443
Income taxes(d)............................................ 584 (2,171) (3,288) (8,209)
--------- --------- --------- ---------
Earnings before depreciation, depletion and
amortization Expense and amortization of excess
cost of equity investments............................... 116,921 127,155 362,044 376,019
Depreciation, depletion and amortization expense........... (20,820) (19,849) (61,541) (59,071)
Amortization of excess cost of equity investments.......... (841) (832) (2,521) (2,512)
--------- --------- --------- ---------
Segment earnings......................................... $ 95,260 $ 106,474 $ 297,982 $ 314,436
========= ========= ========= =========
62
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- --------------------
2006 2005 2006 2005
---- ---- ---- ----
Gasoline (MMBbl)........................................... 117.1 117.5 344.1 344.4
Diesel fuel (MMBbl)........................................ 42.2 41.7 120.2 122.8
Jet fuel (MMBbl)........................................... 30.0 29.3 89.4 88.1
----- ----- ----- -----
Total refined products volumes (MMBbl)................... 189.3 188.5 553.7 555.3
Natural gas liquids (MMBbl)................................ 9.3 8.4 28.0 26.1
----- ----- ----- -----
Total delivery volumes (MMBbl)(e)........................ 198.6 196.9 581.7 581.4
- ----------
(a) Nine month 2006 amount includes a $13,458 increase in expense associated
with environmental liability adjustments. Third quarter and nine month 2005
amounts include a $5,000 increase in expense associated with a North System
liquids inventory reconciliation adjustment.
(b) Nine month 2006 amount includes a $4,861 increase in expense associated
with environmental liability adjustments on Plantation Pipe Line Company.
(c) Nine month 2006 amount includes a $5,700 increase in income from the
settlement of transmix processing contracts.
(d) Nine month 2006 amount includes a $1,871 decrease in expense associated
with the tax effect on our share of environmental expenses incurred by
Plantation Pipe Line Company and described in footnote (b).
(e) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
Our Products Pipelines segment reported earnings before depreciation,
depletion and amortization of $116.9 million on revenues of $207.7 million in
the third quarter of 2006. This compares to earnings before depreciation,
depletion and amortization of $127.2 million on revenues of $181.9 million in
the third quarter of 2005. For the comparable nine month periods, the segment
reported earnings before depreciation, depletion and amortization of $362.0
million on revenues of $577.3 million in 2006, and earnings before depreciation,
depletion and amortization of $376.0 million on revenues of $527.8 million in
2005.
Segment Earnings before Depreciation, Depletion and Amortization
The segment's $10.3 million (8%) decrease in earnings before depreciation,
depletion and amortization expenses in the third quarter of 2006 compared with
the third quarter of 2005, and its $14.0 million (4%) decrease in earnings
before depreciation, depletion and amortization in the first nine months of 2006
compared with the first nine months of 2005 were largely related to incremental
pipeline maintenance expenses recognized in the third quarter of 2006, related
to a change that both recognized and transferred a portion of the segment's
pipeline integrity costs from sustaining capital expenditures (within "Property,
plant and equipment, net" on our accompanying consolidated balance sheets) to
maintenance expense (within "Operations and maintenance" in our accompanying
consolidated statements of income).
Pipeline integrity costs encompass those costs incurred as part of an
overall pipeline integrity management program, which is a process for assessing
and mitigating pipeline risks in order to reduce both the likelihood and
consequences of incidents. An effective pipeline integrity program is a
systematic, comprehensive process that entails pipeline assessment services,
maintenance and repair services, and regulatory compliance. Our pipeline
integrity program is designed to provide our management the information needed
to effectively allocate resources for appropriate prevention, detection and
mitigation activities.
Beginning in the third quarter of 2006, the refined petroleum products
pipelines and associated terminal operations included within our Products
Pipelines segment (including Plantation Pipe Line Company, our 51%-owned equity
investee) began recognizing certain costs incurred as part of its pipeline
integrity management program as maintenance expense in the period incurred, and
in addition, recorded an expense for costs previously capitalized during the
first six months of 2006. Combined, this change reduced the segment's earnings
before depreciation, depletion and amortization expenses by $18.1
million--increasing maintenance expenses by $14.9 million, decreasing earnings
from equity investments by $5.2 million, and decreasing income tax expenses by
$2.0 million.
63
In addition, as noted in the table above, the segment's earnings before
depreciation, depletion and amortization expenses for the first nine months of
2006 included environmental expenses of $16.4 million, net of taxes, from the
adjustment of environmental liabilities, and other income of $5.7 million from
the settlement of transmix processing contracts. Both of these items occurred in
the second quarter of 2006. Also, the segment's earnings before depreciation,
depletion and amortization expenses for the third quarter and first nine months
of 2005 included a loss of $5.0 million, recognized in September 2005, to
account for differences between physical and book natural gas liquids inventory
on our North System natural gas liquids pipeline.
The overall decreases of $10.3 million (8%) and $14.0 million (4%),
respectively, in the three and nine month segment earnings before depreciation,
depletion and amortization expenses in 2006, relative to 2005, were primarily
due to the following:
o increases of $5.9 million (480%) and $7.5 million (94%) respectively,
from our North System--due primarily to the $5.0 million inventory
reconciliation reserve taken in the third quarter of 2005, as
discussed above, and to higher throughput revenues in both the third
quarter and first nine months of 2006. The overall increases were
partly offset by a $1.0 million increase in pipeline maintenance
expenses due to the expensing of pipeline integrity costs;
o increases of $1.1 million (22%) and $6.0 million (37%), respectively,
from our petroleum pipeline transmix processing operations--due
primarily to incremental earnings before depreciation, depletion and
amortization from the inclusion of our recently constructed
Greensboro, North Carolina transmix facility and (for the comparable
nine month periods) to an increase of $5.7 million related to
favorable settlements of transmix contract agreements.
In the second quarter of 2006, we completed construction and placed
into service the approximately $11 million Greensboro facility, which
is capable of processing 6,000 barrels of transmix per day for
Plantation and other interested parties. In the three and nine months
ended September 30, 2006, the Greensboro facility accounted for
incremental earnings before depreciation, depletion and amortization
of $1.3 million and $1.5 million, respectively. The increase from
contract settlements consisted of two separate settlements in the
second quarter of 2006. First, we recorded income of $6.2 million from
fees received for the early termination of a long-term transmix
processing agreement at our Colton, California processing facility.
Secondly, we recorded an expense of $0.5 million related to payments
we made to Motiva Enterprises LLC in June 2006 to settle claims for
prior period transmix purchase costs at our Richmond, Virginia
processing facility;
o an increase of $1.1 million (15%) and a decrease of $0.2 million (1%),
respectively, from our Central Florida Pipeline--the quarterly
increase was driven by higher operating revenues, due to higher
average tariff rates, and the nine month decrease resulted from higher
operating expenses, which included $0.4 million of pipeline integrity
expenses and which more than offset a year-over-year increase in
revenues;
o a decrease of $1.8 million (9%) and an increase of $1.3 million (2%),
respectively, from the combined operations of our West Coast and
Southeast refined products terminal operations--the quarterly decrease
included a $1.6 million (17%) drop in earnings before depreciation,
depletion and amortization from our West Coast terminals, due
primarily to incremental environmental expenses in the third quarter
of 2006. The nine month increase in earnings was driven by higher
earnings from our Southeast terminals, due to higher 2006 throughput
volumes at higher rates, relative to 2005;
o decreases of $3.4 million (43%) and $6.9 million (24%), respectively,
from our approximate 51% ownership interest in Plantation Pipe Line
Company--primarily due to lower equity earnings from Plantation, net
of income taxes. The overall quarterly decrease in earnings before
depreciation, depletion and amortization was primarily due to a $3.2
million decrease, representing our proportionate share of Plantation's
pipeline integrity expenses, net of income taxes that were recognized
in the third quarter of 2006. The decrease across the comparable nine
month periods includes the $3.2 million decrease due to pipeline
integrity expenses and a $3.5 million decrease, representing our
proportionate share of additional environmental expense recognized by
Plantation Pipe Line Company in the second quarter of 2006. The
expense was related to environmental
64
and clean-up liability adjustments associated with an April 17, 2006
pipeline release of turbine fuel from Plantation's 12-inch petroleum
products pipeline located in Henrico County, Virginia;
o decreases of $5.1 million (127%) and $5.4 million (34%), respectively,
from our 49.8% ownership interest in the Cochin pipeline system--due
mainly to incremental pipeline integrity expenses of $5.4 million
recognized in the third quarter of 2006; and
o decreases of $7.8 million (9%) and $16.1 million (7%), respectively,
from our combined Pacific and CALNEV Pipeline operations--the
quarterly decrease was largely due to higher pipeline maintenance
expenses, resulting from incremental pipeline integrity expenses of
$7.5 million in the third quarter of 2006, and the nine month decrease
was primarily due to higher environmental expenses associated with
environmental liability adjustments, the expensing of pipeline
integrity expenses in the third quarter of 2006, and higher
year-over-year fuel and power costs as a result of higher electricity
usage and higher utility rates.
Segment Details
Revenues for the segment increased $25.8 million (14%) in the third quarter
of 2006, compared to the third quarter of 2005. For the comparable nine month
periods, revenues increased $49.5 million (9%) in 2006 versus 2005. The
period-to-period increases in segment revenues for the comparable three and nine
month periods of 2006 and 2005, respectively, were principally due to the
following:
o increases of $12.2 million (80%) and $21.4 million (50%),
respectively, from our Southeast terminals--largely attributable to
higher ethanol blending and sales revenues and higher liquids
inventory sales (offset by higher costs of sales, as described below);
o increases of $5.3 million (6%) and $10.5 million (4%), respectively,
from our Pacific operations--the quarter-to-quarter increase consisted
of a $3.3 million (5%) increase in refined products delivery revenues
and a $2.0 million (9%) increase in refined products terminal revenues
in the third quarter of 2006, compared to the third quarter of 2005.
The increase from refined products delivery revenues was due to a 3%
increase in mainline delivery volumes and an almost 2% increase in
mainline average tariff rates, reflecting the impact of both rate
reductions that went into effect on May 1, 2006 according to
settlements reached in connection with our Pacific operations' rate
litigation, and rate increases that went into effect July 1, 2006
according to the FERC annual index rate increase (a producer price
index-finished goods adjustment).
For the comparable nine month periods, the overall increase in
revenues consisted of a $5.8 million (3%) increase from mainline
delivery revenues and a $4.7 million (7%) increase in product terminal
revenues. The increase from product delivery revenues was due to a 2%
increase in mainline delivery volumes and a slight (almost 1%)
increase in mainline average tariff rates. The increase from terminal
revenues was due to the higher transportation barrels and to
incremental service revenues, including diesel lubricity-improving
injection services that we began offering in May 2005;
o increases of $2.3 million (29%) and $3.5 million (13%), respectively,
from our North System--due to higher natural gas liquids delivery
revenues in 2006 versus 2005. The period-to-period increases in
delivery revenues were driven by increases of 18% and 6%,
respectively, in system throughput volumes, due largely to additional
refinery demand, and by increases of 10% and 7%, respectively, in
average tariff rates. The tariff increases resulted from a combination
of annual indexed tariff increases approved by the FERC (effective
July 1, 2005 and 2006), and from increases in the proportion of
volumes shipped at higher versus lower tariffs;
o increases of $2.2 million (15%) and $5.7 million (13%), respectively,
from our West Coast terminals--related to rent escalations, higher
throughput barrels and rates at various locations, and additional tank
capacity at our Carson/Los Angeles Harbor system terminals;
o increases of $1.6 million (10%) and $4.9 million (11%), respectively,
from our CALNEV Pipeline--due mainly to higher refined products
deliveries, higher terminal revenues as a result of additional
transportation barrels delivered at our Barstow, California and Las
Vegas, Nevada terminals, and higher diesel lubricity
65
additive injection service revenues. Revenues from refined products
deliveries increased $1.3 million (11%) and $4.0 million (12%),
respectively, in the three and nine months ended September 30, 2006,
when compared to the same periods last year. The quarter-to-quarter
increase from refined products deliveries was due to a 3% increase in
delivery volumes and a 7% increase in average tariff rates (including
a FERC tariff index increase in July 2006). The nine month increase
was due to a 6% increase in delivery volumes and a 5% increase in
average tariff rates (including FERC annual index rate increases
effective July 1, 2005 and July 1, 2006); and
o increases of $0.9 million (9%) and $2.6 million (9%), respectively,
from our Central Florida Pipeline--driven by increases of 13% and 10%,
respectively, in average tariff rates for the three and nine month
periods of 2006 compared to 2005. The increased rates reflect
reductions in zone-based credits in 2006 versus 2005.
Combining all of the segment's operations, total delivery volumes of
refined petroleum products increased a slight 0.4% in the third quarter of 2006,
compared to the third quarter of 2005, but transport volumes increased by 10.5%
in the Arizona market during the third quarter of 2006, as our Pacific
operations' East Line expansion was in service for the entire quarter. The
expansion project substantially increased pipeline capacity from El Paso, Texas
to Tucson and Phoenix, Arizona. Excluding volumes delivered by Plantation Pipe
Line, combined deliveries of refined petroleum products were up 2% for the third
quarter of 2006 compared to the third quarter of 2005. In the third quarter of
2006, Plantation realized a 3.9% decrease in delivery volumes compared to the
third quarter of 2005, primarily due to alternative pipeline service into
Southeast markets and to changes in supply from Louisiana and Mississippi
refineries related to new ultra low sulfur diesel and ethanol blended gasoline
requirements. Compared to the third quarter of 2005, total deliveries of natural
gas liquids increased almost 11% in the third quarter of 2006.
The segment's combined operating expenses, which consist of all cost of
sales expenses, operating and maintenance expenses, fuel and power expenses, and
all tax expenses, excluding income taxes, increased $34.0 million (56%) and
$64.4 million (38%), respectively, in the third quarter and first nine months of
2006, compared to the same year-ago periods. The overall increases in operating
expenses for the comparable three and nine month periods were mainly due to the
following:
o increases of $12.4 million (228%) and $18.5 million (105%),
respectively, from our Southeast terminals--largely attributable to
higher costs of sales related to higher ethanol blending and purchases
(offset by higher ethanol revenues) and higher liquids purchases;
o increases of $10.4 million (51%) and $23.9 million (38%),
respectively, from our Pacific operations--due primarily to higher
overall major maintenance expenses, including $5.8 million of pipeline
integrity expenses in the third quarter of 2006, lower capitalized
expenses primarily due to the September 2006 reclassification of
pipeline integrity management costs from capital to expense, and to
higher period-to-period fuel and power expenses, due to both higher
refined products delivery volumes and overall higher utility rates.
The nine month increase was also due to higher environmental expenses
in 2006 versus 2005, due to environmental liability adjustments, and
higher electricity expenses resulting from a utility rebate credit
received in the first quarter of 2005;
o increases of $5.2 million (140%) and $4.9 million (42%), respectively,
from our proportionate interest in the Cochin Pipeline--due
principally to an incremental $5.4 million of pipeline integrity
expenses in the third quarter of 2006. The incremental pipeline
integrity expenses were partly offset by lower pipeline operating
expenses, in the first nine months of 2006, related to the decrease in
transportation volumes in 2006 compared to 2005. The decrease in
delivery volumes was primarily due to pipeline operating pressure
restrictions;
o increases of $4.9 million (93%) and $8.1 million (55%), respectively,
from our West Coast terminals--primarily related to incremental
environmental expenses, higher materials and supplies expense as a
result of lower capitalized overhead, and incremental pipeline
integrity expenses;
o increases of $4.0 million (114%) and $7.7 million (71%), respectively,
from our CALNEV Pipeline--due primarily to higher period-to-period
environmental expense accruals, higher overall major maintenance
expenses, including $1.7 million of pipeline integrity expenses in the
third quarter of 2006, and to higher power expenses, related to
increases in product delivery volumes and average utility rates;
66
o a decrease of $0.1 million (4%) and an increase of $2.9 million (42%),
respectively, from our Central Florida Pipeline operations--the slight
quarterly decrease reflects incremental pipeline integrity expenses of
$0.4 million in 2006, offset by lower maintenance expenses due to
additional expense accruals related to a pipeline release occurring in
September 2005. The nine month increase was chiefly due to incremental
environmental expenses, in 2006, resulting from quarterly
environmental liability adjustments; and
o decreases of $3.6 million (37%) and $3.4 million (17%), respectively,
from our North System--due primarily to the $5.0 million inventory
reconciliation reserve taken in the third quarter of 2005, as
discussed above, partly offset by both incremental pipeline integrity
expenses of $1.0 million in the third quarter of 2006, and higher
property tax expenses related to an expense true-up recognized in the
third quarter of 2006.
The segment's equity investments consist of our approximate 51% interest in
Plantation Pipe Line Company, our 50% interest in the Heartland Pipeline
Company, and our 50% interest in Johnston County Terminal, LLC. Earnings from
these investments decreased $5.7 million (92%) in the third quarter of 2006 and
$10.6 million (49%) in the first nine months of 2006, when compared to the same
periods last year. Both decreases primarily related to the lower earnings from
Plantation, as described above.
Income from both allocable interest income and other income and expense
items increased $0.9 million (52%) and $6.7 million (151%), respectively, in the
comparable three and nine month periods. The quarterly increase was due to
higher administrative overhead collected by our West Coast terminals from a
reimbursable project, and the nine month increase was primarily due to the $5.7
million other income item from the settlement of transmix processing contracts
in the second quarter of 2006.
For the comparable three and nine month periods, the segment's income tax
expenses decreased $2.8 million (127%) and $4.9 million (60%), respectively.
Both decreases related to the lower pre-tax earnings from Plantation and Cochin,
as described above.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of equity investments, increased $1.0 million (5%)
in the third quarter of 2006 and $2.5 million (4%) in the first nine months of
2006, when compared to the same prior year periods. The period-to-period
increases were primarily due to higher depreciation expenses from our Pacific
and Southeast terminal operations. The increase from our Pacific operations
related to higher depreciable costs as a result of the capital spending we have
made for both pipeline and storage expansion since the end of the third quarter
of 2005. The increase from our Southeast terminal operations related to
incremental depreciation charges resulting from final purchase price
allocations, made in the fourth quarter of 2005, for depreciable terminal assets
we acquired in November 2004 from Charter Terminal Company and Charter-Triad
Terminals, LLC.
Natural Gas Pipelines
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- ----------------------------
2006 2005 2006 2005
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 1,650,427 $ 2,108,788 $ 5,082,183 $ 5,198,337
Operating expenses and Other expense(a).................... (1,519,129) (1,996,737) (4,678,855) (4,863,524)
Earnings from equity investments........................... 10,062 8,705 31,833 25,733
Interest income and Other, net-income (expense)............ 376 1,560 875 2,039
Income taxes............................................... (973) (361) (900) (1,899)
----------- ----------- ----------- -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity 140,763 121,955 435,136 360,686
investments................................................
Depreciation, depletion and amortization expense........... (15,959) (15,205) (47,938) (45,779)
Amortization of excess cost of equity investments.......... (71) (70) (210) (208)
----------- ----------- ----------- -----------
Segment earnings......................................... $ 124,733 $ 106,680 $ 386,988 $ 314,699
=========== =========== =========== ===========
Natural gas transport volumes (Trillion Btus)(b)........... 384.9 353.1 1,067.4 998.1
=========== =========== =========== ===========
Natural gas sales volumes (Trillion Btus)(c)............... 243.5 239.3 690.0 688.6
=========== =========== =========== ===========
- ---------
67
(a) Nine month 2006 amount includes a $1,500 increase in expense associated
with environmental liability adjustments, a $6,244 reduction in expense due
to the release of a reserve related to a natural gas pipeline contract
obligation, and a $15,114 gain from the combined sale of our Douglas
natural gas gathering system and Painter Unit fractionation facility.
(b) Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate
natural gas pipeline group, Trailblazer and TransColorado pipeline volumes.
(c) Represents Texas intrastate natural gas pipeline group.
Our Natural Gas Pipelines business segment reported earnings before
depreciation, depletion and amortization of $140.8 million on revenues of
$1,650.4 million in the third quarter of 2006. This compares to earnings before
depreciation, depletion and amortization of $122.0 million on revenues of
$2,108.8 million in the third quarter of 2005. For the comparable nine month
periods, the segment reported earnings before depreciation, depletion and
amortization of $435.1 million on revenues of $5,082.2 million in 2006, and
earnings before depreciation, depletion and amortization of $360.7 million on
revenues of $5,198.3 million in 2005.
As noted in the table above, the segment's earnings before depreciation,
depletion and amortization expenses for the first nine months of 2006 included
an increase in expense of $1.5 million from the adjustment of environmental
liabilities, a reduction in expense of $6.2 million due to the release of a
reserve related to a natural gas purchase/sales contract, and a gain of $15.1
million from the combined sale of our Douglas natural gas gathering system and
Painter Unit fractionation facility. All three items occurred in the second
quarter of 2006.
Segment Earnings before Depreciation, Depletion and Amortization
The segment's $18.8 million (15%) increase in earnings before depreciation,
depletion and amortization expenses in the third quarter of 2006 compared with
the third quarter of 2005, and its $74.4 million (21%) increase in earnings in
the first nine months of 2006 compared with the first nine months of 2005 were
primarily due to the following:
o increases of $9.9 million (44%) and $6.9 million (9%), respectively,
from our Kinder Morgan Interstate Gas Transmission system--due largely
to higher operational sales of natural gas and incremental natural gas
park and loan service revenues earned in the third quarter of 2006.
The year-over-year increase in earnings in 2006 relative to 2005 was
partially offset by favorable imbalance valuation adjustments
recognized in the second quarter of 2005;
o increases of $6.3 million (9%) and $41.5 million (23%), respectively,
from our Texas intrastate natural gas pipeline group--due primarily to
improved margins resulting from the negotiation of profitable gas
purchase and sales contracts, and higher value from storage and
processing activities. With regard to our natural gas sales
activities, margin is defined as the difference between the prices at
which we buy gas in our supply areas and the prices at which we sell
gas in our market areas, less the cost of fuel to transport. Our Texas
intrastate group's margins can vary depending upon, among other
things, the price volatility of natural gas produced in and delivered
from the Gulf Coast region and Texas, the availability of
transportation systems with adequate capacity, the availability of
pipeline and/or underground system storage, and any changes or trends
in the terms or conditions in which natural gas sale and purchase
prices are contractually indexed.
The increase in earnings in the first nine months of 2006 versus the
first nine months of 2005 includes the $6.2 million increase resulting
from the release of a previously established reserve related to a
natural gas purchase/sales contract. The contract is associated with
the operations of our West Clear Lake natural gas storage facility
located in Harris County, Texas. We acquired this storage facility as
part of our acquisition of Kinder Morgan Tejas on January 31, 2002,
and upon acquisition, we established a reserve for a contract
liability;
o an increase of $2.0 million (18%) and a decrease of $0.4 million (1%),
respectively, from our Trailblazer Pipeline--due to timing differences
on the settlements of pipeline transportation imbalances in 2006,
relative to 2005. These pipeline imbalances were due to differences
between the volumes nominated and volumes delivered at an
inter-connecting point by the pipeline;
68
o increases of $1.3 million (18%) and $6.2 million (28%), respectively,
from our 49% equity investment in Red Cedar Gathering Company--due
largely to higher natural gas gathering revenues and to higher prices
on incremental sales of excess fuel gas;
o increases of $0.2 million (2%) and $3.9 million (14%), respectively,
from our TransColorado Pipeline--the quarter-to-quarter increase was
largely due to a favorable property tax liability adjustment
recognized in the third quarter of 2006, and the nine month increase
was largely due to higher gas transmission revenues earned in 2006
compared to 2005. The revenue increase related to higher natural gas
delivery volumes resulting from system improvements associated with an
expansion, completed since the end of the first quarter of 2005, on
the northern portion of the pipeline. TransColorado's north system
expansion project was in-service on January 1, 2006, and provides for
up to 300 million cubic feet per day of additional northbound
transportation capacity; and
o a decrease of $0.9 million (34%) and an increase of $16.5 million
(196%), respectively, from the combined operations of our Casper
Douglas and Painter natural gas gathering and processing operations.
The quarter-to-quarter decrease was primarily due to decreased
revenues in 2006 compared to 2005, mainly due to lower natural gas
sales and partly due to the sale of our Douglas natural gas gathering
system and our Painter Unit fractionation facility in April 2006.
Effective April 1, 2006, we sold our Douglas natural gas gathering
system and our Painter Unit fractionation facility to a third party
for approximately $42.5 million in cash, and we included a net gain of
$15.1 million within "Other expense (income)" in our accompanying
consolidated statements of income for the three and nine months ended
September 30, 2006. For more information on this gain, see Note 2 to
our consolidated financial statements included elsewhere in this
report.
The nine month increase in earnings in 2006 versus 2005 was mainly due
to the $15.1 million gain discussed above, a $3.2 million increase in
revenues due mainly to increased natural gas sales, favorable gas
imbalance gains and higher commodity prices, and a $1.5 million
decrease related to incremental environmental expenses in the second
quarter of 2006.
Segment Details
Compared to the same two periods in 2005, total segment operating revenues,
including revenues from natural gas sales, decreased $458.4 million (22%) in the
third quarter of 2006, and decreased $116.1 million (2%) in the first nine
months of 2006. Similarly, combined operating expenses, including natural gas
purchase costs, decreased $477.6 million (24%) in the third quarter of 2006, and
decreased $184.7 million (4%) in the first nine months of 2006, when compared to
the same periods of 2005.
The period-to-period changes in segment revenues and operating
expenses reflect changes in average natural gas prices and changes in natural
gas volumes purchased and sold, which affect both natural gas sales revenues and
natural gas purchase expenses; however, we increased earnings by realizing
higher margins from our Texas intrastate natural gas pipeline group's purchasing
and sales activities, and from its natural gas storage and processing
activities. For the comparable three and nine month periods, the Texas
intrastate groups' natural gas sales margin increased $7.4 million (20%) and
$47.4 million (53%), respectively, in 2006 versus 2005. The variations in
natural gas sales margin for both the three and nine months ended September 30,
2006, compared with the same periods last year, were driven by changes in
natural gas prices and sales volumes--the $7.4 million quarterly margin increase
consisted of a $10.5 million increase from favorable changes in average sales
versus average purchase prices (favorable price variance) and a $3.1 million
decrease from lower volumes (unfavorable volume variance)--the $47.4 million
nine month margin increase consisted of a $50.8 million increase from favorable
changes in average sales prices versus average purchase prices and a $3.4
million decrease from lower volumes. Also, the intrastate groups' margins from
natural gas processing activities increased $6.2 million (111%) and $8.4 million
(47%), respectively, in the comparable three and nine month periods of 2006
versus 2005.
We account for the segment's investments in Red Cedar Gathering Company,
Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC under the equity
method of accounting. Combined earnings from these three investees increased
$1.4 million (16%) and $6.1 million (24%), respectively, in the third quarter
and first nine months of 2006, when compared to the same periods last year. The
increases were chiefly due to higher net income earned by Red Cedar during 2006,
as described above.
69
On September 1, 2006, we and the Southern Ute Indian Tribe agreed to a
resolution that would transfer all of the members' equity in Coyote Gas
Treating, LLC to the members' equity of Red Cedar Gathering Company. According
to the provisions of this resolution, we and the Southern Ute Tribe contributed
the value of our respective 50% ownership interests in Coyote Gas Treating, LLC
to Red Cedar, and as a result, Coyote Gas Treating, LLC became a wholly owned
subsidiary of Red Cedar. For more information on this contribution, see Note 13
to our consolidated financial statements included elsewhere in this report.
The segment's combined interest income and earnings from other income items
(Other, net) decreased $1.2 million in both the three and nine month periods of
2006, when compared to the same prior year periods. The decrease was chiefly due
to a gain from a property disposal by our Kinder Morgan Tejas Pipeline in the
third quarter of 2005. Income tax expenses increased $0.6 million in the third
quarter of 2006, but decreased $1.0 million in the first nine months of 2006,
when compared to the same periods in 2005. The changes primarily related to tax
accrual adjustments related to the operations of our Mier-Monterrey Mexico
Pipeline.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased a slight $0.8 million (5%)
in the third quarter of 2006 versus the third quarter of 2005; for the nine
month periods, depreciation related expenses increased $2.2 million (5%) in 2006
versus 2005. The increases were largely due to incremental capital spending
since last year's third quarter, and to additional depreciation charges on our
Kinder Morgan Texas system due to the acquisition of our North Dayton, Texas
natural gas storage facility in August 2005.
CO2
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- -------------------
2006 2005 2006 2005
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues(a)....................................................... $ 192,303 $ 163,079 $ 552,783 $ 488,271
Operating expenses................................................ (68,888) (48,546) (194,212) (152,389)
Earnings from equity investments.................................. 3,380 5,533 14,113 21,932
Other, net-income (expense)....................................... 324 (6) 336 (6)
Income taxes...................................................... (57) (151) (181) (263)
--------- --------- --------- ---------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments... 127,062 119,909 372,839 357,545
Depreciation, depletion and amortization expense(b)............... (50,731) (34,658) (132,021) (111,822)
Amortization of excess cost of equity investments................. (504) (505) (1,513) (1,513)
--------- --------- --------- ---------
Segment earnings................................................ $ 75,827 $ 84,746 $ 239,305 $ 244,210
========= ========= ========= =========
Carbon dioxide delivery volumes (Bcf)(c).......................... 164.3 153.6 503.4 479.0
========= ========= ========= =========
SACROC oil production (gross) (MBbl/d)(d)......................... 30.3 30.8 30.8 32.4
========= ========= ========= =========
SACROC oil production (net) (MBbl/d)(e)........................... 25.3 25.6 25.7 26.9
========= ========= ========= =========
Yates oil production (gross) (MBbl/d)(d).......................... 26.3 24.1 25.9 24.0
========= ========= ========= =========
Yates oil production (net) (MBbl/d)(e)............................ 11.7 10.7 11.5 10.7
========= ========= ========= =========
Natural gas liquids sales volumes (net) (MBbl/d)(e)............... 8.4 9.4 8.9 9.5
========= ========= ========= =========
Realized weighted average oil price per Bbl(f)(g)................. $ 32.49 $ 26.12 $ 31.42 $ 27.46
========= ========= ========= =========
Realized weighted average natural gas liquids
price per Bbl(g)(h)............................................. $ 47.68 $ 41.89 $ 44.82 $ 37.09
========= ========= ========= =========
- ----------
(a) Nine month 2006 amount includes a $1,819 loss on derivative contracts used
to hedge forecasted crude oil sales.
(b) Includes depreciation, depletion and amortization expense associated with
oil and gas producing and gas processing activities in the amount of
$45,704 for the third quarter of 2006, $30,336 for the third quarter of
2005, $117,628 for the first nine months of 2006, and $98,628 for the first
nine months of 2005. Includes depreciation, depletion and amortization
expense associated with sales and transportation services activities in the
amount of $5,027 for the third quarter of 2006, $4,322 for the third
quarter of 2005, $14,393 for the first nine months of 2006, and $13,194 for
the first nine months of 2005.
(c) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos
pipeline volumes.
(d) Represents 100% of the production from the field. We own an approximate 97%
working interest in the SACROC unit and an approximate 50% working interest
in the Yates unit.
(e) Net to Kinder Morgan, after royalties and outside working interests.
70
(f) Includes all Kinder Morgan crude oil production properties.
(g) Hedge gains/losses for crude oil and natural gas liquids are included with
crude oil.
(h) Includes production attributable to leasehold ownership and production
attributable to our ownership in processing plants and third party
processing agreements.
Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates. The segment's primary businesses involve the
production, marketing and transportation of both carbon dioxide (commonly called
CO2) and crude oil, and the production and marketing of natural gas and natural
gas liquids. For the third quarter of 2006, the segment reported earnings before
depreciation, depletion and amortization of $127.1 million on revenues of $192.3
million. These amounts compare to earnings before depreciation, depletion and
amortization of $119.9 million on revenues of $163.1 million in the same quarter
last year. For the comparable nine month periods, the segment reported earnings
before depreciation, depletion and amortization of $372.8 million on revenues of
$552.8 million in 2006, and earnings before depreciation, depletion and
amortization of $357.5 million on revenues of $488.3 million in 2005.
Segment Earnings before Depreciation, Depletion and Amortization
Sales and Transportation Activities
For our CO2 segment, both the $7.2 million (6%) increase in earnings before
depreciation, depletion and amortization in the third quarter of 2006 over the
third quarter of 2005, and the $15.3 million (4%) increase in the first nine
months of 2006 over the first nine months of 2005 were driven by higher earnings
from the segment's carbon dioxide sales and transportation activities. Earnings
before depreciation, depletion and amortization from these activities increased
$7.6 million (18%) and $20.6 million (17%), respectively, in the third quarter
and first nine months of 2006, when compared to the same prior year periods. The
increases in earnings were driven by higher revenues--from both carbon dioxide
sales and deliveries, and from crude oil pipeline transportation. The overall
increases were partly offset by lower equity earnings from the segment's 50%
ownership interest in the Cortez Pipeline Company.
The period-to-period increases in carbon dioxide sales revenues were due to
both higher average prices and higher sales volumes. The increases in volumes
were largely attributable to the continued strong demand for carbon dioxide from
tertiary oil recovery projects in the Permian Basin area since the end of the
third quarter last year, and to increased carbon dioxide production from the
McElmo Dome source field. We operate and own a 45% interest in McElmo Dome,
which supplies carbon dioxide to oil recovery fields in the Permian Basin of
southeastern New Mexico and West Texas. It is the largest known carbon dioxide
deposit in the world--covering approximately 203,000 acres from south of McElmo
Canyon into Delores County, Colorado.
Correlating closely with the increase in crude oil prices since the end of
the third quarter of 2005, average carbon dioxide sales prices increased 19% and
26%, respectively, for the three and nine month periods of 2006, when compared
to the same periods a year ago. In addition, during both nine month periods, we
did not use derivative contracts to hedge or help manage the financial impacts
associated with the increases in carbon dioxide prices, and as always, we did
not recognize profits on carbon dioxide sales to ourselves.
Oil and Gas Producing Activities
The remaining changes in period-to-period segment earnings before
depreciation, depletion and amortization--a decrease of $0.4 million (1%) in the
comparable three month periods and a decrease of $5.3 million (2%) in the
comparable nine month periods, were attributable to the segment's crude oil and
natural gas producing activities, which also include its natural gas processing
activities. The decreases in period-to-period earnings were largely due to
higher combined operating expenses and partly due to lower crude oil production
at the SACROC oil field unit. The higher operating expenses included higher
field operating and maintenance expenses, higher property and severance taxes,
and higher fuel and power expenses. The increases in expenses more than offset
higher overall crude oil and natural gas plant product sales revenues.
71
In addition, increased crude oil production at the Yates oil field unit was
offset by a previously announced decline in crude oil production at the SACROC
unit. On a gross basis (meaning total quantity produced), average crude oil
production increased 9% quarter-over-quarter at Yates, but decreased 2% at the
SACROC unit, where the decline in production is mostly due to one section of the
field that is underperforming. As originally disclosed in our report on Form
10-Q filed for the quarter ended March 31, 2006, we now expect our CO2 segment
to fall short of its annual published budget of segment earnings before
depreciation, depletion and amortization expenses by approximately $45 million,
or 8%. However, we continue to expect strong annual carbon dioxide production
volumes and earnings at the McElmo Dome unit in 2006, and we expect the crude
oil production and earnings from the Yates field unit to exceed their annual
budgeted amounts.
Segment Details
Our CO2 segment's revenues increased $29.2 million (18%) in the third
quarter of 2006 compared to the third quarter of 2005, and including a $1.8
million hedge ineffectiveness loss in June 2006, revenues increased $64.5
million (13%) in the first nine months of 2006 versus 2005. The respective third
quarter and nine month increases were primarily due to the following:
o increases of $24.0 million (27%) and $39.2 million (14%),
respectively, from crude oil sales--attributable to increases of 24%
and 14%, respectively, in our realized weighted average price of crude
oil and a 2% increase in quarter-to-quarter sales volumes. For the
comparable nine month periods, crude oil sales volumes were
essentially flat;
o increases of $3.9 million (26%) and $14.3 million (41%), respectively,
from carbon dioxide sales--due mainly to higher average sales prices,
discussed above, and to increases of 12% and 8%, respectively, in
period-to-period sales volumes;
o increases of $2.9 million (19%) and $7.2 million (17%), respectively,
from carbon dioxide and crude oil pipeline transportation
revenues--due largely to increases of 7% and 5%, respectively, in
system-wide carbon dioxide delivery volumes. The improvements in
carbon dioxide throughput volumes were driven by higher contract
demand, and the higher crude oil pipeline transportation revenues
reflect higher crude oil throughputs from our Kinder Morgan Wink
Pipeline;
o increases of $0.5 million (2%) and $12.8 million (13%), respectively,
from natural gas liquids sales--attributable to higher average sales
prices, partially offset by decreases in volumes primarily related to
the lower production at SACROC; and
o decreases of $0.9 million (70%) and $9.1 million (73%), respectively,
from natural gas sales--mainly attributable to lower volumes of gas
available for sale in the third quarter and first nine months of 2006
versus the same periods last year, due to natural gas volumes used at
the power plant we constructed at the SACROC oil field unit and placed
in service in June 2005. We constructed the SACROC power plant in
order to reduce our purchases of electricity from third-parties, but
it reduces our sales of natural gas because some natural gas volumes
are consumed by the plant. The power plant now provides approximately
half of SACROC's current electricity needs. KMI operates and maintains
the power plant under a five-year contract expiring in June 2010, and
we reimburse KMI for its operating and maintenance costs.
We mitigate commodity price risk through a long-term hedging strategy
that uses derivative contracts to reduce the impact of unpredictable changes in
crude oil and natural gas liquids sales prices. Our goal is to use derivative
contracts in order to prevent or reduce the possibility of future losses, and
our strategy is intended to generate more stable realized prices. Had we not
used energy derivative contracts to transfer commodity price risk, our crude oil
sales prices would have averaged $68.20 per barrel in the third quarter of 2006,
and $61.17 per barrel in the third quarter of 2005. All of our hedge gains and
losses for crude oil and natural gas liquids are included in our realized
average price for oil; none are allocated to natural gas liquids. For more
information on our hedging activities, see Note 10 to our consolidated financial
statements included elsewhere in this report.
72
Compared to the same periods of 2005, the segment's operating expenses
increased $20.3 million (42%) in the third quarter of 2006 and $41.8 million
(27%) in the first nine months of 2006. The increases consisted of the
following:
o increases of $12.3 million (58%) and $25.0 million (36%),
respectively, from combined cost of sales and field operating and
maintenance expenses-- largely due to higher well workover and
completion expenses related to infrastructure expansions at the SACROC
and Yates oil field units since the third quarter last year. Workover
expenses, including labor, relate to incremental operating and
maintenance charges incurred on producing wells in order to restore or
increase production, and are often performed in order to stimulate
production, add pumping equipment, remove fill from the wellbore, or
mechanically repair the well.
Our oil and gas operations, coupled with carbon dioxide flooding,
often require a high level of investment, including ongoing expenses
for facility upgrades, wellwork and drilling. We continue to
aggressively pursue opportunities to drill new wells and/or expand
existing wells for both carbon dioxide and crude oil in order to
benefit from robust demand for energy commodities in and around the
Permian Basin area;
o increases of $6.6 million (40%) and $9.6 million (18%), respectively,
from fuel and power expenses-- due to increased carbon dioxide
compression and equipment utilization, higher fuel costs, and higher
electricity expenses due to higher rates as a result of higher fuel
costs to electricity providers. Overall higher electricity costs were
partly offset, however, by the benefits provided from the power plant
we constructed at the SACROC oil field unit, described above; and
o increases of $1.4 million (13%) and $7.2 million (23%), respectively,
from taxes, other than income taxes--attributable mainly to higher
property and production (severance) taxes. The higher property taxes
related to both increased asset infrastructure and higher assessed
property values since the end of the third quarter of 2005. The higher
severance taxes, which are primarily based on the gross wellhead
production value of crude oil and natural gas, were driven by the
higher period-to-period crude oil revenues.
Earnings from equity investments, representing equity earnings from our 50%
ownership interest in the Cortez Pipeline Company, decreased $2.2 million (39%)
and $7.8 million (36%), respectively, in the third quarter and first nine months
of 2006, versus the same periods in 2005. The decreases reflect lower overall
net income earned by Cortez in 2006 relative to 2005. The decreases were
expected because the 2005 periods benefited from higher tariffs, due to making
up under-collected revenues in prior years. The decrease in revenues from lower
tariffs more than offset incremental revenues realized as a result of higher
carbon dioxide delivery volumes.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased $16.1 million (46%) in
the third quarter and $20.2 million (18%) in first nine months of 2006, when
compared to the same prior year periods. The increases were largely due to a
higher unit-of-production depletion rate used in third quarter of 2006,
related to our interest in the SACROC oil field unit, and to higher
depreciable costs, related to incremental capital spending since the end of
the third quarter last year. In addition, we recognized incremental
depreciation charges of $0.8 million and $2.2 million, respectively,
attributable to the various oil and gas properties we acquired in April 2006
from Journey Acquisition - I, L.P. and Journey 2000, L.P.
73
Terminals
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2006 2005 2006 2005
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 223,151 $ 177,484 $ 649,822 $ 515,115
Operating expenses......................................... (122,230) (94,318) (354,892) (271,470)
Earnings from equity investments........................... 76 18 190 51
Other, net-income (expense)................................ 1,056 886 2,335 (293)
Income taxes............................................... (3,599) (2,372) (7,451) (9,874)
---------- --------- --------- ---------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity 98,454 81,698 290,004 233,529
investments................................................
Depreciation, depletion and amortization expense........... (19,320) (15,644) (55,280) (41,972)
Amortization of excess cost of equity investments.......... - - - -
---------- --------- --------- ---------
Segment earnings......................................... $ 79,134 $ 66,054 $ 234,724 $ 191,557
========== ========= ========= =========
Bulk transload tonnage (MMtons)(a)......................... 23.2 20.4 67.9 65.8
========== ========= ========= =========
Liquids leaseable capacity (MMBbl)......................... 43.5 40.3 43.5 40.3
========== ========= ========= =========
Liquids utilization %...................................... 97.8% 96.5% 97.8% 96.5%
========== ========= ========= =========
- ----------
(a) Volumes for acquired terminals are included for all periods.
Our Terminals segment includes the operations of our petroleum and
petrochemical-related liquids terminal facilities (other than those included in
our Products Pipelines segment) as well as all of our coal and dry-bulk material
services, including all transload, engineering and other in-plant services. In
the third quarter of 2006, our Terminals segment reported earnings before
depreciation, depletion and amortization of $98.5 million on revenues of $223.2
million. This compares to earnings before depreciation, depletion and
amortization of $81.7 million on revenues of $177.5 million in the third quarter
last year. For the first nine months of 2006, our Terminals segment reported
earnings before depreciation, depletion and amortization of $290.0 million on
revenues of $649.8 million, while in the same prior-year period, the segment
reported earnings before depreciation, depletion and amortization of $233.5
million on revenues of $515.1 million.
Segment Earnings before Depreciation, Depletion and Amortization
The segment's $16.8 million (21%) increase in earnings before depreciation,
depletion and amortization expenses in the third quarter of 2006 compared with
the third quarter of 2005, and the $56.5 million (24%) increase in earnings in
the first nine months of 2006 compared with the first nine months of 2005 were
driven by a combination of internal expansions, incremental volumes, and
acquisitions.
Our terminal acquisitions since the beginning of 2005 primarily included
the following:
o our Texas Petcoke terminals, located in and around the Ports of
Houston and Beaumont, Texas, acquired effective April 29, 2005;
o three terminals acquired separately in July 2005: our Kinder Morgan
Staten Island terminal, a dry-bulk terminal located in Hawesville,
Kentucky and a liquids/dry-bulk facility located in Blytheville,
Arkansas;
o all of the ownership interests in General Stevedores, L.P., which
operates a break-bulk terminal facility located along the Houston Ship
Channel, acquired July 31, 2005;
o our Kinder Morgan Blackhawk terminal located in Black Hawk County,
Iowa, acquired in August 2005;
o a terminal-related repair shop located in Jefferson County, Texas,
acquired in September 2005; and
74
o three terminal operations acquired separately in April 2006: terminal
equipment and infrastructure located on the Houston Ship Channel, a
rail terminal located at the Port of Houston, and a rail ethanol
terminal located in Carson, California.
Combined, these terminal operations acquired since the beginning of 2005
accounted for incremental amounts of earnings before depreciation, depletion and
amortization of $4.0 million, revenues of $9.2 million and operating expenses of
$5.2 million, respectively, in the third quarter of 2006, and incremental
amounts of earnings before depreciation, depletion and amortization of $29.4
million, revenues of $58.8 million and operating expenses of $29.4 million,
respectively, in the first nine months of 2006, when compared to the same
periods a year ago. The incremental amounts above relate to the acquired
terminals' operations during the additional months of ownership in the third
quarter and first nine months of 2006, as compared to 2005, and do not include
increases or decreases during the same months we owned the assets in both years.
For the comparable three months, most of the period-to-period increases in
operating results from terminal acquisitions were attributable to the terminal
assets and operations we acquired from A&L Trucking, L.P. and U.S. Development
Group in April 2006 for an aggregate consideration of approximately $61.9
million. Combined, these assets accounted for incremental amounts of earnings
before depreciation, depletion and amortization of $3.8 million, revenues of
$8.7 million and operating expenses of $4.9 million, respectively, in the third
quarter of 2006.
For the comparable nine month periods, most of the period-to-period
increases in operating results from terminal acquisitions were attributable to
the inclusion of our Texas petroleum coke terminals and repair shop assets,
which we acquired from Trans-Global Solutions, Inc. on April 29, 2005 for an
aggregate consideration of approximately $247.2 million. The primary assets
acquired included facilities and railway equipment located at the Port of
Houston, the Port of Beaumont and the TGS Deepwater Terminal located on the
Houston Ship Channel. Combined, these assets accounted for incremental amounts
of earnings before depreciation, depletion and amortization of $16.8 million,
revenues of $31.0 million and operating expenses of $14.2 million, respectively,
during the first four months of 2006.
For all other terminal operations (those owned during identical periods in
both 2005 and 2006), earnings before depreciation, depletion and amortization
increased $12.8 million (16%) in the third quarter of 2006 versus the third
quarter of 2005, and increased $27.1 million (12%) in the first nine months of
2006 versus the first nine months of 2005. The respective third quarter and nine
month year-to-date increases in earnings from terminal operations owned during
both years were primarily due to the following:
o increases of $5.1 million (25%) and $9.6 million (17%), respectively,
from our Gulf Coast region. The increases were primarily due to higher
earnings from our Pasadena and Galena Park, Texas liquids facilities.
The period-to-period increases were driven by higher revenues from new
and incremental customer agreements, additional liquids tank capacity
from capital expansions at our Pasadena terminal since the third
quarter of 2005, higher truck loading rack service fees, and
incremental revenues from customer deficiency charges in the third
quarter of 2006;
o increases of $3.5 million (47%) and $7.9 million (32%), respectively,
from our Mid-Atlantic region. The quarterly increase was driven by a
$1.8 million increase from our Chesapeake Bay, Maryland bulk terminal
and a $1.4 million increase from our Shipyard River terminal, located
in Charleston, South Carolina. The increase at Chesapeake was due to
higher revenues earned from transferring higher volumes of petroleum
coke, coal, and pig iron; the increase at Shipyard was due to higher
revenues from increased coal volumes, tank rentals and ancillary
terminal services.
The nine month increase was driven by a $3.6 million increase from our
Shipyard River terminal, a $2.9 million increase from our Fairless
Hills, Pennsylvania bulk terminal, and a $1.3 million increase from
our Philadelphia, Pennsylvania liquids terminal. The increase from
Shipyard reflects higher revenues from liquids warehousing and coal
and cement handling, the increase at Fairless Hills was due to higher
volumes of steel imports and heavier shipping activity on the Delaware
River, and the increase at Philadelphia was due to higher revenues
from an increase in fuel grade ethanol volumes, and annual rate
escalations on certain customer contracts;
75
o increases of $2.0 million (49%) and $1.7 million (9%), respectively,
from terminals included in our Lower Mississippi (Louisiana) region.
The quarterly increase was primarily due to higher earnings from our
International Marine Terminals facility, a Louisiana partnership owned
66 2/3% by us. IMT, located in Port Sulphur, Louisiana, suffered
property damage and a general loss of business due to the effects of
Hurricane Katrina, which struck the Gulf Coast in the third quarter of
2005.
The nine month increase was primarily due to higher earnings from IMT
and our DeLisle, Mississippi terminal, both negatively impacted by
hurricane damage in 2005, incremental income related to a favorable
settlement associated with the purchase of our Kinder Morgan St.
Gabriel terminal in September 2002, and to incremental earnings from
our Amory, Mississippi bulk terminal, which began operations in July
2005;
o increases of $1.9 million (17%) and $2.1 million (6%), respectively,
from terminals included in our Northeast region. The increases were
primarily due to higher earnings from our liquids terminals located in
Carteret, New Jersey and Staten Island, New York. The quarterly
increase was largely due to higher revenues from new and renegotiated
customer contracts at Carteret, and to additional tankage and transmix
sales at our Kinder Morgan Staten Island terminal. The nine month
increase was due to the same factors that affected third quarter
results, and to an overall increase in petroleum imports to New York
Harbor, resulting in an 11% increase in total liquids throughput at
Carteret; and
o increases of $0.4 million (4%) and $3.9 million (26%), respectively,
from our Texas Petcoke region. The increases were due to higher
revenues from petroleum coke transfers, which more than offset higher
sales costs and operating expenses.
Segment Details
Segment revenues for all terminals owned during identical periods of both
years increased $36.5 million (21%) in the third quarter of 2006, and $75.9
million (15%) in the first nine months of 2006, when compared to the same
prior-year periods. The overall changes in three and nine month revenues from
terminals owned during identical periods of both years included the following:
o increases of $9.6 million (52%) and $19.9 million (32%), respectively,
from our Mid-Atlantic region, due primarily to higher revenues from
our Fairless Hills, Chesapeake Bay, and Shipyard River terminals, as
discussed above;
o increases of $6.5 million (24%) and $12.6 million (16%), respectively,
from our Gulf Coast liquids facilities, due primarily to higher
revenues from Pasadena and Galena Park, as discussed above;
o increases of $5.3 million (21%) and $5.8 million (7%), respectively,
from terminals included in our Lower Mississippi (Louisiana) region.
The increases were largely due to higher tonnage, dockage and
insurance revenues at our IMT facility, higher bulk transfer revenues
from our DeLisle and Amory, Mississippi terminals, and higher revenues
from ship and cargo brokerage;
o increases of $5.0 million (29%) and $15.4 million (57%), respectively,
from our Texas Petcoke terminal region, due to higher petroleum coke
transfer volumes;
o increases of $3.6 million (102%) and $10.3 million (101%),
respectively, from engineering and terminal design services, due to
both incremental revenues from new clients and from existing clients
starting new projects due to economic growth, and to increased
revenues from material sales;
o increases of $2.6 million (9%) and $3.8 million (4%), respectively,
from terminals included in our Midwest region, due largely to
increased liquids throughput and storage activities from our two
Chicago liquids terminals, increases of 34% and 10%, respectively, in
coal transfer volumes from the combined operations of our Cora,
Illinois and Grand Rivers, Kentucky coal terminals, and higher marine
oil fuel and asphalt sales from our Dravosburg, Pennsylvania bulk
terminal; and
76
o increases of $2.2 million (10%) and $2.8 million (4%), respectively,
from our Northeast terminals, largely to increases at our Carteret and
Kinder Morgan Staten Island terminals, as discussed above.
Operating expenses for all terminals owned during both periods increased
$22.7 million (24%) in the third quarter of 2006, and $54.0 million (20%) in the
first nine months of 2006, when compared to the same periods last year. The
respective third quarter and nine month year-to-date increases in operating
expenses from terminal operations owned during identical periods of both years
were primarily due to the following:
o increases of $6.1 million (55%) and $11.3 million (30%), respectively,
from our Mid-Atlantic terminals, largely due to higher operating and
maintenance expenses at our Fairless Hills, Shipyard River, and Pier
IX terminals. The increases at Fairless Hills were largely due to
higher wharfage, trucking and general maintenance expenses related to
the increase in steel products handled, the increases at Shipyard were
due to higher labor, equipment rentals, and general maintenance
expenses, all associated with increased tonnage, and the increases at
Pier IX, located in Newport News, Virginia, related to major
maintenance repairs and to higher expenses related to a fire that
occurred at the terminal in June 2006;
o increases of $4.8 million (61%) and $11.7 million (99%), respectively,
from our Texas Petcoke terminal region, due largely to higher labor
expenses, rail service and railcar maintenance expenses, and harbor
and barge expenses, all related to higher petroleum coke volumes;
o increases of $4.4 million (139%) and $11.8 million (124%),
respectively, from engineering-related services, due primarily to
higher salary, overtime and other employee-related expenses, as well
as increased contract labor, all associated with the increased project
work described above;
o increases of $2.4 million (13%) and $8.1 million (14%), respectively,
from our Louisiana terminals, largely due to property damage,
demurrage and other expenses, which in large part related to the
effects of hurricanes Katrina and Rita, both of which impacted the
Gulf Coast since the third quarter of 2005. Increases also resulted
from higher stevedoring, dockage, and demurrage expenses related to
increased shipping activities;
o increases of $1.9 million (12%) and $3.3 million (7%), respectively,
from our Midwest region terminals, due primarily to higher marine fuel
costs of sales at our Dravosburg terminal, higher maintenance and
outside service expenses associated with increases in coal transfer
volumes, and additional labor and equipment rental expenses from the
combined operations of our Argo and Chicago, Illinois liquids
terminals due to increased ethanol throughput and incremental liquids
storage and handling business;
o increases of $1.5 million (33%) and $2.8 million (19%), respectively,
from terminals in our Ferro alloys region, due primarily to higher
labor and higher equipment maintenance and rentals related to
increased ores and metals handling at our Chicago and Industry,
Pennsylvania terminals; and
o increases of $1.4 million (19%) and $3.1 million (15%), respectively,
from our Gulf Coast liquids terminals, due primarily to incremental
labor expenses, tank cleaning and maintenance, power expenses and
permitting fees.
The segment's earnings from equity investments remained essentially flat
across both comparable periods, and income from other items increased $0.2
million and $2.6 million, respectively, in the comparable three and nine periods
of 2006, compared to 2005. The three month increase was largely due to gains
realized from the sale of our Kinder Morgan River Terminals' Fort Smith,
Arkansas warehouse operating assets in the third quarter of 2006. The nine month
increase included a $1.8 million income item recognized in the first quarter of
2006 and described above, related to a favorable settlement associated with the
purchase of our Kinder Morgan St. Gabriel terminal, and a $1.2 million increase
related to a disposal loss recognized in the first quarter of 2005 on warehouse
property at our Elizabeth River bulk terminal, located in Chesapeake, Virginia.
Income tax expenses increased $1.2 million (52%) and decreased $2.4 million
(25%) in the third quarter and first nine months of 2006, respectively, compared
to the same periods a year ago. The quarter-to-quarter increase was primarily
due to higher taxable earnings from all combined tax-paying terminal entities.
The decrease in the comparable nine month periods was largely impacted by a $1.8
million reduction in expense associated with a June
77
2006 adjustment to the accrued federal income tax liability account of Kinder
Morgan Bulk Terminals, Inc., the tax-paying entity that owns many of our bulk
terminal businesses.
Compared to the same periods in 2005, non-cash depreciation, depletion and
amortization charges increased $3.7 million (23%) in the third quarter of 2006,
and $13.3 million (32%) in the first nine months of 2006. The year-over-year
increases in depreciation expenses resulted from the capital expenditures and
terminal acquisitions we have made since the beginning of 2005. Since the
beginning of last year, we completed numerous improvement projects and acquired
various terminal operations in order to expand and enhance our terminalling
services. Collectively, the terminal assets we acquired since the beginning of
2005 and listed above accounted for incremental depreciation expenses of $1.1
million and $7.8 million, respectively, in the third quarter and first nine
months of 2006.
Other
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- --------------------------
2006 2005 2006 2005
---- ---- ---- ----
(In thousands-income/(expense))
General and administrative expenses........................ $ (59,694) $ (47,073) $ (183,913) $ (171,058)
Unallocable interest, net.................................. (89,424) (69,688) (249,617) (196,362)
Minority interest.......................................... (2,018) (1,806) (7,881) (6,648)
---------- ---------- ---------- ----------
Interest and corporate administrative expenses........... $ (151,136) $ (118,567) $ (441,411) $ (374,068)
========== ========== ========== ==========
Items not attributable to any segment include general and administrative
expenses, unallocable interest income, interest expense and minority interest.
General and administrative expenses include such items as salaries and
employee-related expenses, payroll taxes, insurance, office supplies and
rentals, unallocated litigation and environmental expenses, and shared corporate
services, including accounting, information technology, human resources, and
legal.
Our total general and administrative expenses increased $12.6 million (27%)
in the third quarter of 2006, when compared to the third quarter of 2005. The
increase was primarily due to a $4.8 million drop in capitalized overhead costs
in the third quarter of 2006 compared to the third quarter of 2005, reflecting
both a lower capitalization rate and lower spending on capital projects. In
addition, we accrued incremental insurance expenses and realized higher employee
benefit expenses in the third quarter of 2006 compared to the third quarter of
2005. The increase in insurance expenses reflect higher period-to-period rates
and the increase in employee benefit expenses reflect higher wage and benefit
costs influenced by changes in compensation levels and health-related expenses.
For the first nine months of 2006, general and administrative expenses
increased $12.9 million (8%) when compared to the same 2005 period. The
year-over-year increase was partly due to lower capitalized overhead costs
(described above), higher corporate service charges, insurance, and employee
benefit expenses in the first nine months of 2006, and partly due to increased
costs associated with new acquisitions made since the third quarter of 2005. The
overall increase was partly offset by lower unallocated litigation and
environmental settlement expenses in 2006--in the first nine months of 2005, we
recognized unallocated litigation and environmental settlement expenses of $33.4
million, consisting of a $25.0 million expense for a settlement reached between
us and a former joint venture partner on our Kinder Morgan Tejas natural gas
pipeline system and a cumulative $8.4 million expense related to settlements of
environmental matters at certain of our operating sites located in the State of
California.
Unallocable interest expense, net of interest income, increased $19.7
million (28%) and $53.3 million (27%), respectively, in the third quarter and
first nine months of 2006, compared to the same year-earlier periods. The
increases were due to both higher average debt levels and higher effective
interest rates. Average borrowings for the three and nine month periods ending
September 30, 2006, increased 8% and 9%, respectively, versus the same periods
last year. The increases were mainly due to higher capital spending and to the
acquisition of external assets and businesses since the end of the third quarter
of 2005. Generally, we fund both our capital spending (including payments for
pipeline project construction costs) and our acquisition outlays from borrowings
under our commercial paper program.
In addition, for the comparable nine month periods, average borrowings
increased in 2006 versus 2005 due to a net increase of $300 million in principal
amount of long-term senior notes. On March 15, 2005, we both closed a
78
public offering of $500 million in principal amount of senior notes and retired
a principal amount of $200 million. We issue senior notes in order to refinance
commercial paper borrowings used for both internal capital spending and
acquisition expenditures.
The weighted average interest rate on all of our borrowings increased 19%
and 17%, respectively, in the third quarter and first nine months of 2006,
compared to the same prior year periods. The increases in our average borrowing
rates reflect a general rise in variable interest rates since the end of the
third quarter of 2005. We use interest rate swap agreements to help manage our
interest rate risk. The swaps are contractual agreements we enter into in order
to transform a portion of the underlying cash flows related to our long-term
fixed rate debt securities into variable rate debt in order to achieve our
desired mix of fixed and variable rate debt. However, in a period of rising
interest rates, these swaps will result in period-to-period increases in our
interest expense. For more information on our interest rate swaps, see Note 10
to our consolidated financial statements, included elsewhere in this report.
Minority interest, representing the deduction in our consolidated net
income attributable to all outstanding ownership interests in our five operating
limited partnerships and their consolidated subsidiaries that are not held by
us, was essentially flat across both quarterly periods, but increased $1.2
million (19%) in the first nine months of 2006, compared to the same period last
year. The increase was primarily due to incremental interest income and expense
allocated to the minority interest in West2East Pipeline LLC, the sole owner of
Rockies Express Pipeline LLC. Prior to ConocoPhillips' acquisition of a 24%
ownership interest in West2East Pipeline LLC on June 30, 2006, we fully
consolidated West2East Pipeline LLC and we reported the 33 1/3% interest we did
not own as minority interest.
Financial Condition
Capital Structure
We attempt to maintain a conservative overall capital structure, with a
long-term target mix of approximately 50% equity and 50% debt. In addition to
our results of operations, our debt and capital balances are affected by our
financing activities, as discussed below in "--Financing Activities." The
following table illustrates the sources of our invested capital (dollars in
thousands):
September 30, December 31,
2006 2005
-------------- ------------
Long-term debt, excluding market value of interest rate swaps...... $ 4,386,706 $ 5,220,887
Minority interest.................................................. 44,666 42,331
Partners' capital, excluding accumulated other
comprehensive loss................................................. 4,878,054 4,693,414
------------ -----------
Total capitalization............................................. 9,309,426 9,956,632
Short-term debt, less cash and cash equivalents.................... 1,123,260 (12,108)
------------ -----------
Total invested capital........................................... $ 10,432,686 $ 9,944,524
============ ===========
Capitalization:
Long-term debt, excluding market value of interest rate swaps.... 47.1% 52.4%
Minority interest................................................ 0.5% 0.4%
Partners' capital, excluding accumulated other
comprehensive loss............................................... 52.4% 47.2%
------------ -----------
100.0% 100.0%
============ ===========
Invested Capital:
Total debt, less cash and cash equivalents and excluding
market value of interest rate swaps..................... 52.8% 52.4%
Partners' capital and minority interest, excluding accumulated
other comprehensive loss ............................... 47.2% 47.6%
------------ -----------
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
79
borrowings under our credit facility, issuing short-term commercial paper,
long-term notes or additional common units or the proceeds from purchases of
additional i-units by KMR with the proceeds from issuances of KMR shares.
In general, we expect to fund:
o cash distributions and sustaining capital expenditures with existing
cash and cash flows from operating activities;
o expansion capital expenditures and working capital deficits with
retained cash (resulting from including i-units in the determination
of cash distributions per unit but paying quarterly distributions on
i-units in additional i-units rather than cash), additional
borrowings, the issuance of additional common units or the proceeds
from purchases of additional i-units by KMR;
o interest payments with cash flows from operating activities; and
o debt principal payments with additional borrowings, as such debt
principal payments become due, or by the issuance of additional common
units or the proceeds from purchases of additional i-units by KMR.
As a publicly traded limited partnership, our common units are attractive
primarily to individual investors, although such investors represent a small
segment of the total equity capital market. We believe that some institutional
investors prefer shares of KMR over our common units due to tax and other
regulatory considerations. We are able to access this segment of the capital
market through KMR's purchases of i-units issued by us with the proceeds from
the sale of KMR shares to institutional investors.
As part of our financial strategy, we try to maintain an investment-grade
credit rating, which involves, among other things, the issuance of additional
limited partner units in connection with our acquisitions and internal growth
activities in order to maintain acceptable financial ratios. Our debt credit
ratings are currently rated BBB+ by Standard & Poor's Rating Services, and Baa1
by Moody's Investors Service. On May 30, 2006, S&P and Moody's each placed our
ratings on credit watch pending resolution of a management buyout proposal for
all of the outstanding shares of KMI. We are not able to predict with certainty
the final outcome of the pending buyout proposal; however, even if the buyout
proposal is consummated, we expect to maintain an investment grade credit
rating.
Short-term Liquidity
Our principal sources of short-term liquidity are:
o our $1.85 billion five-year senior unsecured revolving credit facility
that matures August 18, 2010;
o our $1.85 billion short-term commercial paper program (which is
supported by our bank credit facility, with the amount available for
borrowing under our credit facility being reduced by our outstanding
commercial paper borrowings); and
o cash from operations (discussed following).
Borrowings under our credit facility can be used for general corporate
purposes and as a backup for our commercial paper program. There were no
borrowings under our credit facility as of December 31, 2005, or as of September
30, 2006. As of September 30, 2006, we had $887.6 million of commercial paper
outstanding.
We provide for additional liquidity by maintaining a sizable amount of
excess borrowing capacity related to our commercial paper program and long-term
revolving credit facility. After inclusion of our outstanding commercial paper
borrowings and letters of credit, the remaining available borrowing capacity
under our bank credit facility was $524.3 million as of September 30, 2006. As
of September 30, 2006, our outstanding short-term debt was $1,147.2 million.
Currently, we believe our liquidity to be adequate.
80
Some of our customers are experiencing, or may experience in the future,
severe financial problems that have had or may have 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.
Long-term Financing
In addition to our principal sources of short-term liquidity listed above,
we could meet our cash requirements (other than distributions to our common
unitholders, Class B unitholders and general partner) through issuing long-term
notes or additional common units, or the proceeds from purchases of additional
i-units by KMR with the proceeds from issuances of KMR shares.
We are subject, however, to changes in the equity and debt markets for our
limited partner units and long-term notes, and there can be no assurance we will
be able or willing to access the public or private markets for our limited
partner units and/or long-term notes in the future. If we were unable or
unwilling to issue additional limited partner units, we would be required to
either restrict potential future acquisitions or pursue other debt financing
alternatives, some of which could involve higher costs or negatively affect our
credit ratings. Our ability to access the public and private debt markets is
affected by our credit ratings. See "--Capital Structure" above for a discussion
of our credit ratings.
All of our long-term debt securities issued to date, other than those
issued under our long-term revolving credit facility or those issued by our
subsidiaries and operating partnerships, generally have the same terms except
for interest rates, maturity dates and prepayment premiums. All of our
outstanding debt securities are unsecured obligations that rank equally with all
of our other senior debt obligations; however, a modest amount of secured debt
has been incurred by some of our operating partnerships and subsidiaries. Our
fixed rate notes provide that we may redeem the notes at any time at a price
equal to 100% of the principal amount of the notes plus accrued interest to the
redemption date plus a make-whole premium.
As of September 30, 2006, our total liability balance due on the various
series of our senior notes was $4,490.4 million, and the total liability balance
due on the various borrowings of our operating partnerships and subsidiaries was
$155.9 million. For additional information regarding our debt securities and
credit facility, see Note 9 to our consolidated financial statements included in
our Form 10-K for the year ended December 31, 2005.
Operating Activities
Net cash provided by operating activities was $878.7 million for the nine
months ended September 30, 2006, versus $901.6 million in the comparable period
of 2005. The period-to-period decrease of $22.9 million (3%) in cash flow from
operations consisted of:
o an $87.8 million decrease in cash inflows relative to net changes in
working capital items, mainly due to timing differences that resulted
in higher net cash payments of $91.3 million with regard to the
collection and payment of both trade and related party receivables and
payables;
o a $19.1 million decrease in cash related to payments made in June 2006
to certain shippers on our Pacific operations' pipelines. The payment
related to a settlement agreement reached in May 2006 that resolved
certain challenges by complainants with regard to delivery tariffs and
gathering enhancement fees at our Pacific operations' Watson Station,
located in Carson, California. The agreement called for estimated
refunds to be paid into an escrow account pending final approval by
the FERC, which was made in the third quarter of 2006;
o a $62.0 million increase in cash from overall higher partnership
income--net of non-cash items including depreciation charges,
undistributed earnings from equity investments, and gains from the
sale of assets. The higher partnership income reflects an increase in
cash earnings from our four reportable business segments in
81
the first nine months of 2006, as discussed above in "-Results of
Operations." The non-cash items include the $15.1 million gain from
the combined sale of our Douglas natural gas gathering system and
Painter Unit fractionation facility in the second quarter of 2006;
o a $17.3 million increase in cash inflows relative to net changes in
non-current assets and liabilities, which represent offsetting changes
in cash from various long-term asset and liability accounts. On a net
basis, the increase in cash inflows from non-current items reflects,
among other things, higher environmental expense accruals in the first
nine months of 2006, higher spending on deferred project study costs
in the first nine months of 2005, and incremental property tax refunds
received in the second quarter of 2006, pursuant to successful
litigation between our Pacific operations and various Arizona taxing
authorities concerning differences over the assessed value of property
owned by our Pacific operations for the tax years 2000 through 2002;
and
o a $4.7 million increase related to higher distributions received from
equity investments--chiefly due to higher distributions received from
Red Cedar Gathering Company in the first nine months of 2006. The
increase in distributions received resulted from Red Cedar's higher
year-over-year net income in the first nine months of 2006 versus the
first nine months of 2005, and also from the fact that Red Cedar had
higher capital expansion spending in 2005, and funded a large portion
of the expenditures with retained cash.
Investing Activities
Net cash used in investing activities was $1,062.1 million for the nine
month period ended September 30, 2006, compared to $905.6 million in the
comparable 2005 period. The $156.5 million (17%) increase in cash used in
investing activities was primarily attributable to:
o a $154.1 million (26%) increase in capital expenditures--driven by a
$163.4 million increase in capital spending from our Natural Gas
Pipelines business segment, largely due to increased investment in
natural gas pipeline and natural gas storage expansion projects.
Including expansion and maintenance projects, our capital expenditures
were $751.3 million in the first nine months of 2006, compared to
$597.2 million in the same prior-year period.
Our sustaining capital expenditures were $76.2 million for the first
nine months of 2006, compared to $95.8 million for the first nine
months of 2005. Sustaining capital expenditures are defined as capital
expenditures which do not increase the capacity of an asset. Beginning
in the third quarter of 2006, our Products Pipelines business segment
began recognizing certain costs incurred as part of its pipeline
integrity management program as maintenance expense in the period
incurred, and in addition, recorded an expense for costs previously
capitalized as sustaining capital expenditures during the first six
months of 2006. Combined, this change reduced the segment's earnings
before depreciation, depletion and amortization expenses by $18.1
million and its sustaining capital expenditures by $14.6 million.
Our forecasted expenditures for the fourth quarter of 2006 for
sustaining capital expenditures are approximately $45.9 million. This
amount has been forecasted primarily for the purchase of plant and
equipment. All of our capital expenditures, with the exception of
sustaining capital expenditures, are discretionary;
o a $77.5 million (27%) increase due to higher expenditures made for
strategic business acquisitions--in the first nine months of 2006, our
acquisition outlays totaled $367.3 million, which consisted of $244.6
million for the acquisition of Entrega Gas Pipeline LLC, $62.5 million
for the acquisition of bulk terminal operations and related assets,
and $60.2 million for the purchase of additional oil and gas
properties. In the first nine months of 2005, we spent $289.8 million,
which primarily included $188.6 million for the acquisition of Texas
Petcoke terminal assets from Trans-Global Solutions, Inc., $50.9
million for our North Dayton, Texas natural gas storage facility, and
$23.9 million for the acquisition of our Kinder Morgan Staten Island
terminal, a petroleum products liquids terminal located in the New
York Harbor area on Staten Island, New York;
o a $68.5 million decrease in cash used due to higher net proceeds
received from the sales of property, plant and equipment and other net
assets, net of salvage and removal costs. The increase in sale
proceeds was driven
82
by (i) the $42.5 million we received in the second quarter of 2006
from Momentum Energy Group, LLC for the combined sale of our Douglas
natural gas gathering system and Painter Unit fractionation facility
and (ii) the $27.0 million we received in the first half of 2006 from
the sale of certain oil and gas properties from Journey Acquisition-I,
L.P. and Journey 2000, L.P.; and
o a $7.3 million decrease due to lower payments for natural gas stored
underground and natural gas liquids pipeline line-fill--largely
related to lower investments in underground natural gas storage
volumes in the first nine months of this year relative to the first
nine months of last year.
In addition, we recently made the following announcements related to our
investing activities:
o On September 11, 2006, we announced major expansions at certain of our
Texas liquids terminal facilities that will provide additional
infrastructure to help meet the growing need for refined petroleum
products storage capacity along the Gulf Coast. The investment of
approximately $195 million will include the construction of:
o new storage tanks at our Pasadena and Galena Park terminals on the
Houston Ship Channel;
o an additional cross-channel pipeline to increase the connectivity
between the two terminals;
o a new ship dock at Galena Park; and
o an additional loading bay at our fully automated truck loading rack
located at our Pasadena terminal.
The expansions are supported by long-term customer commitments and
will result in approximately 3.4 million barrels of additional tank
storage capacity at the Pasadena and Galena Park terminals.
Construction began in October 2006 and all of the projects are
expected to be completed by the spring of 2008; and
o On October 19, 2006, we announced plans to invest approximately $388
million to further expand our 550-mile CALNEV Pipeline. CALNEV
currently transports refined petroleum products from the Los Angeles,
California area to the Las Vegas, Nevada market through parallel
14-inch and 8-inch diameter pipelines. The proposed expansion would
include construction of a new 16-inch diameter pipeline and would
increase system capacity to approximately 200,000 barrels per day upon
completion. Capacity could be increased as necessary to over 300,000
barrels per day with the addition of pump stations.
Environmental permitting and right-of-way acquisition is expected to
take between 24 to 30 months, and construction is anticipated to be
competed within nine months thereafter. The expansion is subject to
environmental permitting, right-of-way acquisition and the receipt of
approvals from the FERC authorizing rates that are economic to CALNEV.
Start-up of the new pipeline is scheduled for late 2009 or early 2010.
Financing Activities
Net cash provided by financing activities amounted to $195.1 million for
the nine months ended September 30, 2006. For the same nine month period last
year, our financing activities provided net cash of $4.2 million. The $190.9
million increase from the comparable 2005 period was primarily due to:
o a $318.2 million increase from overall debt financing
activities--which include our issuances and payments of debt and our
debt issuance costs. The overall increase was primarily due to a
$612.1 million increase from higher net commercial paper borrowings in
the first nine months of 2006, partially offset by a $294.4 million
decrease due to both issuances and payments of senior notes during
2005. The increase in commercial paper debt includes net borrowings of
$412.5 million under the commercial paper program of Rockies Express
Pipeline LLC. We held a 66 2/3% ownership interest in Rockies Express
Pipeline LLC until June 30, 2006, and according to the provisions of
generally accepted accounting principles, we included its cash inflows
and outflows in our consolidated statement of cash flows for the six
months ended June 30, 2006.
On June 30, 2006, following ConocoPhillips' acquisition of a 24%
ownership interest in West2East Pipeline LLC (and its subsidiary
Rockies Express Pipeline LLC), we deconsolidated West2East Pipeline
LLC and we have subsequently accounted for our investment under the
equity method of accounting. Following the
83
change to the equity method on June 30, 2006, Rockies Express' debt
balances were no longer included in our consolidated balance sheet and
its cash inflows and outflows for all periods subsequent to June 2006
were not included in our consolidated statement of cash flows.
The decrease in cash inflows from changes in our senior notes related
to debt activities occurring on March 15, 2005. On that date, we both
closed a public offering of $500 million in principal amount of 5.80%
senior notes and repaid $200 million of 8.0% senior notes that matured
on that date. The 5.80% senior notes are due March 15, 2035. We
received proceeds from the issuance of the notes, after underwriting
discounts and commissions, of approximately $494.4 million, and we
used the proceeds to repay the 8.0% senior notes and to reduce our
commercial paper debt;
o a $104.8 million increase from contributions from minority
interests--principally due to contributions of $104.2 million received
from Sempra Energy with regard to its ownership interest in Rockies
Express Pipeline LLC. The contribution from Sempra includes an amount
of $80 million, contributed in the first quarter of 2006, for Sempra's
original 33 1/3% share of the purchase price of Entrega Pipeline LLC.
In April 2006, Rockies Express Pipeline LLC merged with and into
Entrega Gas Pipeline LLC, and the surviving entity was renamed Rockies
Express Pipeline LLC;
o a $6.0 million increase from net changes in cash book
overdrafts--which represent checks issued but not yet endorsed;
o a $200.4 million decrease from higher partnership
distributions--distributions to all partners, consisting of our common
and Class B unitholders, our general partner and minority interests,
totaled $896.9 million in the first nine months of 2006, compared to
$696.5 million in the comparable 2005 period. The overall increase in
period-to-period distributions included minority interest
distributions of $105.2 million paid from our Rockies Express Pipeline
LLC subsidiary to Sempra Energy in the first half of 2006.
The distributions to Sempra (and distributions to us for our
proportional ownership interest) were made in conjunction with Rockies
Express' establishment of and subsequent borrowings under its
commercial paper program during the second quarter of 2006, as
discussed above. During the second quarter of 2006, Rockies Express
both issued a net amount of $412.5 million of commercial paper and
distributed $315.5 million to its member owners. Prior to the
establishment of its commercial paper program (supported by its
five-year unsecured revolving credit agreement), Rockies Express
funded its acquisition of Entrega Gas Pipeline LLC and its Rockies
Express Pipeline construction costs with contributions from both us
and Sempra.
Excluding the minority interest distributions to Sempra, overall
distributions increased $95.2 million. The increase primarily resulted
from higher distributions in 2006 of "Available Cash," as described
below in "--Partnership Distributions." The increase in "Available
Cash" distributions in 2006 versus 2005 was due to an increase in the
per unit cash distributions paid, an increase in the number of units
outstanding and an increase in our general partner incentive
distributions. The increase in our general partner incentive
distributions resulted from both increased cash distributions per unit
and an increase in the number of common units and i-units outstanding;
and
o a $37.0 million decrease in cash inflows from equity
issuances--primarily related to the incremental cash we received for
our third quarter 2005 common unit issuance compared to our third
quarter 2006 common unit issuance. In the third quarter of 2005, we
issued, in a public offering, 5,750,000 of our common units at a price
of $51.25 per unit. After commissions and underwriting expenses, we
received net proceeds of $283.6 million for the issuance of these
units. Similarly, in an August 2006 public offering, we issued an
additional 5,750,000 of our common units at a price of $44.80, less
commissions and underwriting expenses. After all fees, we received net
proceeds of $248.0 million for the issuance of these common units. We
used the proceeds from each of these two equity issuances to reduce
the borrowings under our commercial paper program.
84
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 and net
reductions in reserves, less cash disbursements and net additions to reserves
and amounts payable to the former general partner of SFPP, L.P. in respect of
its remaining 0.5% interest in SFPP.
Our general partner is granted discretion by our partnership agreement,
which discretion has been delegated to KMR, subject to the approval of our
general partner in certain cases, to establish, maintain and adjust reserves for
future operating expenses, debt service, maintenance capital expenditures, rate
refunds and distributions for the next four quarters. These reserves are not
restricted by magnitude, but only by type of future cash requirements with which
they can be associated. When KMR determines our quarterly distributions, it
considers current and expected reserve needs along with current and expected
cash flows to identify the appropriate sustainable distribution level.
Our general partner and owners of our common units and Class B units
receive distributions in cash, while KMR, the sole owner of our i-units,
receives distributions in additional i-units. We do not distribute cash to
i-unit owners but retain the cash for use in our business. However, the cash
equivalent of distributions of i-units is treated as if it had actually been
distributed for purposes of determining the distributions to our general
partner. Each time we make a distribution, the number of i-units owned by KMR
and the percentage of our total units owned by KMR increase automatically under
the provisions of our partnership agreement.
Available cash is initially distributed 98% to our limited partners and 2%
to our general partner. These distribution percentages are modified to provide
for incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
o first, 98% to the owners of all classes of units pro rata and 2% to
our general partner until the owners of all classes of units have
received a total of $0.15125 per unit in cash or equivalent i-units
for such quarter;
o second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the
owners of all classes of units have received a total of $0.17875 per
unit in cash or equivalent i-units for such quarter;
o third, 75% of any available cash then remaining to the owners of all
classes of units pro rata and 25% to our general partner until the
owners of all classes of units have received a total of $0.23375 per
unit in cash or equivalent i-units for such quarter; and
o fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units
in cash and to owners of i-units in the equivalent number of i-units,
and 50% to our general partner.
On August 14, 2006, we paid a quarterly distribution of $0.81 per unit for
the second quarter of 2006. This distribution was 4% greater than the $0.78
distribution per unit we paid in August 2005 for the second quarter of 2005. We
paid this distribution in cash to our common unitholders and to our Class B
unitholders. KMR, our sole i-unitholder, received additional i-units based on
the $0.81 cash distribution per common unit. We believe that future operating
results will continue to support similar levels of quarterly cash and i-unit
distributions; however, no assurance can be given that future distributions will
continue at such levels.
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
that we paid on August 14, 2006 to our general partner (for the second quarter
of 2006) was $129.0 million. Our general partner's incentive distribution that
we paid in August 2005 to our general partner (for the second quarter of 2005)
was $115.7 million. Our general partner's incentive distribution for the
distribution that we declared for the third
85
quarter of 2006 was $133.0 million. Our general partner's incentive distribution
for the distribution that we paid for the third quarter of 2005 was $121.5
million.
Litigation and Environmental
As of September 30, 2006, we have recorded a total reserve for
environmental claims, without discounting and without regard to anticipated
insurance recoveries, in the amount of $65.2 million. In addition, we have
recorded a receivable of $27.1 million for expected cost recoveries that have
been deemed probable. The reserve is primarily established to address and clean
up soil and ground water impacts from former releases to the environment at
facilities we have acquired or accidental spills or releases at facilities that
we own. Reserves for each project are generally established by reviewing
existing documents, conducting interviews and performing site inspections to
determine the overall size and impact to the environment. Reviews are made on a
quarterly basis to determine the status of the cleanup and the costs associated
with the effort. In assessing environmental risks in conjunction with proposed
acquisitions, we review records relating to environmental issues, conduct site
inspections, interview employees, and, if appropriate, collect soil and
groundwater samples.
Additionally, as of September 30, 2006, we have recorded a total reserve
for legal fees, transportation rate cases and other litigation liabilities in
the amount of $112.7 million. The reserve is primarily related to various claims
from lawsuits arising from our Pacific operations' pipeline transportation
rates, and the contingent amount is based on both the circumstances of
probability and reasonability of dollar estimates. We regularly assess the
likelihood of adverse outcomes resulting from these claims in order to determine
the adequacy of our liability provision.
We believe we have established adequate environmental and legal reserves
such that the resolution of pending environmental matters and litigation will
not have a material adverse impact on our business, cash flows, financial
position or results of operations. However, changing circumstances could cause
these matters to have a material adverse impact.
Pursuant to our continuing commitment to operational excellence and our
focus on safe, reliable operations, we have implemented, and intend to implement
in the future, enhancements to certain of our operational practices in order to
strengthen our environmental and asset integrity performance. These enhancements
have resulted and may result in higher operating costs and sustaining capital
expenditures; however, we believe these enhancements will provide us the greater
long term benefits of improved environmental and asset integrity performance.
Please refer to Notes 3 and 14, respectively, to our consolidated financial
statements included elsewhere in this report for additional information
regarding pending litigation, environmental and asset integrity matters.
Certain Contractual Obligations
There have been no material changes in our contractual obligations that
would affect the disclosures presented as of December 31, 2005 in our 2005 Form
10-K report.
Off Balance Sheet Arrangements
Except as set forth under "--Rockies Express Pipeline LLC Debt" in Note 7
to our consolidated financial statements included elsewhere in this report,
there have been no material changes in our obligations with respect to other
entities that are not consolidated in our financial statements that would affect
the disclosures presented as of December 31, 2005 in our 2005 Form 10-K.
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," 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,
86
income or cash flow or to make distributions are forward-looking statements.
Forward-looking statements are not guarantees of performance. They involve
risks, uncertainties and assumptions. Future actions, conditions or events and
future results of operations may differ materially from those expressed in these
forward-looking statements. Many of the factors that will determine these
results are beyond our ability to control or predict. Specific factors which
could cause actual results to differ from those in the forward-looking
statements include:
o price trends and overall demand for natural gas liquids, refined
petroleum products, oil, carbon dioxide, natural gas, coal and other
bulk materials and chemicals in North America;
o economic activity, weather, alternative energy sources, conservation
and technological advances that may affect price trends and demand;
o changes in our tariff rates implemented by the Federal Energy
Regulatory Commission or the California Public Utilities Commission;
o our ability to acquire new businesses and assets and integrate those
operations into our existing operations, as well as our ability to
make expansions to our facilities;
o difficulties or delays experienced by railroads, barges, trucks, ships
or pipelines in delivering products to or from our terminals or
pipelines;
o our ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
o shut-downs or cutbacks at major refineries, petrochemical or chemical
plants, ports, utilities, military bases or other businesses that use
our services or provide services or products to us;
o crude oil and natural gas production from exploration and production
areas that we serve, including, among others, the Permian Basin area
of West Texas;
o changes in laws or regulations, third-party relations and approvals,
decisions of courts, regulators and governmental bodies that may
adversely affect our business or our ability to compete;
o changes in accounting pronouncements that impact the measurement of
our results of operations, the timing of when such measurements are to
be made and recorded, and the disclosures surrounding these
activities;
o our ability to offer and sell equity securities and debt securities or
obtain debt financing in sufficient amounts to implement that portion
of our business plan that contemplates growth through acquisitions of
operating businesses and assets and expansions of our facilities;
o our indebtedness could make us vulnerable to general adverse economic
and industry conditions, limit our ability to borrow additional funds,
and/or place us at competitive disadvantages compared to our
competitors that have less debt or have other adverse consequences;
o interruptions of electric power supply to our facilities due to
natural disasters, power shortages, strikes, riots, terrorism, war or
other causes;
o our ability to obtain insurance coverage without significant levels of
self-retention of risk;
o acts of nature, sabotage, terrorism or other similar acts causing
damage greater than our insurance coverage limits;
o capital markets conditions;
o the political and economic stability of the oil producing nations of
the world;
o national, international, regional and local economic, competitive and
regulatory conditions and developments;
87
o the ability to achieve cost savings and revenue growth;
o inflation;
o interest rates;
o the pace of deregulation of retail natural gas and electricity;
o foreign exchange fluctuations;
o the timing and extent of changes in commodity prices for oil, natural
gas, electricity and certain agricultural products;
o the extent of our success in discovering, developing and producing oil
and gas reserves, including the risks inherent in exploration and
development drilling, well completion and other development
activities;
o engineering and mechanical or technological difficulties with
operational equipment, in well completions and workovers, and in
drilling new wells;
o the uncertainty inherent in estimating future oil and natural gas
production or reserves;
o the timing and success of business development efforts; and
o unfavorable results of litigation and the fruition of contingencies
referred to in Note 3 to our consolidated financial statements
included elsewhere in this report.
There is no assurance that any of the actions, events or results of the
forward-looking statements will occur, or if any of them do, what impact they
will have on our results of operations or financial condition. Because of these
uncertainties, you should not put undue reliance on any forward-looking
statements.
See Item 1A "Risk Factors" of our Annual Report on Form 10-K for the year
ended December 31, 2005 and Part II, Item 1A "Risk Factors" of this report, 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 2005 Form 10-K report and
this report. The risk factors could cause our actual results to differ
materially from those contained in any forward-looking statement. Other than as
required by applicable law, we disclaim any obligation to update the above list
or to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
There have been no material changes in market risk exposures that would
affect the quantitative and qualitative disclosures presented as of December 31,
2005, in Item 7A of our 2005 Form 10-K report. For more information on our risk
management activities, see Note 10 to our consolidated financial statements
included elsewhere in this report.
Item 4. Controls and Procedures.
As of September 30, 2006, 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,
88
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 Securities Exchange
Act of 1934 is recorded, processed, summarized and reported as and when
required, and is accumulated and communicated to our management, including our
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow
timely decisions regarding required disclosure. There has been no change in our
internal control over financial reporting during the quarter ended September 30,
2006 that has materially affected, or is reasonably likely to materially affect,
our internal control over financial reporting.
89
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 3 to our consolidated financial statements
entitled "Litigation, Environmental and Other Contingencies," which is
incorporated in this item by reference.
Item 1A. Risk Factors.
Except as set forth below, there have been no material changes to the risk
factors disclosed in Item 1A "Risk Factors" in our Annual Report on Form 10-K
for the year ended December 31, 2005.
The consummation of a transaction to acquire all of the outstanding common
stock of KMI that results in substantially more debt at KMI could have an
adverse effect on us, such as a downgrade in the ratings of our debt securities.
On August 28, 2006, KMI entered into an agreement and plan of merger whereby
investors led by Richard D. Kinder, Chairman and CEO of KMI, would acquire all
of the outstanding shares of KMI for $107.50 per share in cash. The investors
include members of senior management of KMI, most of whom are also senior
officers of our general partner and of KMR. As a result, prior to the closing of
this transaction, our senior management's attention may be diverted from the
management of our daily operations. In response to this proposed transaction,
Moody's Investor Services placed both our long-term and short-term debt ratings
under review for possible downgrade and Standard & Poor's put our long-term debt
rating on credit watch with negative implications. In connection with the
merger, KMI will incur substantially more debt, which could have an adverse
effect on us, such as a downgrade in the ratings of our debt securities, which
could be significant.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Item 5. Other Information.
None.
Item 6. Exhibits.
4.1 -- Certain instruments with respect to long-term debt of Kinder Morgan
Energy Partners, L.P. and its consolidated subsidiaries which relate to
debt that does not exceed 10% of the total assets of Kinder Morgan
Energy Partners, L.P. and its consolidated subsidiaries are omitted
pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R.
sec.229.601. Kinder Morgan Energy Partners, L.P. hereby agrees
90
to furnish supplementally to the Securities and Exchange Commission a
copy of each such instrument upon request.
10.1 -- First Amendment, dated October 28, 2005, to Five-Year Credit Agreement
dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P.,
the lenders party thereto and Wachovia Bank, National Association as
Administrative Agent.
10.2 -- Second Amendment, dated April 13, 2006, to Five-Year Credit Agreement
dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P.,
the lenders party thereto and Wachovia Bank, National Association as
Administrative Agent.
10.3 -- Third Amendment, dated October 6, 2006, to Five-Year Credit Agreement
dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P.,
the lenders party thereto and Wachovia Bank, National Association as
Administrative Agent.
11 -- Statement re: computation of per share earnings.
12 -- Statement re: computation of ratio of earnings to fixed charges.
31.1 -- Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the Securities
Exchange Act of 1934, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 -- Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the Securities
Exchange Act of 1934, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 -- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 -- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
- -----------
91
SIGNATURE
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 sole General Partner
By: KINDER MORGAN MANAGEMENT, LLC,
the Delegate of Kinder Morgan G.P., Inc.
/s/ Kimberly A. Dang
------------------------------------------
Kimberly A. Dang
Vice President and Chief Financial Officer
Date: November 7, 2006
92