F O R M 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 157,019,676 common units outstanding as of July 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 Six Months
Ended June 30, 2006 and 2005.................................... 3
Consolidated Balance Sheets - June 30, 2006 and December 31,
2005............................................................ 4
2005 Consolidated Statements of Cash Flows - Six Months Ended
June 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......................................... 57
Critical Accounting Policies and Estimates...................... 57
Results of Operations........................................... 58
Financial Condition............................................. 76
Information Regarding Forward-Looking Statements................ 83
Item 3: Quantitative and Qualitative Disclosures About Market Risk........ 85
Item 4: Controls and Procedures........................................... 85
` PART II. OTHER INFORMATION
Item 1: Legal Proceedings................................................. 86
Item 1A: Risk Factors...................................................... 86
Item 2: Unregistered Sales of Equity Securities and Use of Proceeds....... 86
Item 3: Defaults Upon Senior Securities................................... 86
Item 4: Submission of Matters to a Vote of Security Holders............... 86
Item 5: Other Information................................................. 86
Item 6: Exhibits.......................................................... 86
Signature........................................................... 88
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Unit Amounts)
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
---------------------------- --------------------------
2006 2005 2006 2005
----------- ----------- ----------- -----------
Revenues
Natural gas sales.............................................. $ 1,470,970 $ 1,492,534 $ 3,162,362 $ 2,845,149
Services....................................................... 512,158 455,602 1,021,660 899,027
Product sales and other........................................ 213,360 178,219 404,067 354,111
----------- ----------- ----------- -----------
2,196,488 2,126,355 4,588,089 4,098,287
----------- ----------- ----------- -----------
Costs, Expenses and Other
Gas purchases and other costs of sales......................... 1,461,403 1,487,574 3,138,634 2,825,344
Operations and maintenance..................................... 193,154 153,595 366,536 292,135
Fuel and power................................................. 53,054 45,438 103,977 87,378
Depreciation, depletion and amortization....................... 97,229 88,261 189,950 173,288
General and administrative..................................... 63,336 50,133 124,219 123,985
Taxes, other than income taxes................................. 31,587 26,225 62,854 52,051
Other expense (income)......................................... (15,114) -- (15,114) --
----------- ----------- ----------- -----------
1,884,649 1,851,226 3,971,056 3,554,181
----------- ----------- ----------- -----------
Operating Income................................................. 311,839 275,129 617,033 544,106
Other Income (Expense)
Earnings from equity investments............................... 18,450 22,838 43,171 48,910
Amortization of excess cost of equity investments.............. (1,414) (1,409) (2,828) (2,826)
Interest, net.................................................. (82,102) (65,312) (157,808) (124,039)
Other, net..................................................... 6,065 649 7,840 (672)
Minority Interest................................................ (3,493) (2,454) (5,863) (4,842)
----------- ----------- ----------- -----------
Income Before Income Taxes....................................... 249,345 229,441 501,545 460,637
Income Taxes..................................................... (2,284) (7,615) (7,775) (15,190)
----------- ----------- ----------- -----------
Net Income....................................................... $ 247,061 $ 221,826 $ 493,770 $ 445,447
=========== =========== =========== ===========
General Partner's interest in Net Income......................... $ 130,156 $ 117,253 $ 259,684 $ 228,980
Limited Partners' interest in Net Income......................... 116,905 104,573 234,086 216,467
----------- ----------- ----------- -----------
Net Income....................................................... $ 247,061 $ 221,826 $ 493,770 $ 445,447
=========== =========== =========== ===========
Basic and Diluted Limited Partners' Net Income per Unit.......... $ 0.53 $ 0.50 $ 1.06 $ 1.04
=========== =========== =========== ===========
Weighted average number of units used in computation of Limited
Partners' Net Income per unit:
Basic............................................................ 221,813 209,220 221,286 208,379
=========== =========== =========== ===========
Diluted.......................................................... 222,150 209,465 221,618 208,529
=========== =========== =========== ===========
Per unit cash distribution declared.............................. $ 0.81 $ 0.78 $ 1.62 $ 1.54
=========== =========== =========== ===========
The accompanying notes are an integral part of these
consolidated financial statements.
3
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
June 30, December 31,
-------- ------------
2006 2005
---- ----
ASSETS
Current Assets
Cash and cash equivalents..................... $ 32,756 $ 12,108
Restricted deposits........................... 38,508 -
Accounts, notes and interest receivable, net
Trade...................................... 772,987 1,011,716
Related parties............................ 4,880 2,543
Inventories
Products................................... 25,365 18,820
Materials and supplies..................... 13,722 13,292
Gas imbalances
Trade...................................... 10,695 18,220
Related parties............................ 7,896 -
Gas in underground storage.................... 33,669 7,074
Other current assets.......................... 125,716 131,451
----------- -----------
1,066,194 1,215,224
----------- -----------
Property, Plant and Equipment, net.............. 9,160,420 8,864,584
Investments..................................... 429,976 419,313
Notes receivable
Trade......................................... 1,438 1,468
Related parties............................... 90,854 109,006
Goodwill........................................ 819,592 798,959
Other intangibles, net.......................... 213,481 217,020
Deferred charges and other assets............... 179,760 297,888
----------- -----------
Total Assets.................................... $11,961,715 $11,923,462
=========== ===========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts....................... $ 47,384 $ 30,408
Trade...................................... 607,314 996,174
Related parties............................ 2,312 16,676
Current portion of long-term debt............. 1,105,038 -
Accrued interest.............................. 79,554 74,886
Accrued taxes................................. 54,208 23,536
Deferred revenues............................. 12,951 10,523
Gas imbalances
Trade...................................... 9,153 22,948
Related parties............................ - 1,646
Accrued other current liabilities............. 737,850 632,088
----------- -----------
2,655,764 1,808,885
----------- -----------
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding................................ 4,642,890 5,220,887
Market value of interest rate swaps........ (48,010) 98,469
----------- -----------
4,594,880 5,319,356
Deferred revenues............................. 23,297 6,735
Deferred income taxes......................... 70,277 70,343
Asset retirement obligations.................. 47,741 42,417
Other long-term liabilities and
deferred credits............................. 1,206,614 1,019,655
----------- -----------
5,942,809 6,458,506
----------- -----------
Commitments and Contingencies (Note 3)
Minority Interest............................... 39,846 42,331
----------- -----------
Partners' Capital
Common Units.................................. 2,593,740 2,680,352
Class B Units................................. 106,662 109,594
i-Units....................................... 1,845,873 1,783,570
General Partner............................... 122,026 119,898
Accumulated other comprehensive loss.......... (1,345,005) (1,079,674)
----------- -----------
3,323,296 3,613,740
----------- -----------
Total Liabilities and Partners' Capital......... $11,961,715 $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)
Six Months Ended June 30,
--------------------------
2006 2005
----------- -----------
Cash Flows From Operating Activities
Net income.......................................................................... $ 493,770 $ 445,447
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization........................................... 189,950 173,288
Amortization of excess cost of equity investments.................................. 2,828 2,826
Earnings from equity investments................................................... (43,171) (48,910)
Distributions from equity investments................................................ 43,429 30,089
Changes in components of working capital:
Accounts receivable................................................................ 251,070 11,455
Other current assets............................................................... (9,180) (3,528)
Inventories........................................................................ (3,947) (2,180)
Accounts payable................................................................... (401,387) (38,721)
Accrued liabilities................................................................ (8,536) 14,233
Accrued taxes...................................................................... 30,939 22,356
Other, net........................................................................... (14,346) (18,115)
----------- -----------
Net Cash Provided by Operating Activities.............................................. 531,419 588,240
----------- -----------
Cash Flows From Investing Activities
Acquisitions of assets............................................................... (365,780) (193,330)
Additions to property, plant and equip. for expansion and maintenance projects....... (561,240) (341,609)
Sale of property, plant and equipment, and other net assets net of removal costs..... 41,727 2,474
Investments in margin deposits and other restricted deposits......................... (38,508) (32,420)
Contributions to equity investments.................................................. (32) (1,070)
Natural gas stored underground and natural gas liquids line-fill..................... (12,863) (20,574)
Other................................................................................ (3,401) (295)
----------- -----------
Net Cash Used in Investing Activities.................................................. (940,097) (586,824)
----------- -----------
Cash Flows From Financing Activities
Issuance of debt..................................................................... 2,827,235 2,599,233
Payment of debt...................................................................... (1,888,295) (2,074,849)
Repayments from loans to related party............................................... 1,097 1,048
Debt issue costs..................................................................... (1,475) (4,994)
Increase (Decrease) in cash book overdrafts.......................................... 16,976 (28,625)
Proceeds from issuance of common units............................................... 157 1,532
Contributions from minority interest................................................. 106,264 1,510
Distributions to partners:
Common units....................................................................... (253,059) (222,099)
Class B units...................................................................... (8,555) (7,970)
General Partner.................................................................... (257,555) (220,286)
Minority interest.................................................................. (111,906) (5,785)
Other, net........................................................................... (1,658) (2,370)
----------- -----------
Net Cash Provided by (Used in) Financing Activities.................................... 429,226 36,345
----------- -----------
Effect of exchange rate changes on cash and cash equivalents........................... 100 (205)
Increase (Decrease) in Cash and Cash Equivalents....................................... 20,648 37,556
Cash and Cash Equivalents, beginning of period......................................... 12,108 --
----------- -----------
Cash and Cash Equivalents, end of period............................................... $ 32,756 $ 37,556
=========== ===========
Noncash Investing and Financing Activities:
Contribution of net assets to partnership investments................................ $ 17,003 $ --
Assets acquired by the issuance of units............................................. -- 46,250
Assets acquired by the assumption of liabilities..................................... 3,757 15,387
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.
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 six 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 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.
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 appraisal of
acquired fixed asset and land values, a reclassification 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 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.
7
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 has begun, 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 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), of which a 24% interest will be transferred immediately with an
additional 1% interest being 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 will own 51% of the equity in the project
(down from 66 2/3%). 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. In addition, effective June 30, 2006, Sempra's ownership interest in
West2East Pipeline LLC decreased to 25% (down from 33 1/3%). 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," as 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. As we will receive
50% of the economics of the project on an ongoing basis, we are no longer
considered the primary beneficiary of this entity as defined by FIN 46R and
thus, effective June 30, 2006, West2East Pipeline LLC was deconsolidated and
will subsequently be accounted for under the equity method of accounting.
Under the equity method, we will 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 will recognize our proportional share of that change in the
"Investment" account. We will 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.
As of June 30, 2006, we had no material net investment in West2East
Pipeline LLC due to the fact that the amount of its assets, primarily property,
plant and equipment, was largely offset by the amount of its liabilities,
primarily debt. In addition, we have guaranteed our proportional share of its
borrowings under a $2 billion credit facility entered into by Rockies Express
Pipeline LLC. As of June 30, 2006, our contingent share of borrowings under this
facility totaled $210.4 million (See Note 7). Summary financial information for
West2East Pipeline LLC, which is accounted for under the equity method as of
June 30, 2006, is as follows (in thousands; amounts represent 100% of investee
information):
8
June 30,
--------
Balance Sheet 2006
---------------------------- --------
Current assets.............. $ 555
Non-current assets.......... 416,542
Current liabilities......... 4,952
Non-current liabilities..... 412,108
Accumulated other comprehensive income $ 37
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 $62.3 million, consisting of
$58.7 million in cash and $3.6 million in assumed liabilities. The acquisition
was made effective March 1, 2006. The properties are primarily located in the
Permian Basin area of West Texas and New Mexico, produce approximately 850
barrels of oil equivalent per day net, and include some fields with potential
for enhanced oil recovery 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. The purchase price plus the anticipated investment to
both further develop carbon dioxide enhanced oil recovery and construct a new
carbon dioxide supply pipeline on all of the acquired properties would be
approximately $115 million. However, we divested certain acquired properties
that are not considered candidates for carbon dioxide enhanced oil recovery,
thus reducing our total investment. In the second quarter of 2006, we received
proceeds of approximately $1.1 million from the sale of certain properties, and
in the third quarter of 2006, we received approximately $27.0 million for
additional property divestitures.
As of June 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............. $58,676
Current liabilities assumed........................ 32
Long-term liabilities assumed...................... 3,548
-------
Total purchase price............................... $62,256
=======
Allocation of purchase price:
Current assets..................................... $ 202
Property, plant and equipment...................... 62,054
-------
$62,256
=======
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.
9
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
Current 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
The following summarized unaudited pro forma consolidated income statement
information for the six months ended June 30, 2006 and 2005, assumes that 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 the
beginning of the period presented. We have prepared these unaudited pro forma
financial results for comparative purposes only. These unaudited pro forma
financial results may not be indicative of the results that would have occurred
if we had completed these acquisitions and joint ventures as of January 1, 2005
or the results that will be attained in the future. Amounts presented below are
in thousands, except for the per unit amounts:
Pro Forma
Six Months Ended June 30,
-------------------------
2006 2005
---------- -----------
(Unaudited)
Revenues..................................... $ 4,600,261 $ 4,157,400
Operating Income............................. 605,005 562,930
Net Income................................... 494,133 455,638
Basic Limited Partners' Net Income per
unit......................................... 1.06 1.08
Diluted Limited Partners' Net Income
per unit..................................... $ 1.06 $ 1.08
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 an approximately
$18.0 million 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.
Our 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 the Douglas processing plant. Our Painter Unit, located near Evanston,
Wyoming, consisted 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
10
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 on those derivative contracts that effectively hedged
uncertain future cash flows associated with forecasted Douglas gathering
transactions from "Accumulated other comprehensive loss" into net income. We
included the net amount of the gain, $15.1 million, within the caption "Other
expense (income)" in our accompanying consolidated statements of income for the
three and six months ended June 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
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.
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.
11
The FERC initially modified the initial decision's ruling regarding the
capital structure to be used in computing SFPP's "starting rate base" to be more
favorable to SFPP, but later reversed that ruling. The FERC also made certain
modifications to the calculation of the income tax allowance and other cost of
service components, generally to SFPP's disadvantage.
On multiple occasions, the FERC required SFPP to file revised East Line
rates based on rulings made in the FERC's various orders. SFPP was also directed
to submit compliance filings showing the calculation of the revised rates, the
potential reparations for each complainant and in some cases potential refunds
to shippers. SFPP filed such revised East Line rates and compliance filings in
March 1999, July 2000, November 2001 (revised December 2001), October 2002 and
February 2003 (revised March 2003). Most of those filings were protested by
particular SFPP shippers. The FERC has held that certain of the rates SFPP filed
at the FERC's directive should be reduced retroactively and/or be subject to
refund; SFPP has challenged the FERC's authority to impose such requirements in
this context.
While the FERC initially permitted SFPP to recover certain of its
litigation, pipeline reconditioning and environmental costs, either through a
surcharge on prospective rates or as an offset to potential reparations, it
ultimately limited recovery in such a way that SFPP was not able to make any
such surcharge or take any such offset. Similarly, the FERC initially ruled that
SFPP would not owe reparations to any complainant for any period prior to the
date on which that party's complaint was filed, but ultimately held that each
complainant could recover reparations for a period extending two years prior to
the filing of its complaint (except for Navajo, which was limited to one month
of pre-complaint reparations under a settlement agreement with SFPP's
predecessor). The FERC also ultimately held that SFPP was not required to pay
reparations or refunds for Watson Station gathering enhancement fees charged
prior to filing a FERC tariff for that service.
In April 2003, SFPP paid complainants and other shippers reparations and/or
refunds as required by FERC's orders. In August 2003, SFPP paid shippers an
additional refund as required by FERC's most recent order in the Docket No.
OR92-8 et al. proceedings. We made aggregate payments of $44.9 million in 2003
for reparations and refunds pursuant to a FERC order.
Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond
Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for
review of FERC's Docket OR92-8 et al. orders in the United States Court of
Appeals for the District of Columbia Circuit. Certain of those petitions were
dismissed by the Court of Appeals as premature, and the remaining petitions were
held in abeyance pending completion of agency action. However, in December 2002,
the Court of Appeals returned to its active docket all petitions to review the
FERC's orders in the case through November 2001 and severed petitions regarding
later FERC orders. The severed orders were held in abeyance for later
consideration.
Briefing in the Court of Appeals was completed in August 2003, and oral
argument took place on November 12, 2003. 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.
12
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 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
13
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.
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 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.
14
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 has moved to intervene in the review proceedings
brought by the other parties. A briefing schedule was set by the Court, with
initial briefs filed May 30, 2006, and final briefs to be filed October 11,
2006.
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. Under the settlement, SFPP agreed to lower
its going-forward rate to $0.003 per barrel and to include certain volumetric
pumping rates in its tariff. SFPP also agreed to pay refunds to all shippers for
the period since April 1, 1999 until the new tariff takes effect. Those refunds
are 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. Total
refunds for the period between April 1, 1999 and May 31, 2006 are approximately
$18.6 million, and according to the provisions of the settlement agreement, in
June 2006, SFPP made aggregate payments of approximately $13.5 million into an
escrow account pending final approval by the FERC. We included this amount
within "Restricted deposits" on our consolidated balance sheet as of June 30,
2006,
Additional refunds will be required for the period between June 1, 2006 and
the date on which the new tariff takes effect. 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. No adverse comments
regarding the settlement were received, and on June 21, 2006, the administrative
law judge certified the settlement to the FERC. On August 2, 2006, the FERC
approved the settlement without modification and directed that it be
implemented.
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.
15
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.
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 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
16
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. A briefing schedule has been set by the Court, with initial briefs filed
May 30, 2006, and final briefs due October 11, 2006.
On July 24, 2006, the FERC filed with the Court 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. It is not possible to predict
whether this motion will be granted and how the FERC's reconsideration may alter
its prior determination regarding the grandfathered status of SFPP's rates. 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.
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.
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
17
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 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 and OR96-2 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. 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 $20
million. In light of the FERC's recent motion for voluntary remand of its
grandfathering orders and SFPP's August 1, 2006 filing to reinstate rates
previously lowered as a result of those orders, the expected impact will be less
than $20 million in 2006 if the reinstatement of the previous rates is upheld.
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 U.S. 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
18
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. 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.
19
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 case has now been briefed to the
administrative law judge.
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.
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
20
approving the requested rate increase also required SFPP to submit cost data for
2001, 2002, and 2003, and to assist the CPUC in determining whether SFPP's
overall rates for California intrastate transportation services are reasonable.
The resolution reserves the right to require refunds, from the date of issuance
of the resolution, to the extent the CPUC's analysis of cost data to be
submitted by SFPP demonstrates that SFPP's California jurisdictional rates are
unreasonable in any fashion. On February 21, 2003, SFPP submitted the cost data
required by the CPUC, which submittal was protested by Valero Marketing and
Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil
Corporation and Chevron Products Company. Issues raised by the protest,
including the reasonableness of SFPP's existing intrastate transportation rates,
were the subject of evidentiary hearings conducted in December 2003 and may be
resolved by the CPUC 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. 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.
With regard to the Power Surcharge Resolution, the November, 2004 rate
increase application, and the January, 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
21
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 was previously set for trial on June 12, 2006, but the
Court granted an uncontested motion filed by the Plaintiffs to continue the
trial date. No trial date is currently set.
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 trial was previously set for trial on June
12, 2006, but the Court granted an uncontested motion filed by the Plaintiffs to
continue the trial date. No trial date is currently set.
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
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
have 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
22
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 has 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 which are virtually identical to the counter-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, 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 has granted Ptasynski's request to non-suit.
Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company are among the
named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al.,
No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case
involves claims by overriding royalty interest owners in the McElmo Dome and Doe
Canyon Units 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 claim breaches of contractual and potential fiduciary duties
owed by the defendants and also allege other theories of liability including
breach of covenants, civil theft, conversion, fraud/fraudulent concealment,
violation of the Colorado Organized Crime Control Act, deceptive trade
practices, and violation of the Colorado Antitrust Act. In addition to actual or
compensatory damages, plaintiffs seek treble damages, punitive damages, and
declaratory relief relating to the Cortez Pipeline tariff and the method of
calculating and paying royalties on McElmo Dome carbon
23
dioxide. The Court denied plaintiffs' motion for summary judgment concerning
alleged underpayment of McElmo Dome overriding royalties on March 2, 2005. No
trial date is currently set.
Cortez Pipeline Company and Kinder Morgan CO2 Company, L.P., successor in
interest to Shell CO2 Company, Ltd., are among the named defendants in CO2
Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November
28, 2005. The arbitration arises 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 current 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 alleges 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 alleges 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 deny 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. The arbitration panel is expected to issue its
decision in August, 2006.
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
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 has
filed a motion to compel arbitration of this matter pursuant to the arbitration
provisions contained in the Feerer Class Action settlement agreement, which
motion was denied by the trial court. An appeal of that ruling has been filed
and is pending before the New Mexico Court of Appeals. Oral arguments took place
before the New Mexico Court of Appeals on March 23, 2006. No date for
arbitration or trial is currently set.
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
24
(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 are seeking 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
third quarter of 2006. In addition, 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
25
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.
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. It is
likely that Grynberg will appeal any dismissal 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'
26
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.
Cannon Interests-Houston v. Kinder Morgan Texas Pipeline, L.P., No.
2005-36174 (333rd Judicial District, Harris County, Texas).
On June 6, 2005, after unsuccessful mediation, Cannon Interests sued Kinder
Morgan Texas Pipeline, L.P., referred to in this report as KMTP, and alleged
breach of contract for the purchase of natural gas storage capacity and for
failure to pay under a profit-sharing arrangement. KMTP counterclaimed that
Cannon Interests failed to provide it with five billion cubic feet of winter
storage capacity in breach of the contract. The plaintiff was claiming
approximately $13 million in damages. In May 2006, the parties entered into a
confidential settlement that resolved all claims in this matter. The case has
been dismissed.
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
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 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
27
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 agreed to participate in and fund a
minor percentage of the settlement. A fairness hearing will occur on August 18,
2006 for the purpose of establishing final approval of the partial settlement.
In the event the settlement is finally approved on August 18, 2006, certain
claims by other residents and businesses shall remain pending. Specifically, the
settlement 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.
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, Kinder Morgan filed a motion for summary judgment.
The city will respond to the pending motions no later than August 18, 2006. Oral
argument will be heard on October 20, 2006. The parties agreed to stay discovery
until after October 20, 2006, 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
28
Washoe) ("Galaz II"); Frankie Sue Galaz, et al v. The United States of America,
the City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners,
L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas, LLC, Kinder Morgan
Operating Limited Partnership "D", Kinder Morgan Services LLC, Berry Hinkley and
Does I-X, No.CVN03-0298-DWH-VPC (United States District Court, District of
Nevada)("Galaz III")
On July 9, 2002, we were served with a purported complaint for class action
in the Snyder case, in which the plaintiffs, on behalf of themselves and others
similarly situated, assert that a leukemia cluster has developed in the City of
Fallon, Nevada. The complaint alleges that the plaintiffs have been exposed to
unspecified "environmental carcinogens" at unspecified times in an unspecified
manner and are therefore "suffering a significantly increased fear of serious
disease." The plaintiffs seek a certification of a class of all persons in
Nevada who have lived for at least three months of their first ten years of life
in the City of Fallon between the years 1992 and the present who have not been
diagnosed with leukemia.
The complaint purports to assert causes of action for nuisance and "knowing
concealment, suppression, or omission of material facts" against all defendants,
and seeks relief in the form of "a court-supervised trust fund, paid for by
defendants, jointly and severally, to finance a medical monitoring program to
deliver services to members of the purported class that include, but are not
limited to, testing, preventative screening and surveillance for conditions
resulting from, or which can potentially result from exposure to environmental
carcinogens," incidental damages, and attorneys' fees and costs.
The defendants responded to the complaint by filing motions to dismiss on
the grounds that it fails to state a claim upon which relief can be granted. On
November 7, 2002, the United States District Court granted the motion to dismiss
filed by the United States, and further dismissed all claims against the
remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs
filed a motion for reconsideration and leave to amend, which was denied by the
court on December 30, 2002. Plaintiffs filed a notice of appeal to the United
States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit
affirmed the dismissal of this case.
On December 3, 2002, plaintiffs filed an additional complaint for class
action in the Galaz I matter asserting the same claims in the same court on
behalf of the same purported class against virtually the same defendants,
including us. On February 10, 2003, the defendants filed motions to dismiss the
Galaz I Complaint on the grounds that it also fails to state a claim upon which
relief can be granted. This motion to dismiss was granted as to all defendants
on April 3, 2003. Plaintiffs 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.
29
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.
The parties are in the process of scheduling a case management conference and
anticipate that discovery will begin in the near term.
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. The parties are in the process of scheduling a
case management conference and anticipate that discovery will begin in the near
term.
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
30
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, and anticipate filing a Stipulation of Dismissal
with the Court in August 2006.
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 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.
Eleven 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 fifteen 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
31
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.
Fourteen of these lawsuits are currently coordinated in Contra Costa County
Superior Court; the fifteenth is expected to be coordinated with the other
lawsuits in the near future. There are also several cross-complaints for
indemnity between the co-defendants in the coordinated lawsuits.
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.
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 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
32
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 currently
estimates the amount of product released to be approximately 665 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 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.
33
Pipeline and Hazardous Materials Safety Administration Corrective Action
Order
On August 26, 2005, we announced that we had received a Corrective Action
Order issued by the PHMSA. The corrective order instructs us to comprehensively
address potential integrity threats along the pipelines that comprise our
Pacific operations. The corrective order focused primarily on eight pipeline
incidents, seven of which occurred in the State of California. The PHMSA
attributed five of the eight incidents to "outside force damage," such as
third-party damage caused by an excavator or damage caused during pipeline
construction.
Following the issuance of the corrective order, we engaged in cooperative
discussions with the PHMSA and we reached an agreement in principle on the terms
of a consent agreement with the PHMSA, subject to the PHMSA's obligation to
provide notice and an opportunity to comment on the consent agreement to
appropriate state officials pursuant to 49 USC Section 60112(c). This comment
period closed on March 26, 2006.
On April 10, 2006, we announced the final consent agreement, which will,
among other things, require us to perform a thorough analysis of recent pipeline
incidents, provide for a third-party independent review of our operations and
procedural practices, and restructure our internal inspections program.
Furthermore, we have reviewed all of our policies and procedures and are
currently implementing various measures to strengthen our integrity management
program, including a comprehensive evaluation of internal inspection
technologies and other methods to protect our pipelines. We expect to spend
approximately $90 million on pipeline integrity activities for our Pacific
operations' pipelines over the next five years. Of that amount, approximately
$26 million is related to this consent agreement. We do not expect that our
compliance with the consent agreement will have a material adverse effect 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.
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
34
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.
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.
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 June 30, 2006,
we have accrued an environmental reserve of $68.4 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.
35
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.
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 June 30, 2006, we have recognized asset
retirement obligations in the aggregate amount of $46.9 million relating to
these requirements at existing sites within our CO2 business segment.
In our Natural Gas Pipelines business segment, if we were to cease
providing utility services, we would be required to remove surface facilities
from land belonging to our customers and others. Our Texas intrastate natural
gas pipeline group has various condensate drip tanks and separators located
throughout its natural gas pipeline systems, as well as inactive gas processing
plants, laterals and gathering systems which are no longer integral to the
overall mainline transmission systems, and asbestos-coated underground pipe
which is being abandoned and retired. Our Kinder Morgan Interstate Gas
Transmission system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of June 30, 2006, we have recognized asset
retirement obligations in the aggregate amount of $1.6 million relating to the
businesses within our Natural Gas Pipelines business segment.
We have included $0.8 million of our total asset retirement obligations as
of June 30, 2006 with "Accrued other current liabilities" in our accompanying
consolidated balance sheet. The remaining $47.7 million obligation is reported
separately as a non-current liability. No assets are legally restricted for
purposes of settling our asset retirement obligations. A reconciliation of the
beginning and ending aggregate carrying amount of our asset retirement
obligations for each of the six months ended June 30, 2006 and 2005 is as
follows (in thousands):
Six Months Ended June 30,
-------------------------
2006 2005
--------- ---------
Balance at beginning of period......... $ 43,227 $ 38,274
Liabilities incurred................. 4,950 521
Liabilities settled.................. (815) (1,197)
Accretion expense.................... 1,189 962
Revisions in estimated cash flows.... -- (522)
--------- ---------
Balance at end of period............. $ 48,551 $ 38,038
========= =========
5. Distributions
On May 15, 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
March 31, 2006. KMR, our sole i-unitholder, received 1,093,826 additional
i-units based on the $0.81 cash distribution per common unit. The distributions
were declared on April 19, 2006, payable to unitholders of record as of April
28, 2006.
On July 19, 2006, we declared a cash distribution of $0.81 per unit for the
quarterly period ended June 30, 2006. The distribution will be paid on August
14, 2006, to unitholders of record as of July 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 1,131,777. For
36
each outstanding i-unit that KMR holds, a fraction of an i-unit (0.018860) will
be issued. The fraction was determined by dividing:
o $0.81, the cash amount distributed per common unit
by
o $42.947, the average of KMR's shares' closing market prices from July
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.
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):
June 30, December 31,
2006 2005
---------- ------------
Goodwill
Gross carrying amount....... $ 833,734 $ 813,101
Accumulated amortization.... (14,142) (14,142)
---------- ------------
Net carrying amount......... 819,592 798,959
========== ============
Changes in the carrying amount of our goodwill for the six months ended
June 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........ - - - 2,870 2,870
Impairments........ - - - - -
-------- ----------- ------- --------- --------
Balance as of June 30,
2006................. $263,182 $ 288,435 $46,101 $ 221,874 $819,592
======== =========== ======= ========= ========
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 June 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
37
current events or circumstances warrant adjustments to our carrying value and/or
revised estimates of useful lives in accordance with APB Opinion No. 18.
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):
June 30, December 31,
2006 2005
--------- ------------
Lease value
Gross carrying amount.......... $ 6,592 $ 6,592
Accumulated amortization....... (1,239) (1,168)
--------- ------------
Net carrying amount............ 5,353 5,424
========= ============
Contracts and other
Gross carrying amount 224,550 221,250
Accumulated amortization....... (16,422) (9,654)
--------- ------------
Net carrying amount............ 208,128 211,596
--------- ------------
Total Other intangibles, net..... $ 213,481 $ 217,020
========= ============
Amortization expense on our intangibles consisted of the following (in
thousands):
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
--------- --------- --------- ----------
Lease value........ $ 35 $ 35 $ 71 $ 71
Contracts and other 3,372 501 6,768 831
--------- --------- --------- ----------
Total amortization. $ 3,407 $ 536 $ 6,839 $ 902
========= ========= ========= ==========
As of June 30, 2006, our weighted average amortization period for our
intangible assets was approximately 19.1 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 June 30, 2006 was $1,105.0 million.
The balance consisted of:
o $1,095.5 million of commercial paper borrowings;
o a $5.7 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 5.558% during the second quarter of 2006 and 5.135% during the
second quarter of 2005.
38
Credit Facilities
As of June 30, 2006, we had two credit facilities:
o a $1.6 billion unsecured five-year credit facility due August 18,
2010; and
o a $250 million unsecured nine-month credit facility due November 21,
2006.
Our credit facilities are with a syndicate of financial institutions, and
Wachovia Bank, National Association is the administrative agent. There were no
borrowings under either credit facility as of June 30, 2006, and there were no
borrowings under our five-year credit facility as of December 31, 2005.
The amount available for borrowing under our two credit facilities as of
June 30, 2006 was reduced by:
o our outstanding commercial paper borrowings ($1,095.5 million as of
June 30, 2006);
o a combined $368 million in five letters of credit that support our
hedging of commodity price risks associated with the sale of natural
gas, natural gas liquids, oil and carbon dioxide;
o a combined $49 million in two letters of credit that support
tax-exempt bonds; 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. As of June 30, 2006, we had $1,095.5 million of commercial
paper outstanding with an average interest rate of 5.2456%. Borrowings under our
commercial paper program reduce the borrowings allowed under our two credit
facilities.
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.
39
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.
As of June 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 June 30, 2006, Cortez Capital Corporation had $83.7 million of
commercial paper outstanding with an average interest rate of 5.1331%, 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 June 30, 2006, $39.3 million in principal amount of
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 June 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. 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
40
expenses, and the borrowings will not reduce the borrowings allowed under our
two credit facilities described above in "--Credit Facilities."
Effective June 30, 2006, West2East Pipeline LLC (and its subsidiary Rockies
Express Pipeline, LLC) was deconsolidated and will subsequently be accounted for
under the equity method of accounting (See Note 2). All three owners 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. As of June 30, 2006, Rockies Express Pipeline LLC had $412.5 million of
commercial paper outstanding, and there were no borrowings under its five-year
credit facility. Accordingly, as of June 30, 2006, our contingent share of
Rockies Express' debt was $210.4 million.
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, KMI has agreed to indemnify us
and our general partner with respect to a total of approximately $733.5 million
of our debt as of June 30, 2006, and 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 June 30, 2006 and December 31, 2005, our partners' capital consisted
of the following limited partner units:
June 30, December 31,
2006 2005
----------- ------------
Common units..................... 157,019,676 157,005,326
Class B units.................... 5,313,400 5,313,400
i-units.......................... 60,009,379 57,918,373
----------- ------------
Total limited partner units.... 222,342,455 220,237,099
=========== ============
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 June 30, 2006, our common unit totals consisted of 142,663,941 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 both June 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 and our i-units
were held entirely by KMR. All of our Class B units were issued to a
wholly-owned subsidiary of KMI in December 2000. The Class B units are similar
to our common units except that they are not eligible for trading on the New
York Stock Exchange.
Our i-units are a separate class of limited partner interests in us. All of
our i-units are owned by KMR and are not publicly traded. In accordance with its
limited liability company agreement, KMR's activities are restricted to being a
limited partner in us, and 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 KMR's limited liability company agreement, the
number of outstanding KMR shares and the number of i-units will at all times be
equal.
41
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 1,093,826 i-units from us on May 15,
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 May 15, 2006 for the
first quarter of 2006 required an incentive distribution to our general partner
of $128.3 million. Our distribution of $0.76 per unit paid on May 13, 2005 for
the first quarter of 2005 required an incentive distribution to our general
partner of $111.1 million. The increased incentive distribution to our general
partner paid for the first quarter of 2006 over the distribution paid for the
first 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 second quarter of 2006 of $0.81 per unit
will result in an incentive distribution to our general partner of approximately
$129.0 million. This compares to our distribution of $0.78 per unit and
incentive distribution to our general partner of approximately $115.7 million
for the second 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
six month periods ended June 30, 2006, and June 30, 2005, the difference between
our net income and our comprehensive income resulted from unrealized gains or
losses on derivatives 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 Six Months Ended
June 30, June 30,
-------------------- --------------------
2006 2005 2006 2005
--------- --------- --------- ---------
Net income........................... $ 247,061 $ 221,826 $ 493,770 $ 445,447
Foreign currency translation
adjustments ......................... 265 (377) 384 (604)
Change in fair value of derivatives
used for hedging purposes............ (266,855) (200,034) (484,867) (756,869)
Reclassification of change in fair
value of derivatives to net income... 116,979 84,751 219,152 145,671
--------- --------- --------- ---------
Total other comprehensive
income/(loss)...................... (149,611) (115,660) (265,331) (611,802)
--------- --------- --------- ---------
Comprehensive income/(loss).......... $ 97,450 $ 106,166 $ 228,439 $(166,355)
========= ========= ========= =========
42
10. Risk Management
Energy Commodity Price Risk Management
Commodity Price Risk
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. Such changes are often caused by shifts in the supply and demand for
these commodities, as well as their locations. Due to this exposure, we use
energy financial instruments, also known as derivative contracts, as a hedging
(offset) mechanism against the volatility of energy commodity prices. Examples
of derivative contracts include the following: forward contracts, futures
contracts, options and swaps (also called contracts for differences).
Pursuant to our management's approved risk management policy, we use
derivative contracts to hedge or reduce our exposure to commodity price risk by
transferring this risk to counterparties who are able and willing to bear it.
Specifically, this price risk is associated with our:
o pre-existing or anticipated physical natural gas, natural gas liquids
and crude oil sales;
o natural gas purchases; and
o system use and storage.
Our risk management activities are primarily used in order to protect our
profit margins and our risk management policies prohibit us from engaging in
speculative trading. Commodity-related activities of our risk management group
are monitored by our risk management committee, which is charged with the review
and enforcement of our management's risk management policy. Our risk management
committee is a separately designated standing committee comprised of 19
executive-level employees of KMI or KMGP Services Company, Inc. whose job
responsibilities involve operations exposed to commodity market risk and other
external risks in the ordinary course of business. The committee is chaired by
our President and is charged with the following three responsibilities:
o establish and review risk limits consistent with our risk tolerance
philosophy;
o recommend to the audit committee of our general partner's delegate any
changes, modifications, or amendments to our risk management policy;
and
o address and resolve any other high-level risk management issues.
Accounting for Derivatives
Current accounting standards define a derivative contract based on its
characteristics, which include among others, one or more underlying variables
(or determinants of value) and one or more notional amounts (or units specified
in the contract). While the value of the underlying variable changes due to
changes in market conditions, the notional amount remains constant throughout
the life of the derivative contract. Examples of underlying variables include a
specified interest rate, commodity price, exchange rate or other variable;
examples of notional amounts include a number of commodities, currency units,
other units specified in the contract, or the principal amount of debt on an
interest rate swap. Together, the underlying and the notional amounts determine
the settlement value of the derivative contract, and, in some cases, whether or
not a settlement is required.
Derivative contracts represent rights or obligations that meet the
definitions of assets or liabilities and should be reported in financial
statements. Furthermore, current accounting standards require derivatives 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 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
43
substantially all of the energy commodity derivative contracts that we use,
including: commodity futures and options contracts, fixed price swaps, and basis
swaps.
Normally, gains and losses due to changes in derivative values during the
period are recognized in current earnings (net income); however, to mitigate the
increased volatility the mark-to-market requirement can produce, parties who
enter into derivative contracts may qualify for special "hedge" accounting
according to the provisions of SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for
Certain Derivative Instruments and Certain Hedging Activities," and SFAS No.
149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities," (collectively, SFAS No. 133), if the derivative is:
o used to offset the risk associated with a particular asset or
liability or an identified portion thereof--referred to as a fair
value hedge; or
o 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--referred to as a cash flow hedge; and
o documented and assessed on a continuing basis in order to demonstrate
that it is "highly effective" in hedging the underlying item. To be
considered effective, changes in the value of the derivative or its
resulting cash flows must substantially offset changes in the value or
cash flows of the item being hedged. A perfectly effective hedge is
one in which changes in the value of the derivative exactly offset
changes in the value of the hedged item or expected cash flow of the
future transactions in reporting periods covered by the derivative
contract. The ineffective portion of the gain or loss and any
component excluded from the computation of the effectiveness of the
derivative contract must be reported in earnings immediately.
With hedge accounting, losses or gains due to changes in derivative values
do not have to be recorded in earnings until they are offset by gains or losses
in the hedged items. In fair value hedges, the balance sheet impact results in
both the derivative contract (asset or liability) and the hedged item (asset or
liability) being reported at fair value, and hedge accounting treatment allows
gains and losses from changes in the fair value of the derivative contract to be
offset by changes in the fair value of the hedged item in current earnings. When
changes in the value of the derivative exactly offset changes in the value of
the hedged item, there should be no impact on earnings; however, when the
derivative is not effective in exactly offsetting changes in the value of the
hedged item, then the ineffective amount must be included in earnings.
With a cash flow hedge, it is the cash flow from an expected future
transaction that is being hedged (as opposed to the value of an asset,
liability, or firm commitment) and so there is no balance sheet entry for the
hedged item. For cash flow hedges, changes in the fair value of the derivative
contract are initially reported as a component of other comprehensive income
(outside current earnings, net income), but only to the extent that they can
later offset the hedged future 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 sheets 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
derivatives and there is no impact on earnings. When the hedged forecasted
transaction does take place and affects earnings, the effective part of the
hedge is also recognized in the income statement, and the earlier recognized
amounts are removed from "accumulated other comprehensive income/loss." If the
forecasted transaction results in an asset or liability, amounts in "accumulated
other comprehensive income/loss" should be reclassified into earnings when the
asset or liability affects earnings through cost of sales, depreciation,
interest expense, etc.
Commodity Price Risk Derivative Contracts
Our energy commodity derivative contracts hedge the commodity price risks
derived from our normal business activities, which include the sale of natural
gas, natural gas liquids and crude oil, and these derivatives have been
designated by us as cash flow hedges as defined by SFAS No. 133. Therefore, the
gains and losses that are included within "Accumulated other comprehensive loss"
in our accompanying consolidated balance sheets are primarily
44
related to the derivative contracts associated with our hedging of anticipated
future cash flows from the sales and purchases of natural gas, natural gas
liquids and crude oil, and as described above, these gains and losses are
reclassified into earnings as the hedged sales and purchases take place.
During the six months ended June 30, 2006 and 2005, we reclassified $219.2
million and $145.7 million, respectively, of "Accumulated other comprehensive
loss" into earnings as a result of hedged forecasted transactions occurring or
discontinuing during the respective time periods, and approximately $485.0
million of our "Accumulated other comprehensive loss" balance of $1,345.0
million as of June 30, 2006 is expected to be reclassified into earnings during
the next twelve months.
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), no other reclassification of Accumulated other
comprehensive loss into earnings during the first six months of 2006 or 2005
resulted from the discontinuance of cash flow hedges due to a determination that
the forecasted transactions would no longer occur by the end of the originally
specified time period, but rather resulted from the hedged forecasted
transactions actually affecting earnings (for example, when the forecasted sales
and purchases actually occurred).
As discussed above, 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) is required to be recognized currently in
earnings. Accordingly, as a result of ineffective hedges, we recognized losses
of $1.6 million and $1.8 million, respectively, during the three and six month
periods ended June 30, 2006, and losses of $0.2 million and $0.4 million,
respectively, during the three and six month periods ended June 30, 2005. All
gains and losses 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 six months ended June 30, 2006
and 2005, we did not exclude any component of the derivative contracts' gain or
loss from the assessment of hedge effectiveness.
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 June 30, 2006 and December 31, 2005 (in
thousands):
June 30, December 31,
2006 2005
--------- ------------
Derivatives-net asset/(liability)
Other current assets.................. $ 118,988 $ 109,437
Deferred charges and other assets..... 21,793 47,682
Accounts payable-Related parties...... -- (16,057)
Accrued other current liabilities..... (606,363) (507,306)
Other long-term liabilities and
deferred credits.................... $(885,944) $ (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 June 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 June 30, 2006, we had five outstanding letters of
credit totaling $368 million in support of our hedging of
45
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 June 30, 2006, our margin deposits associated with our commodity
contract positions and over-the-counter swap partners totaled $25.1 million, and
we reported this amount as "Restricted deposits" in our accompanying
consolidated balance sheet as of June 30, 2006. In June 2006, our CO2 business
segment hedged an incremental 23 million barrels of crude oil production at its
SACROC and Yates oil field units for the years 2007 through 2011 by entering
into a new hedge facility with J. Aron & Company/Goldman Sachs that does not
require the posting of margin. As of December 31, 2005, we had no cash margin
deposits associated with our commodity contract positions and over-the-counter
swap partners.
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.
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 June 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 June 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 June 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.
46
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.
Our interest rate swaps have been designated as fair value hedges as
defined by SFAS No. 133. As discussed above, if a company uses derivative
contracts 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 is appropriate. SFAS No. 133 designates derivative
contracts that hedge a recognized asset or liability's exposure to changes in
their fair value as fair value hedges and the gain or loss on fair value hedges
are to be recognized in earnings in the period of change together with the
offsetting loss or gain on the hedged item attributable to the risk being
hedged. The effect of that accounting is to reflect in earnings the extent to
which the hedge is not effective in achieving offsetting changes in fair value.
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.
The differences between the fair value and the original carrying value
associated with our interest rate swap agreements, that is, the derivatives'
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 June 30, 2006 and
December 31, 2005 (in thousands):
June 30, December 31,
2006 2005
-------- ------------
Derivatives-net asset/(liability)
Deferred charges and other assets....... $ 24,422 $ 112,386
Other long-term liabilities and
deferred credits........................ (72,432) (13,917)
-------- ------------
Market value of interest rate swaps... $(48,010) $ 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 June 30, 2006, all of
our interest rate swap agreements were with counterparties with investment grade
credit ratings.
11. Reportable Segments
We divide our operations into four reportable business segments:
o Products Pipelines;
o Natural Gas Pipelines;
47
o CO2; and
o Terminals.
We evaluate performance principally based on each segments' earnings before
depreciation, depletion and amortization, which exclude general and
administrative expenses, third-party debt costs 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 June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
----------- ----------- ----------- -----------
Revenues(a)
Products Pipelines
Revenues from external customers....... $ 189,021 $ 174,632 $ 369,547 $ 345,915
Intersegment revenues.................. - - - -
Natural Gas Pipelines
Revenues from external customers....... 1,601,760 1,616,657 3,431,756 3,089,549
Intersegment revenues.................. - - - -
CO2
Revenues from external customers....... 185,789 162,029 360,480 325,192
Intersegment revenues.................. - - - -
Terminals
Revenues from external customers....... 219,918 173,037 426,306 337,631
Intersegment revenues.................. 365 - 365 -
----------- ----------- ----------- -----------
Total segment revenues.................... 2,196,853 2,126,355 4,588,454 4,098,287
Less: Total intersegment revenues......... (365) - (365) -
----------- ----------- ----------- -----------
Total consolidated revenues............... $ 2,196,488 $ 2,126,355 $ 4,588,089 $ 4,098,287
=========== =========== =========== ===========
Operating expenses(b)
Products Pipelines........................ $ 78,893 $ 57,070 $ 139,540 $ 109,126
Natural Gas Pipelines..................... 1,477,074 1,509,692 3,174,840 2,866,787
CO2....................................... 66,715 54,334 125,324 103,843
Terminals................................. 116,881 91,736 232,662 177,152
----------- ----------- ----------- -----------
Total consolidated operating expenses... $ 1,739,563 $ 1,712,832 $ 3,672,366 $ 3,256,908
=========== =========== =========== ===========
Other expense (income)(c)
Products Pipelines........................ $ - $ - $ - $ -
Natural Gas Pipelines..................... (15,114) - (15,114) -
CO2....................................... - - - -
Terminals................................. - - - -
----------- ----------- ----------- -----------
Total consolidated other expense (income) $ (15,114) - $ (15,114) -
=========== =========== =========== ===========
Depreciation, depletion and amortization
Products Pipelines........................ $ 20,479 $ 19,828 $ 40,721 $ 39,222
Natural Gas Pipelines..................... 16,046 15,816 31,979 30,574
CO2....................................... 42,018 38,462 81,290 77,164
Terminals................................. 18,686 14,155 35,960 26,328
----------- ----------- ----------- -----------
Total consol. depreciation, depletion
and amortization........................ $ 97,229 $ 88,261 $ 189,950 $ 173,288
=========== =========== =========== ===========
48
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
----------- ----------- ----------- -----------
Earnings from equity investments(d)
Products Pipelines........................ $ 2,688 $ 7,065 $ 10,553 $ 15,450
Natural Gas Pipelines..................... 10,609 8,598 21,771 17,028
CO2....................................... 5,075 7,151 10,733 16,399
Terminals................................. 78 24 114 33
----------- ----------- ----------- -----------
Total consolidated equity earnings..... $ 18,450 $ 22,838 $ 43,171 $ 48,910
=========== =========== =========== ===========
Amortization of excess cost of equity
investments
Products Pipelines........................ $ 839 $ 836 $ 1,680 $ 1,680
Natural Gas Pipelines..................... 70 69 139 138
CO2....................................... 505 504 1,009 1,008
Terminals................................. - - - -
----------- ----------- ----------- -----------
Total consol. amortization of excess
cost of investments..................... $ 1,414 $ 1,409 $ 2,828 $ 2,826
=========== =========== =========== ===========
Interest income
Products Pipelines........................ $ 1,124 $ 1,149 $ 2,235 $ 2,298
Natural Gas Pipelines..................... - 166 150 337
CO2....................................... - - - -
Terminals................................. - - - -
----------- ----------- ----------- -----------
Total segment interest income.......... 1,124 1,315 2,385 2,635
Unallocated interest income............... 758 93 1,361 265
----------- ----------- ----------- -----------
Total consolidated interest income..... $ 1,882 $ 1,408 $ 3,746 $ 2,900
=========== =========== =========== ===========
Other, net - income (expense)(e)
Products Pipelines........................ $ 6,105 $ 223 $ 6,200 $ 365
Natural Gas Pipelines..................... 47 396 349 142
CO2....................................... 11 (1) 12 -
Terminals................................. (98) 31 1,279 (1,179)
----------- ----------- ----------- -----------
Total consolidated other, net - income
(expense)............................... $ 6,065 $ 649 $ 7,840 $ (672)
=========== =========== =========== ===========
Income tax benefit (expense)(f)
Products Pipelines........................ $ (817) $ (2,737) $ (3,872) $ (6,038)
Natural Gas Pipelines..................... 385 (1,081) 73 (1,538)
CO2....................................... (51) (67) (124) (112)
Terminals................................. (1,801) (3,730) (3,852) (7,502)
----------- ----------- ----------- -----------
Total consolidated income tax benefit
(expense)............................... $ (2,284) $ (7,615) $ (7,775) $ (15,190)
=========== =========== =========== ===========
Segment earnings
Products Pipelines........................ $ 97,910 $ 102,598 $ 202,722 $ 207,962
Natural Gas Pipelines..................... 134,725 99,159 262,255 208,019
CO2....................................... 81,586 75,812 163,478 159,464
Terminals................................. 82,895 63,471 155,590 125,503
----------- ----------- ----------- -----------
Total segment earnings(g)............... 397,116 341,040 784,045 700,948
Interest and corporate administrative
expenses(h)............................... (150,055) (119,214) (290,275) (255,501)
----------- ----------- ----------- -----------
Total consolidated net income........... $ 247,061 $ 221,826 $ 493,770 $ 445,447
=========== =========== =========== ===========
Segment earnings before depreciation,
depletion, amortization and amortization of
excess cost of equity investments(i)
Products Pipelines........................ $ 119,228 $ 123,262 $ 245,123 $ 248,864
Natural Gas Pipelines..................... 150,841 115,044 294,373 238,731
CO2....................................... 124,109 114,778 245,777 237,636
Terminals................................. 101,581 77,626 191,550 151,831
----------- ----------- ----------- -----------
Total segment earnings before DD&A...... 495,759 430,710 976,823 877,062
Total consol. depreciation, depletion and
amortization.............................. (97,229) (88,261) (189,950) (173,288)
Total consol. amortization of excess cost
of investments............................ (1,414) (1,409) (2,828) (2,826)
Interest and corporate administrative
expenses.................................. (150,055) (119,214) (290,275) (255,501)
----------- ----------- ----------- -----------
Total consolidated net income ......... $ 247,061 $ 221,826 $ 493,770 $ 445,447
=========== =========== =========== ===========
49
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
----------- ----------- ----------- -----------
Capital expenditures
Products Pipelines........................ $ 64,537 $ 56,647 $ 121,242 $ 97,717
Natural Gas Pipelines..................... 189,100 23,488 209,569 33,147
CO2....................................... 58,895 74,385 133,092 126,942
Terminals................................. 55,045 43,281 97,337 83,803
----------- ----------- ----------- -----------
Total consolidated capital
expenditures(j)......................... $ 367,577 $ 197,801 $ 561,240 $ 341,609
=========== =========== =========== ===========
June 30, December 31,
----------- ------------
2006 2005
----------- ------------
Assets
Products Pipelines................... $ 3,950,877 $ 3,873,939
Natural Gas Pipelines................ 3,891,768 4,139,969
CO2.................................. 1,876,842 1,772,756
Terminals............................ 2,213,757 2,052,457
----------- ------------
Total segment assets................. 11,933,244 11,839,121
Corporate assets(k).................. 28,471 84,341
----------- ------------
Total consolidated assets............ $11,961,715 $ 11,923,462
=========== ============
- ---------
(a) 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. 2006 amounts include environmental liability adjustments resulting
in a $13,458 expense to our Products Pipelines business segment and a
$1,500 expense to our Natural Gas Pipelines business segment. Also, 2006
amounts include a $6,244 reduction in expense our Natural Gas Pipelines
business segment due to the release of a reserve related to a natural gas
purchase/sales contract.
(c) 2006 amounts represent a $15,114 gain to our Natural Gas Pipelines business
segment from the sale of our Douglas natural gas gathering system and our
Painter Unit fractionation facility.
(d) 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) 2006 amounts include a $5,700 increase in income to our Products Pipelines
business segment from the settlement of transmix processing contracts.
(f) 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 (c).
(g) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses, other
expenses, 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
expenses.
(j) Includes sustaining capital expenditures of $34,988 and $28,747 for the
three months ended June 30, 2006 and 2005, respectively, and includes
sustaining capital expenditures of $60,653 and $52,956 for the six months
ended June 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 other restricted deposits, and
certain unallocable deferred charges.
We do not attribute interest and debt expense to any of our reportable
business segments. For the three months ended June 30, 2006 and 2005, we
reported (in thousands) total consolidated interest expense of $83,984 and
$66,720, respectively. For the six months ended June 30, 2006 and 2005, we
reported (in thousands) total consolidated interest expense of $161,554 and
$126,939, respectively.
50
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 June 30, Six Months Ended June 30,
2006 2005 2006 2005
----------- -------------- ------------ ------------
Net periodic benefit cost
Service cost................................. $ 3 $ 2 $ 5 $ 4
Interest cost................................ 67 77 134 154
Expected return on plan assets............... -- -- -- --
Amortization of prior service cost........... (30) (29) (59) (58)
Actuarial (gain)............................. (113) (127) (226) (254)
----- ----- ----- -----
Net periodic benefit cost.................... $ (73) $ (77) $(146) $(154)
===== ===== ===== =====
Our net periodic benefit cost for the second quarter and the first six
months of 2006 were credits of $73,000 and $146,000, 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 have been 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 June 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
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.
51
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 June 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 June 30, 2006, and we included the remaining
$90.9 million balance as "Notes receivable-Related parties."
Coyote Gas Treating, LLC
We own a 50% equity interest in Coyote Gas Treating, LLC, referred to in
this report as Coyote Gulch. Coyote Gulch is a joint venture, and Enterprise
Field Services LLC owns the remaining 50% equity interest. We are the managing
partner of 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 corresponds 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, Enterprise and we agreed to a resolution that would transfer
Coyote Gulch's notes payable to Enterprise and us 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. The $17.0 million amount is included within "Investments" on our
consolidated balance sheet as of June 30, 2006.
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.
52
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. The FERC's brief is due August
23, 2006, and INGAA's reply brief is due September 6, 2006.
The implementation of this FERC order on January 1, 2006, had no material
impact on our financial position, results of operations, or cash flows in the
first half of 2006. Our Kinder Morgan Interstate Gas Transmission system,
referred to in this report as KMIGT, expects an increase of approximately $0.8
million in operating expenses in 2006 related to pipeline integrity management
programs due to its implementation of this FERC order on January 1, 2006, which
will cause KMIGT to expense certain program costs that previously were
capitalized.
In addition, our intrastate natural gas pipelines located within the State
of Texas are not FERC-regulated but are regulated by the Railroad Commission of
Texas. We will maintain our current accounting procedures with respect to our
accounting for pipeline integrity testing costs.
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 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.
53
Notice of Proposed Rulemaking - Revisions to Blanket Certificate
Regulations and Clarification Regarding Rates
On June 16, 2006, in Docket No. RM06-7-000, the FERC issued a notice of
proposed rulemaking (pursuant to a joint petition for a rulemaking by INGAA and
the Natural Gas Supply Association) that would extend blanket certificate
(self-implementing) authority to a broader class of facilities, such as mainline
expansions, certain LNG facilities, and certain storage facilities. The proposed
rules also increase the cost limits for such self-implementing authority. In the
notice, the FERC found that its existing policies can accommodate the joint
petitioners' desire to offer rate incentives to obtain early project commitments
and that such rate incentives do not constitute undue discrimination. Comments
are due August 25, 2006.
Policy Statement - Natural Gas Quality and Interchangeability
On June 19, 2006, in Docket No. PL04-3-000, the FERC issued a Policy
Statement providing guidelines that the FERC will use in dealing with gas
quality and interchangeability issues. The FERC affirmed that any enforceable
gas quality standard must be contained in a pipeline tariff. The Policy
Statement emphasized flexibility and tailoring of gas quality specifications to
various market conditions and requirements.
Natural Gas Pipeline Expansion Filings
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." Upon approval
by the FERC, this project will authorize the first planned segment extension of
the Rockies Express Pipeline extending from the Cheyenne Hub located in Weld
County, Colorado to an interconnection with Panhandle Eastern Pipe Line located
in Audrain County, Missouri. The project will comprise approximately 713 miles
of 42-inch diameter pipeline and is proposed 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 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.
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;
54
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.
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.
55
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 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).
Earlier adoption is permitted as of the beginning of an entity's fiscal year,
provided the entity has not yet issued financial statements, including interim
financial statements, for any period of that fiscal year. The effective date of
this Statement is the date an entity adopts the requirements of this Statement.
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). We
are currently reviewing the effects of EITF 06-3.
56
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.
Proposed Standard on Pensions and Other Post-Retirement Benefits
On July 26, 2006, the FASB affirmed its previous decision to make the
recognition provisions of its proposed standard "Employers' Accounting for
Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB
Statements No. 87, 88, 106 and 132(R)," effective for public companies for
fiscal years ending after December 15, 2006 (December 31, 2006 for us).
We will be required to (i) apply the new standard to our year-end financial
statements and (ii) recognize on our consolidated balance sheet the funded
status of our pension and post-retirement benefit plans. We are currently
reviewing the effects of this proposed standard and assessing the impact of the
potential balance sheet changes.
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
The following discussion and analysis of our financial condition and
results of operations provides you with a narrative on our financial results. It
contains a discussion and analysis of the results of operations for each segment
of our business, followed by a discussion and analysis of our financial
condition. The following discussion and analysis should be read in conjunction
with:
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 assets and
liabilities 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:
57
o the economic useful lives of our assets;
o the fair values used to determine possible asset impairment charges;
o provisions for uncollectible accounts receivable;
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 not
been any significant changes in these policies and estimates during the three
and six months ended June 30, 2006.
Results of Operations
Consolidated
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
--------- ---------- ---------- ----------
(In thousands)
Earnings before depreciation, depletion and amortization expense
and amortization of excess cost of equity investments
Products Pipelines............................................ $ 119,228 $ 123,262 $ 245,123 $ 248,864
Natural Gas Pipelines......................................... 150,841 115,044 294,373 238,731
CO2........................................................... 124,109 114,778 245,777 237,636
Terminals..................................................... 101,581 77,626 191,550 151,831
--------- ---------- ---------- ----------
Segment earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments(a).................................................. 495,759 430,710 976,823 877,062
Depreciation, depletion and amortization expense................ (97,229) (88,261) (189,950) (173,288)
Amortization of excess cost of equity investments............... (1,414) (1,409) (2,828) (2,826)
Interest and corporate administrative expenses(b)............... (150,055) (119,214) (290,275) (255,501)
--------- ---------- ---------- ----------
Net income........................................................ $ 247,061 $ 221,826 $ 493,770 $ 445,447
========= ========== ========== ==========
- ---------------
(a) 2006 Products Pipelines business segment amounts include environmental
liability adjustments resulting in a $16,448 increase in expense and
transmix contract settlements resulting in income of $5,700. 2006
Natural Gas Pipelines business segment amounts include environmental
liability adjustments resulting in a $1,500 increase in expense, a
$15,114 gain from the combined sale of our Douglas natural gas
gathering system and Painter Unit fractionation facility, and a $6,244
reduction in expense due to the release of a reserve related to a
natural gas pipeline contract obligation. 2006 CO2 business segment
amounts include a $1,819 loss on derivative contracts used to hedge
forecasted crude oil sales.
(b) Includes unallocated interest income, interest and debt expense,
general and administrative expenses (including unallocated litigation
and environmental expenses) and minority interest expense.
Throughout the first half of 2006, we increased earnings in 2006, relative
to 2005, by capitalizing on:
o improved margins from natural gas sale, transportation, and storage
activities;
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 second quarter of 2005.
For the second quarter of 2006, our consolidated net income was $247.1
million, or $0.53 per diluted unit. This compares to consolidated net income of
$221.8 million, or $0.50 per diluted unit, for the second quarter of 2005. For
the six month periods ended June 30, our consolidated net income totaled $493.8
million ($1.06 per diluted unit) in 2006 and $445.4 million ($1.04 per diluted
unit) in 2005. We earned total revenues of $2,196.5 million and
58
$2,126.4 million, respectively, in the three month periods ended June 30, 2006
and 2005, and total revenues of $4,588.1 million and $4,098.3 million,
respectively, in the six month periods ended June 30, 2006 and 2005.
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. Our segment earnings before depreciation, depletion and
amortization expenses consist of our:
o revenues;
o earnings from equity investments;
o income taxes;
o allocable interest income; and
o other income items, net of other expense items;
less
o operating expenses, which include our natural gas purchases and other
costs of sales, operations and maintenance expenses, fuel and power
expenses and taxes, other than income taxes; and
o other operating expense (income) items.
We 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 second quarter of 2006 and 2005, our total
segment earnings before depreciation, depletion and amortization totaled $495.8
million and $430.7 million, respectively; for the comparable six month periods,
total segment earnings before depreciation, depletion and amortization totaled
$976.8 million in 2006 and $877.1 million in 2005.
Excluding the environmental and certain other items described in footnote
(a) in the table above and discussed following, our second quarter and
year-to-date 2006 segment earnings before depreciation, depletion and
amortization for our four business segments totaled $488.5 million for the
second quarter of 2006, up 13% from total segment earnings before depreciation,
depletion and amortization reported for the second quarter 2005. For the first
six months of 2006, total segment earnings before depreciation, depletion and
amortization, and the certain other items, totaled $969.5 million, up 11% from
total segment earnings before depreciation, depletion and amortization reported
for the same prior year period.
Environmental Matters and Certain Other Items
As described in footnote (a) in the table above, our second quarter and
year-to-date 2006 segment earnings before depreciation, depletion and
amortization included net earnings of $7.3 million from certain items occurring
in the second quarter of 2006. The items consisted of the following:
o a decrease of $17.9 million, related to additional environmental
expense associated with environmental liability adjustments and
refined petroleum products pipeline releases. The amount consisted of
two pieces. First, after a review of any potential environmental
issues that could impact our assets or operations and of our need to
correctly record all related environmental contingencies, we
recognized a decrease in earnings of $14.4 million, related to an
increase in environmental expense and in our accrued environmental and
related claim liabilities. Secondly, we recognized a decrease in
earnings of $3.5 million, related to our share of additional
environmental expense recognized by Plantation Pipe Line Company. The
expense was related to environmental and clean-up liability
adjustments associated with an April 17, 2006 pipeline release of
turbine
59
fuel from Plantation's 12-inch petroleum products pipeline located in
Henrico County, Virginia.
Our environmental expense of $17.9 million included a $14.9 million
expense recorded within "Operations and maintenance," a $4.9 million
expense recorded within "Earnings from equity investments," and a $1.9
million reduction in expense recorded within "Income Taxes" in our
accompanying consolidated statements of income for the three and six
months ended June 30, 2006. Combined, the $17.9 million increase in
environmental expense resulted in a $16.4 million increase in expense
to our Products Pipelines business segment and a $1.5 million increase
in expense to our Natural Gas Pipelines business segment. For more
information on environmental matters, see Note 3 to our consolidated
financial statements included elsewhere in this report;
o an increase of $15.1 million, related to the combined sale of our
Douglas natural gas gathering system and Painter Unit fractionation
facility. Effective April 1, 2006, we sold these assets 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 six
months ended June 30, 2006. For more information on this gain, see
Note 2 to our consolidated financial statements included elsewhere in
this report;
o an increase of $6.2 million, related to a reduction in a previously
established reserve for 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. We included the $6.2 million
reduction in the reserve within "Gas purchases and other costs of
sales" in our accompanying consolidated statements of income for the
three and six months ended June 30, 2006;
o an increase of $5.7 million, related to two separate contract
settlements from our petroleum transmix processing operations. 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.
We included the net income of $5.7 million from these two items within
"Other, net" in our accompanying consolidated statements of income for
the three and six months ended June 30, 2006; and
o a decrease of $1.8 million, due to a loss from ineffective cash flow
hedging of forecasted sales of crude oil by our CO2 business segment.
The hedge ineffectiveness resulted from differences between the
deliverable grade of crude oil specified in our derivative contracts,
on the one hand, and the deliverable grade of crude oil we expected to
sell, on the other hand. We included this ineffective loss as a
reduction to revenues and included the amount within "Product sales
and other" in our accompanying consolidated statements of income for
the three and six months ended June 30, 2006.
Declared Partnership Distributions
We declared a cash distribution of $0.81 per unit for the second quarter of
2006 (an annualized rate of $3.24). This distribution is almost 4% higher than
the $0.78 per unit distribution we made for the second 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.
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 $20 million in 2006. For
more information on our Pacific operations' regulatory proceedings, see Note 3
to our consolidated financial statements included elsewhere in this report.
60
Products Pipelines
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues...................................................... $ 189,021 $ 174,632 $ 369,547 $ 345,915
Operating expenses(a)......................................... (78,893) (57,070) (139,540) (109,126)
Earnings from equity investments(b)........................... 2,688 7,065 10,553 15,450
Interest income and Other, net-income (expense)(c)............ 7,229 1,372 8,435 2,663
Income taxes(d)............................................... (817) (2,737) (3,872) (6,038)
----------- ---------- ---------- ---------
Earnings before depreciation,depletion and amortization
expense and amortization of excess cost of
equity investments.......................................... 119,228 123,262 245,123 248,864
Depreciation, depletion and amortization expense.............. (20,479) (19,828) (40,721) (39,222)
Amortization of excess cost of equity investments............. (839) (836) (1,680) (1,680)
----------- ---------- ---------- ---------
Segment earnings............................................ $ 97,910 $ 102,598 $ 202,722 $ 207,962
=========== ========== ========== =========
Gasoline (MMBbl).............................................. 115.4 118.0 227.0 226.9
Diesel fuel (MMBbl)........................................... 39.3 40.8 78.0 81.0
Jet fuel (MMBbl).............................................. 29.9 29.4 59.4 58.8
----------- ---------- ---------- ---------
Total refined product volumes (MMBbl)....................... 184.6 188.2 364.4 366.7
Natural gas liquids (MMBbl)................................... 8.9 8.0 18.7 17.6
Total delivery volumes (MMBbl)(e)........................... 193.5 196.2 383.1 384.3
=========== ========== ========== =========
__________
(a) 2006 amounts include a $13,458 increase in expense associated with
environmental liability adjustments.
(b) 2006 amounts include a $4,861 increase in expense associated with
environmental liability adjustments on Plantation Pipe Line Company.
(c) 2006 amounts include a $5,700 increase in income from the settlement of
transmix processing contracts.
(d) 2006 amounts include 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 $119.2 million on revenues of $189.0 million in
the second quarter of 2006. This compares to earnings before depreciation,
depletion and amortization of $123.3 million on revenues of $174.6 million in
the second quarter of 2005. For the comparable six month periods, the segment
reported earnings before depreciation, depletion and amortization of $245.1
million on revenues of $369.5 million in 2006, and earnings before depreciation,
depletion and amortization of $248.9 million on revenues of $345.9 million in
2005.
As noted in the table above, and referred to above in
"-Consolidated--Environmental Matters and Certain Other Items," the segment's
2006 earnings included an expense of $16.4 million from the adjustment of
environmental liabilities and other income of $5.7 million from the settlement
of two separate transmix processing contracts. Excluding these two items,
segment earnings before depreciation, depletion and amortization expenses
totaled $129.9 million for the second quarter of 2006 and $255.8 million for the
first six months of 2006.
Segment Earnings before Depreciation, Depletion and Amortization
Excluding the effect of the two adjustments described above, our Products
Pipelines' segment earnings before depreciation, depletion and amortization
increased $6.6 million (5%) in the second quarter of 2006, and $6.9 million (3%)
in the first half of 2006, compared to the same prior year periods. Despite
relatively flat earnings across the comparable first quarter periods, the
segment was able to increase earnings before depreciation, depletion and
amortization expenses in the second quarter of 2006, relative to a year ago,
from strong performances from our Southeast terminal operations, our North
System, our Central Florida and Cypress pipelines, our Pacific operations, and
our equity interest in Plantation Pipe Line Company, all of which produced
improved results compared to the second quarter of 2005. Earnings from our
Transmix operations and our proportionate interest in the Cochin Pipeline
declined in the second quarter of 2006 versus the second quarter of 2005.
61
The segment's overall increases in segment earnings before depreciation,
depletion and amortization expenses (and excluding the above adjustments) for
the comparable three and six month periods primarily included the following
period-to-period increases and decreases:
o increases of $2.2 million (26%) and $3.1 million (20%), respectively,
from our Southeast products terminal operations--due primarily to
higher product inventory sales at higher average prices and to
incremental storage revenues from certain terminals acquired from
Charter Terminal Company and Charter-Triad Terminals in November 2004;
o increases of $2.2 million (63%) and $1.6 million (17%), respectively,
from our North System--due largely to higher throughput revenues and
higher natural gas liquids product gains in the second quarter of 2006
versus the second quarter of 2005;
o increases of $1.1 million (1%) and $3.1 million (2%), respectively,
from our combined West Coast refined petroleum products pipelines and
terminal operations, which include our Pacific operations, our CALNEV
Pipeline and our West Coast terminals.
The quarter-to-quarter increase in earnings before depreciation,
depletion and amortization expenses from these three operations was
driven by increases of $0.5 million (5%) from our West Coast terminal
operations and $0.4 million (1%) from our Pacific operations. The
increase from our West Coast terminals was primarily due to a $1.8
million (13%) increase in operating revenues, partially offset by
higher quarter-to-quarter operating expenses. The earnings increase
was driven by additional tankage at our Carson/Los Angeles Harbor
system terminals, overall higher product throughput, and higher rent
rates. The increase from our Pacific operations was largely due to
lower property tax expenses and higher administrative overhead
collected from recollectible capital projects. The decrease in
property tax expenses related to adjustments made to tax liability
accounts in May 2006, following a favorable ruling settling
differences over property valuations in the State of Arizona.
The increase in earnings for the comparable six month periods was
primarily due to a $2.2 million (10%) increase from our CALNEV
Pipeline operations and a $0.7 million (1%) increase from our Pacific
operations. The increase from CALNEV was mainly due to higher product
delivery revenues, driven by an over 7% increase in delivery volumes
and a 4% increase in average tariff rates. The higher volumes in 2006
were attributable to both strong demand, primarily from the Las Vegas,
Nevada market, and to service interruptions in the first quarter of
2005 resulting from adverse weather on the West Coast. The higher
tariffs were due to a Federal Energy Regulatory Commission tariff
index increase in July 2005 (producer price index-finished goods
adjustment). The increase from our Pacific operations was due
principally to the same factors that affected second quarter results,
as discussed above;
o increases of $0.9 million (11%) and $0.3 million (2%), respectively,
from our Central Florida Pipeline--due largely to higher refined
products transportation revenues in the second quarter of 2006,
compared to the second quarter a year ago. In the second quarter of
2006, total pipeline delivery revenues increased $1.2 million (12%)
compared to the second quarter of 2005. The increase was due to a 2%
increase in product delivery volumes and to a 10% increase in the
average tariff per barrel transported;
o an increase of $0.8 million (9%) in the comparable second quarter
periods from our approximate 51% ownership interest in Plantation Pipe
Line Company--due chiefly to higher operating fees. Earnings from our
investment in Plantation were flat across both six month periods, as
higher income from operating functions were offset by lower equity
earnings;
o decreases of $0.3 million (6%) and $0.3 million (3%), respectively,
from our 49.8% ownership interest in the Cochin pipeline system--due
primarily to lower transportation revenues caused by a drop in
ethylene delivery volumes. The decrease in delivery volumes was
primarily due to pipeline operating pressure restrictions. Total
delivery volumes on the Cochin Pipeline decreased 16% in the second
quarter of 2006 versus the second quarter of 2005; and
62
o decreases of $0.2 million (4%) and $0.9 million (8%), respectively,
from our petroleum pipeline transmix processing operations--due
primarily to lower revenues and higher fuel and power expenses in the
second quarter of 2006, compared to the second quarter last year.
On a year-to-date basis, total transmix processing volumes decreased
over 5% in 2006 versus 2005, largely due to a decrease at our
Indianola, Pennsylvania transmix facility. The higher expenses were
partly due to the start-up of our recently constructed transmix
facility located in Greensboro, North Carolina. In the second quarter
of 2006, we completed construction and placed into service the
approximately $11 million facility, which is capable of processing
6,000 barrels of transmix per day for Plantation and other interested
parties. In the second quarter of 2006, the Greensboro facility
accounted for incremental earnings before depreciation, depletion and
amortization of $0.2 million.
Segment Details
Revenues for the segment increased $14.4 million (8%) in the second quarter
of 2006 compared to the second quarter of 2005. For the comparable six month
periods, revenues increased $23.6 million (7%) in 2006 versus 2005.
The period-to-period increases in segment revenues for the comparable three
and six month periods of 2006 and 2005, respectively, were principally due to
the following:
o increases of $10.2 million (78%) and $9.2 million (33%), respectively,
from our Southeast terminals--largely attributable to higher product
inventory sales, as described above;
o increases of $1.8 million (13%) and $3.5 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 $1.0 million (7%) and $3.3 million (12%), respectively,
from our CALNEV Pipeline. The quarter-to-quarter increase was
primarily due to a $0.9 million (8%) increase in refined product
delivery revenues in the second quarter of 2006, compared to the
second quarter of 2005. The increase from product delivery revenues
was due to a 3% increase in transport volumes and a 4% increase in
average tariff rates. For the comparable six month periods, the $3.3
million increase in 2006 over 2005 consisted of a $2.6 million (12%)
increase in product delivery revenues and a $0.7 million (10%)
increase in product terminal revenues. The increase from product
deliveries was due to an over 7% increase in delivery volumes and an
over 4% increase in average tariff rates, due to a Federal Energy
Regulatory Commission tariff index increase in July 2005 (producer
price index-finished goods adjustment);
o increases of $1.2 million (12%) and $1.7 million (9%), respectively,
from our Central Florida Pipeline--driven by increases of 10% and 8%,
respectively, in the average tariff rates for the three and six month
periods of 2006 compared to 2005;
o increases of $1.2 million (15%) and $1.2 million (7%), respectively,
from our North System--due to higher natural gas liquids delivery
revenues in the second quarter of 2006. The increase was driven by an
over 3% increase in natural gas liquids delivery volumes and an 11%
increase in average tariffs. The tariff increase resulted from a
combination of an annual indexed tariff increase approved by the
Federal Energy Regulatory Commission (effective July 1, 2005), and an
increase in the proportion of volumes shipped at higher versus lower
tariffs offered on the North System;
o decrease of $0.2 million (0%) and increase of $5.2 million (3%),
respectively, from our Pacific operations. The quarter-to-quarter
decrease consisted of a $1.0 million (2%) decrease in refined product
delivery revenues and a $0.8 million (3%) increase in product terminal
revenues in the second quarter of 2006, compared to the second quarter
of 2005. The decrease from product delivery revenues was due to an
almost 2% decrease in mainline average tariff rates, reflecting the
impact of rate reductions that went into effect on May 1, 2006
according to settlements reached over our Pacific operations'
litigated rate case issues. Without this rate reduction, revenues from
our Pacific operations would have increased in the second quarter of
2006, relative to the second quarter of 2005.
63
For the comparable six month periods, the increase in revenues
consisted of a $2.5 million (2%) increase from mainline delivery
revenues and a $2.7 million (6%) increase in product terminal
revenues. The increase from product delivery revenues was due to an
almost 2% increase in mainline delivery volumes, and the increase from
terminal revenues was due to the higher transportation volumes and to
incremental service revenues, including diesel lubricity-improving
injection services that we began offering in May 2005;
o decreases of $1.2 million (13%) and $0.8 million (4%), respectively,
from our ownership interest in Cochin--attributable to the lower
transportation revenues, as described above;
Combining all of the segment's operations, total delivery volumes of
refined petroleum products decreased almost 2% in the second quarter of 2006,
compared to the second quarter of 2005. Excluding volumes delivered by
Plantation Pipe Line, combined deliveries of refined petroleum products were
essentially unchanged across both quarterly periods. In the second quarter of
2006, Plantation realized a 6.7% decrease in delivery volumes compared to the
second quarter of 2005, due to alternative pipeline service into Southeast
markets and to changes in supply from Louisiana and Mississippi refineries.
Compared to the second quarter of 2005, total deliveries of natural gas liquids
increased 11% in the second quarter of 2006, and quarter-to-quarter refined
product delivery volumes were up 3.5% and 1.9%, respectively, on our CALNEV and
Central Florida pipelines in 2006. Through the first six months of 2006, and
excluding Plantation volumes, total refined product delivery volumes for the
segment were up 1.4%, but segment gasoline delivery volumes were down 0.2%,
diesel volumes were up 2.8% and jet fuel volumes were up 5.2%.
Excluding the 2006 environmental liability adjustment, 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 $8.4 million (15%) and $17.0 million
(16%), respectively, in the second quarter and first half of 2006, compared to
the same year-ago periods. The overall increases in operating expenses for the
comparable three and six month periods were mainly due to the following:
o increases of $8.0 million (170%) and $6.1 million (50%), respectively,
from our Southeast terminals--largely attributable to higher ethanol
purchases (offset by higher ethanol revenues) and increased operating
and maintenance expenses associated with increased terminal
activities;
o increases of $1.1 million (22%) and $2.9 million (31%), respectively,
from our West Coast terminals--primarily related to incremental
environmental expenses, higher operating expenses related to increased
terminal activities, and higher electricity expenses due to increased
volumes and higher utility rates;
o increases of $0.9 million (24%) and $1.1 million (15%), respectively,
from our CALNEV Pipeline--due primarily to higher electricity
expenses, higher second quarter 2006 operating expenses, and
incremental environmental expense accruals. The increases in power
expenses related to increases in product delivery volumes and to
increases in average utility rates;
o increases of $0.4 million (20%) and $1.5 million (37%), respectively,
from our Central Florida Pipeline operations--due primarily to
environmental expenses in the first half of 2006 (expenses excluded
from the amounts referred to above in "-Consolidated--Environmental
Matters and Certain Other Items"), and to higher operating and
maintenance expenses associated with higher throughput volumes;
o decrease of $0.4 million (1%) and increase of $4.9 million (11%),
respectively, from our Pacific operations. The quarter-to-quarter
decrease was primarily due to lower property taxes in the second
quarter of 2006, described above, and to lower operating and
maintenance expenses due to higher second quarter 2005 expenses
associated with line wash-outs, repairs and environmental issues. The
increase in the first half of 2006 over the first half of 2005 was
largely due to higher fuel and power expenses in 2006, due to both
product delivery volume and utility rate increases, and to a utility
rebate credit received in the first quarter of 2005; and
o decreases of $0.7 million (17%) and $0.3 million (4%), respectively,
from our interest in the Cochin Pipeline--due to lower operating,
maintenance, and fuel and power expenses, all primarily related to the
decrease in transportation volumes in 2006 compared to 2005, as
discussed above.
64
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 that was included
in our November 2004 Charter products terminals acquisition. Excluding the
adjustment related to our share of Plantation's environmental expenses described
above, earnings from these investments increased $0.5 million (7%) in the second
quarter of 2006, when compared to the same period last year. Segment earnings
from equity investments were flat across the comparable six month periods. The
quarter-to-quarter increase was primarily due to a $0.4 million increase in
equity earnings from our investment in Heartland. Heartland's net income for the
second quarter of 2006 exceeded its net income for the second quarter of 2005
largely due to expenses, recognized in the second quarter of 2005, related to
refined products imbalance adjustments.
Excluding the $5.7 million other income item from the settlement of
transmix processing contracts in the second quarter of 2006, the segment's
income from both allocable interest income and other income and expense items
remained flat across both comparable three and six month periods.
Excluding the adjustment for the tax effect on Plantation's environmental
adjustment, the segment's income tax expenses were unchanged across the
comparable three month periods, but decreased $0.3 million (5%) in the first six
months of 2006, compared to 2005. The decrease was primarily due to the lower
pre-tax earnings from Plantation Pipe Line Company, due primarily to higher oil
loss expenses related to higher product prices, and lower transportation
revenues. Compared to the first half of 2005, Plantation's overall pipeline
deliveries of refined products declined 5% in 2006, due principally to warmer
than normal weather, and partly to incremental volumes being diverted to
competing pipelines.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of equity investments, increased $0.7 million (3%)
in the second quarter of 2006 and $1.5 million (4%) in the first half of 2006,
when compared to the same prior year periods. The quarter-to-quarter increase
was primarily due to higher expenses 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 second quarter of 2005.
In addition to higher depreciation from our Pacific operations, the $1.5 million
increase in the comparable six month periods includes incremental depreciation
charges from our Southeast terminal operations, related to additional
depreciation expense as a result of 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 June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues...................................................... $ 1,601,760 $ 1,616,657 $ 3,431,756 $ 3,089,549
Operating expenses and Other expense(a)....................... (1,461,960) (1,509,692) (3,159,726) (2,866,787)
Earnings from equity investments.............................. 10,609 8,598 21,771 17,028
Interest income and Other, net-income (expense)............... 47 562 499 479
Income taxes.................................................. 385 (1,081) 73 (1,538)
------------ ------------ ----------- -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments................................................. 150,841 115,044 294,373 238,731
Depreciation, depletion and amortization expense.............. (16,046) (15,816) (31,979) (30,574)
Amortization of excess cost of equity investments............. (70) (69) (139) (138)
------------ ------------ ----------- -----------
Segment earnings............................................ $ 134,725 $ 99,159 $ 262,255 $ 208,019
============ ============ =========== ===========
Natural gas transport volumes (Trillion Btus)(b).............. 345.7 307.1 682.5 645.1
============ ============ =========== ===========
Natural gas sales volumes (Trillion Btus)(c).................. 223.0 222.7 446.5 449.3
============ ============ =========== ===========
__________
(a) 2006 amounts include 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.
65
(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 $150.8 million on revenues of
$1,601.8 million in the second quarter of 2006. This compares to earnings before
depreciation, depletion and amortization of $115.0 million on revenues of
$1,616.7 million in the second quarter of 2005. For the six month periods ended
June 30, 2006 and 2005, the segment reported earnings before depreciation,
depletion and amortization of $294.4 million and $238.7 million, respectively,
and revenues of $3,431.8 million and $3,089.5 million, respectively.
As noted in the table above, and referred to above in
"--Consolidated--Environmental Matters and Certain Other Items," the segment's
2006 earnings included an expense of $1.5 million from the adjustment of our
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. Excluding these three
items, segment earnings before depreciation, depletion and amortization expenses
totaled $131.0 million for the second quarter of 2006 and $274.6 million for the
first six months of 2006.
Segment Earnings before Depreciation, Depletion and Amortization
Excluding the effect of the three adjustments described above, the
segment's $16.0 million (14%) increase in earnings before depreciation,
depletion and amortization in the second quarter of 2006 versus the second
quarter of 2005, and its $35.9 million (15%) increase in earnings before
depreciation, depletion and amortization in the first half of 2006 versus the
first half of 2005 were primarily related to the following changes:
o increases of $12.7 million (24%) and $28.9 million (25%),
respectively, from our Texas intrastate natural gas pipeline
group--due primarily to improved margins from 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;
o increases of $2.1 million (104%) and $3.8 million (73%), respectively,
from our Casper Douglas natural gas gathering and processing
operations--due mainly to increased natural gas sales, favorable gas
imbalance gains and higher commodity prices, net of hedges;
o increases of $1.9 million (26%) and $4.9 million (34%), respectively,
from our 49% equity investment in the Red Cedar Gathering Company--due
largely to higher prices on incremental sales of excess fuel gas and
by higher natural gas gathering revenues;
o increases of $1.8 million (20%) and $3.7 million (20%), respectively,
from our TransColorado Pipeline--due primarily to higher gas
transmission revenues, related to higher delivery volumes. The
increase in volumes resulted 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;
o an increase of $1.2 million (11%) and a decrease of $2.4 million (9%),
respectively, from our Trailblazer Pipeline--due to timing differences
on the settlements of pipeline transportation imbalances in each of
the first two quarters of 2006 versus the same periods of 2005. These
pipeline imbalances were due to differences between the volumes
nominated and volumes delivered at an inter-connecting point by the
pipeline; and
66
o decreases of $3.7 million (12%) and $3.0 million (6%), respectively,
from our Kinder Morgan Interstate Gas Transmission system--due largely
to favorable imbalance valuation adjustments recognized in the second
quarter of 2005.
Segment Details
Compared to the same two periods last year, total segment operating
revenues, including revenues from natural gas sales, decreased $14.9 million
(1%) in the second quarter of 2006, but increased $342.3 million (11%) in the
first six months of 2006. Similarly, excluding the effect of the three
adjustments described above, combined operating expenses, including natural gas
purchase costs and excluding the 2006 environmental and contract obligation
adjustments, decreased $27.9 million (2%) in the second quarter of 2006, and
increased $312.8 million (11%) in the first six months of 2006, when compared to
the same periods of 2005.
The period-to-period changes in segment revenues and segment operating
expenses were due mainly to the purchase and sales activities of our Texas
intrastate natural gas pipeline group, discussed above, and to the relative
changes in average natural gas prices, which decreased in the second quarter of
2006, relative to the second quarter of 2005, but increased in the first half of
2006, relative to the first half of 2005. Accordingly, revenues from the sales
of natural gas by our Texas Intrastate group decreased $15.9 million (1%) in the
second quarter of 2006 versus the second quarter of 2005, but increased $324.0
million (12%) in the first half of 2006 versus the first half of 2005;
similarly, the group's costs of sales, excluding the adjustment related to the
pipeline contract obligation adjustment, decreased $35.5 million (2%) in the
second quarter of 2006 versus the second quarter of 2005, but increased $294.1
million (11%) in the first half of 2006 versus the first half of 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
$2.0 million (23%) and $4.7 million (28%), respectively, in the second quarter
and first six 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.
The segment's interest income and earnings from other income items
decreased $0.5 million in the second quarter of 2006, compared to the second
quarter of 2005, but were flat across the comparable six month periods. The
quarter-to-quarter decrease was mainly due to higher gains, recognized in the
second quarter of 2005, from changes in the fair value of derivative contracts
used to hedge our Mier-Monterrey Mexico Pipeline's exposure to unfavorable
changes in foreign currency exchange rates.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased only slightly over both
comparable periods--$0.2 million (1%) in the second quarter and $1.4 million
(5%) in the first six months of 2006, when compared to the same periods last
year. The increases were largely due to incremental capital spending since June
2005, 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 June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues(a)................................................... $ 185,789 $ 162,029 $ 360,480 $ 325,192
Operating expenses(b)......................................... (66,715) (54,334) (125,324) (103,843)
Earnings from equity investments.............................. 5,075 7,151 10,733 16,399
Other, net-income (expense)................................... 11 (1) 12 -
Income taxes.................................................. (51) (67) (124) (112)
------------ ---------- ---------- ----------
Earnings before depreciation, depletion and amortization
Expense and amortization of excess cost of equity
investments................................................. 124,109 114,778 245,777 237,636
Depreciation, depletion and mortization expense(c)............ (42,018) (38,462) (81,290) (77,164)
Amortization of excess cost of equity investments............. (505) (504) (1,009) (1,008)
------------ ---------- ---------- ----------
Segment earnings............................................ $ 81,586 75,812 $ 163,478 $ 159,464
============ ========== ========== ==========
67
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
---- ---- ---- ----
Carbon dioxide delivery volumes (Bcf)(d)...................... 166.7 155.5 339.1 325.4
======== ========= ========= =========
SACROC oil production (gross) (MBbl/d)(e)..................... 30.8 32.5 31.0 33.1
======== ========= ========= =========
SACROC oil production (net) (MBbl/d)(f)....................... 25.6 27.0 25.9 27.6
======== ========= ========= =========
Yates oil production (gross)(MBbl/d)(e)....................... 26.2 24.0 25.6 24.0
======== ========= ========= =========
Yates oil production (net) (MBbl/d)(f)........................ 11.6 10.7 11.4 10.7
======== ========= ========= =========
Natural gas liquids sales volumes (net) (MBbl/d)(f)........... 9.0 9.3 9.2 9.5
======== ========= ========= =========
Realized weighted average oil price per Bbl(g)(h)............. $ 31.28 $ 27.39 $ 30.88 $ 28.10
======== ========= ========= =========
Realized weighted average natural gas liquids price
per Bbl(h)(i)................................................. $ 45.64 $ 35.40 $ 43.48 $ 34.67
======== ========= ========= =========
__________
(a) 2006 amounts include a $1,819 loss on derivative contracts used to
hedge forecasted crude oil sales.
(b) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(c) Includes depreciation, depletion and amortization expense associated
with oil and gas producing and gas processing activities in the amount
of $37,334 for the second quarter of 2006, $33,712 for the second
quarter of 2005, $71,924 for the first six months of 2006, and $68,025
for the first six months of 2005. Includes depreciation, depletion and
amortization expense associated with sales and transportation services
activities in the amount of $4,684 for the second quarter of 2006,
$4,750 for the second quarter of 2005, $9,366 for the first six months
of 2006, and $9,139 for the first six months of 2005.
(d) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and
Pecos pipeline volumes.
(e) 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.
(f) Net to Kinder Morgan, after royalties and outside working interests.
(g) Includes all Kinder Morgan crude oil production properties.
(h) Hedge gains/losses for oil and natural gas liquids are included with
crude oil.
(i) 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 second quarter of 2006, the segment reported earnings
before depreciation, depletion and amortization of $124.1 million on revenues of
$185.8 million. These amounts compare to earnings before depreciation, depletion
and amortization of $114.8 million on revenues of $162.0 million in the same
quarter last year. For the comparable six month periods, the segment reported
earnings before depreciation, depletion and amortization of $245.8 million on
revenues of $360.5 million in 2006, and earnings before depreciation, depletion
and amortization of $237.6 million on revenues of $325.2 million in 2005.
Segment Earnings before Depreciation, Depletion and Amortization
As noted in the table above, and referred to above in
"--Consolidated--Environmental Matters and Certain Other Items," second quarter
and year-to-date 2006 segment earnings before depreciation, depletion and
amortization included a charge of $1.8 million from a loss on derivative
contracts used to hedge forecasted crude oil sales. Excluding this item, segment
earnings before depreciation, depletion and amortization totaled $125.9 million
in the second quarter of 2006 and $247.6 million in the first six months of
2006.
Sales and Transportation Activities
For our CO2 segment, both the $11.1 million (10%) increase in earnings
before depreciation, depletion and amortization in the second quarter of 2006
over the second quarter of 2005 and the $10.0 million (4%) increase in the first
six months of 2006 over the first six months of 2005 (excluding the above
adjustment) 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 $7.5 million (19%) and $12.9
million (17%), respectively, in the second quarter and first half of 2006, when
compared to the same prior year periods. The increases were driven primarily by
higher revenues from carbon dioxide sales and crude oil pipeline transportation.
The period-to-period increases in carbon dioxide sales revenues were due to
higher average prices, largely attributable to continued strong demand for
carbon dioxide from tertiary oil recovery projects, which commonly
68
inject carbon dioxide into reservoirs adjacent to producing crude oil wells. The
carbon dioxide acts as both a pressurizing agent and, when dissolved into the
underground crude oil, mobilizes trapped oil and significantly reduces its
viscosity, enabling the oil to flow more easily to production wells.
Accordingly, carbon dioxide prices have correlated closely with the increase in
crude oil prices since the end of the second quarter of 2005. Also, during both
2006 and 2005, 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--an increase of $3.6 million (5%) in
the comparable three month periods and a decrease of $2.9 million (2%) in the
comparable six month periods, were attributable to the segment's oil and natural
gas producing activities, which also include its natural gas processing
activities.
The increase in earnings from oil and gas activities in the comparable
three month periods reflected an $18.9 million (14%) increase in revenues in
2006, relative to 2005, which more than offset a $15.3 million (26%) increase in
combined operating expenses. The quarterly earnings increase was driven by
strong oil production at the Yates oil field unit, partially offset by a
previously announced decline in oil production at the SACROC unit. On a gross
basis (meaning total quantity produced), average oil production increased 9%
quarter-over-quarter at Yates, but decreased 5% at the SACROC unit, where the
decline in production is mostly due to one section of the field that is
underperforming. In addition, in the second quarter of 2006, we benefited from
increases of 14% and 29%, respectively, in our realized weighted average price
of oil and natural gas liquids per barrel, as compared to the second quarter of
2005. For the comparable six month periods, our realized weighted average prices
of oil and natural gas liquids per barrel increased 10% and 25%, respectively.
The decrease in earnings from oil and gas activities in the comparable six
month periods was due to higher period-to-period combined operating expenses,
which more than offset corresponding revenue increases in both the second
quarter and the first six months of 2006. The increases in operating expenses
were due to higher field operating and maintenance expenses, higher property and
severance taxes, and higher fuel and power expenses. The increases in revenues
were primarily due to higher prices on the sales of both natural gas liquids and
crude oil.
With respect to crude oil, prices throughout the first half of 2006 have
remained at higher levels than the corresponding period in 2005. The higher
prices for natural gas liquids reflect favorable gas processing margins, which
is the relative difference in economic value (on an energy content basis)
between natural gas liquids as a separated liquid, on the one hand, and as a
portion of the residue natural gas stream, on the other hand.
Because our CO2 segment is exposed to market risks related to the price
volatility of crude oil and natural gas liquids, we mitigate this commodity
price risk through a long-term hedging strategy that involves the use of
derivative contracts as hedges to the exposure of fluctuating expected future
cash flows produced by unpredictable changes in crude oil and natural gas
liquids sales prices. The strategy is intended to generate more stable realized
prices, and 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. Had we not used energy derivative contracts to transfer
commodity price risk, our crude oil sale prices would have averaged $67.46 per
barrel in the second quarter of 2006, versus $50.95 per barrel in the second
quarter of 2005. For more information on our hedging activities, see Note 10 to
our consolidated financial statements included elsewhere in this report.
Finally, in our report on Form 10-Q for the quarter ended March 31, 2006,
we disclosed that we expected 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%. In the second quarter
of 2006, the segment was able to make up a significant portion of that projected
shortfall, and we now expect that our CO2 segment will fall approximately $20
million, or 4%, short of its 2006 budget of 16% growth in segment earnings
before depreciation, depletion and amortization. Currently, we expect to achieve
record annual carbon dioxide production volumes at the McElmo Dome source field
in 2006, we expect actual production from the Yates field unit to exceed its
annual budgeted production, and we expect that, compared to the first six months
of this year, production from the SACROC field will increase in the remaining
half of 2006.
69
Segment Details
Excluding the $1.8 million hedge ineffectiveness loss, our CO2 segment's
revenues increased $25.6 million (16%) and $37.1 million (11%) in the second
quarter and first six months of 2006, respectively, versus the same periods in
2005. The respective second quarter and year-to-date period-to-period increases
were primarily due to the following:
o increases of $13.8 million (15%) and $15.3 million (8%), respectively,
from crude oil sales--attributable to higher average sale prices,
partially offset by relatively flat period-to-period production
volumes;
o increases of $7.4 million (25%) and $12.3 million (21%), respectively,
from natural gas liquids sales--attributable to higher average prices
and partially offset by decreases in production primarily related to
the lower production at SACROC;
o increases of $3.5 million (28%) and $10.4 million (52%), respectively,
from carbon dioxide sales--due mainly to higher average sale prices,
discussed above, and to an almost 9% increase in sales volumes in the
second quarter of 2006 versus the second quarter last year;
o increases of $3.1 million (21%) and $4.3 million (15%), respectively,
from carbon dioxide and crude oil pipeline transportation
revenues--due largely to increases of 7% and 4%, respectively, in
carbon dioxide delivery volumes; and
o decreases of $4.2 million and $8.3 million, respectively, from natural
gas sales--attributable to lower volumes of gas available for sale in
the second quarter and first half of 2006 versus the same periods last
year, largely 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
third-party charges for the production of electrical energy at the
SACROC field and 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.
Compared to the same periods of 2005, the segment's operating expenses
increased $12.4 million (23%) in the second quarter of 2006 and $21.5 million
(21%) in the first six months of 2006. The increases consisted of the following:
o increases of $7.4 million (30%) and $12.7 million (26%), respectively,
from combined cost of sales and field operating and maintenance
expenses-- largely due to higher well workover and completion
expenses, including labor, related to infrastructure expansions at the
SACROC and Yates oil field units since the second quarter last year.
Workover expenses 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;
o increases of $3.2 million (30%) and $5.8 million (29%), respectively,
from taxes, other than income taxes (primarily both property and
production 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 second quarter of 2005; the higher
severance taxes, which are primarily based on the gross wellhead
production value of oil and natural gas, were driven by the higher
period-to-period crude oil revenues; and
o increases of $1.8 million (10%) and $3.0 million (8%), 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.
Earnings from the segment's equity investments, representing equity
earnings from our 50% ownership interest in the Cortez Pipeline Company,
decreased $2.1 million (29%) and $5.7 million (35%) in the second quarter and
70
first six months of 2006, respectively, versus the same periods in 2005. The
decreases reflect lower overall net income earned by Cortez, due primarily to
lower carbon dioxide transportation revenues as a result of lower average tariff
rates. 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 $3.6 million (9%) in
the second quarter and $4.1 million (5%) in first six months of 2006, when
compared to year-ago periods. The increases were due to higher depreciable
costs, related to incremental capital spending since June 2005, and to
incremental depreciation charges of $1.4 million attributable to the various
oil and gas properties we acquired in April 2006 from Journey Acquisition -
I, L.P. and Journey 2000, L.P.
Terminals
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
--------- ---------- --------- ----------
(In thousands, except operating statistics)
Revenues.............................................. $ 220,283 $ 173,037 $ 426,671 $ 337,631
Operating expenses(a)................................. (116,881) (91,736) (232,662) (177,152)
Earnings from equity investments...................... 78 24 114 33
Other, net-income (expense)........................... (98) 31 1,279 (1,179)
Income taxes.......................................... (1,801) (3,730) (3,852) (7,502)
--------- ---------- --------- ----------
Earnings before depreciation, depletion and
amortization expense and amortization of excess
cost of equity investments.......................... 101,581 77,626 191,550 151,831
Depreciation, depletion and amortization expense...... (18,686) (14,155) (35,960) (26,328)
Amortization of excess cost of equity investments..... - - - -
--------- ---------- --------- ----------
Segment earnings.................................... $ 82,895 $ 63,471 $ 155,590 $ 125,503
Bulk transload tonnage (MMtons)(b).................... 22.6 22.2 44.7 45.4
========= ========== ========= ==========
Liquids leaseable capacity (MMBbl).................... 43.5 37.3 43.5 37.3
========= ========== ========= ==========
Liquids utilization %................................. 96.6% 96.4% 96.6% 96.4%
========= ========== ========= ==========
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) 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 second quarter of 2006, our Terminals segment reported earnings before
depreciation, depletion and amortization of $101.6 million on revenues of $220.3
million. This compares to earnings before depreciation, depletion and
amortization of $77.6 million on revenues of $173.0 million in the second
quarter last year. For the first six months of 2006, our Terminals segment
reported earnings before depreciation, depletion and amortization of $191.6
million on revenues of $426.7 million, while in the same period of 2005, the
segment reported earnings before depreciation, depletion and amortization of
$151.8 million on revenues of $337.6 million.
Segment Earnings before Depreciation, Depletion and Amortization
Our terminal acquisitions since the second quarter 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;
71
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
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 second quarter of
2005 accounted for incremental amounts of earnings before depreciation,
depletion and amortization of $13.0 million, revenues of $28.2 million and
operating expenses of $15.2 million, respectively, in the second quarter of
2006, and incremental amounts of earnings before depreciation, depletion and
amortization of $28.0 million, revenues of $56.9 million and operating expenses
of $28.9 million, respectively, in the first six months of 2006, when compared
to the same periods a year ago.
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. 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. The TGS acquisition made us the largest independent
handler of petroleum coke in the United States. Including increases from the
additional month of ownership in the second quarter of 2006 as well as increases
from the same two months we owned the assets during both years, the petroleum
coke terminal operations we acquired from TGS accounted for incremental amounts
of earnings before depreciation, depletion and amortization of $6.6 million,
revenues of $14.9 million and operating expenses of $8.3 million, respectively,
in the second quarter of 2006, when compared to the second quarter of 2005. For
the comparable six month periods, the assets accounted for incremental amounts
of earnings before depreciation, depletion and amortization of $19.5 million,
revenues of $38.3 million and operating expenses of $18.8 million, respectively,
in the first six months of 2006, when compared to the same period of 2005.
For all other terminal operations (those owned during both six month
periods), earnings before depreciation, depletion and amortization increased
$11.0 million (15%) in the second quarter of 2006 versus the second quarter of
2005, and increased $11.8 million (8%) in the first six months of 2006 versus
the first six months of 2005. The overall changes in three and six month
earnings from terminals owned during both years included the following:
o increases of $2.0 million (11%) and $4.5 million (12%), respectively,
from our Pasadena and Galena Park, Texas Gulf Coast liquids
facilities--due to higher revenues from new customer agreements,
higher truck loading rack service fees, and additional liquids tank
capacity from capital expansions at our Pasadena terminal;
o increases of $1.5 million (18%) and $2.8 million (16%), respectively,
from our liquids terminal located in Carteret, New Jersey--due to
higher revenues from new and renegotiated customer contracts and from
increased petroleum imports to New York Harbor;
o increases of $1.4 million (83%) and $2.2 million (66%), respectively,
from our Shipyard River terminal, located in Charleston, South
Carolina--largely due to higher revenues from increased cement
volumes, tank rentals and ancillary terminal services;
o increases of $1.3 million (42%) and $1.2 million (19%), respectively,
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 $1.0 million (404%) and $2.3 million (148%),
respectively, from our bulk terminal located in Fairless Hills,
Pennsylvania--due to higher volumes of steel imports and heavier
shipping activity on the Delaware River;
72
o increases of $1.0 million (28%) and $0.5 million (7%), respectively,
from our Materials Services (rail transloading) region--mainly due to
overall higher railcar activity and higher revenues from incremental
ethanol transfers along the East Coast;
o an increase of $0.8 million (203%) and a decrease of $1.5 million
(155%), respectively, 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 quarter-to-quarter
increase in earnings was primarily due to higher terminal tonnage,
higher dockage and fleeting revenues, and incremental business
insurance revenues. The decrease in earnings in the comparable six
month periods was largely due to higher expenses, including higher
demurrage and shipping-related charges, incremental expenses related
to Hurricane-related liability adjustments, and higher fuel costs;
o increases of $0.7 million (40%) and $1.4 million (42%), respectively,
from our Port Sutton, Florida bulk terminal--due primarily to higher
stevedoring and transfer revenues associated with an increase in the
number of inbound vessels and barge unloadings; and
o an increase of $0.5 million (40%) and a decrease of $1.1 million
(26%), respectively, from our Chesapeake Bay, Maryland bulk terminal.
The quarter-to-quarter increase in earnings was primarily due to lower
operating expenses in the first quarter of 2006, due to lower tonnage
and lower rental expenses. The year-to-date decrease in earnings was
largely due to lower revenues in 2006 versus 2005, due to lower
petroleum coke and steel coil transfers.
Segment Details
Segment revenues for all terminals owned during both years increased $19.1
million (12%) in the second quarter of 2006, and $32.2 million (10%) in the
first six months of 2006, when compared to the same prior-year periods. The
overall changes in three and six month revenues from terminals owned during both
years included the following:
o increases of $5.8 million (28%) and $10.3 million (23%), respectively,
from our Mid-Atlantic region, due primarily to higher steel volumes at
our Fairless Hills terminal, and to higher tank rentals and cement and
petroleum coke volumes at our Shipyard River terminal;
o increases of $3.4 million (105%) and $6.7 million (100%),
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 (10%) and $6.1 million (12%), respectively,
from our Pasadena and Galena Park Gulf Coast facilities, as discussed
above;
o increases of $2.1 million (7%) and $3.6 million (6%), respectively,
from terminals included in our Lower Mississippi (Louisiana) region,
due largely to higher higher tonnage, dockage and insurance revenues
at our IMT facility, incremental revenues from our Amory, Mississippi
bulk terminal, which began operations in July 2005, and higher bulk
transfer revenues from our DeLisle, Mississippi terminal; and
o increases of $1.1 million (4%) and $1.1 million (2%), respectively,
from terminals included in our Midwest region, due largely to
increased liquids throughput and storage activities from our two
Chicago liquids terminals, higher coal transfer volumes from our Cora,
Illinois coal terminal, and higher marine oil fuel sales from our
Dravosburg, Pennsylvania bulk terminal.
Operating expenses for all terminals owned during both periods increased
$9.9 million (11%) in the second quarter of 2006, and $26.6 million (15%) in the
first half of 2006, when compared to the same periods last year. The overall
changes in three and six month operating expenses from terminals owned during
both years included the following:
73
o increases of $3.8 million (124%) and $7.4 million (117%),
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 $2.5 million (18%) and $5.3 million (19%), respectively,
from our Mid-Atlantic terminals, largely due to higher operating and
maintenance expenses at our Fairless Hills terminal and at our Pier IX
bulk terminal, located in Newport News, Virginia. The increases at
Fairless Hills was largely due to higher wharfage, trucking and
general maintenance expenses related to the increase in steel products
handled, the increases at Pier IX related to major maintenance repairs
and to higher expenses related to a fire that occurred at the terminal
in June 2006;
o increases of $0.8 million (4%) and $5.7 million (15%), respectively,
from our Louisiana terminals, largely due to property damage,
demurrage and other expenses, which in large part relate to the
effects of hurricanes Katrina and Rita, both of which impacted the
Gulf Coast since the end of the second quarter of 2005;
o increases of $0.8 million (26%) and $0.1 million (1%), respectively,
from our West region terminals, due to higher labor and port fees
associated with increased tonnage at our Longview, Washington terminal
in the second quarter of 2006;
o increases of $0.5 million (7%) and $1.7 million (12%), respectively,
from our Pasadena and Galena Park Gulf Coast liquids terminals, due to
incremental labor expenses, power expenses and permitting fees; and
o increases of $0.3 million (4%) and $1.3 million (11%), respectively,
from terminals in our Southeast region, due primarily to higher labor
and equipment maintenance at our Port Sutton, Florida and Elizabeth
River, Virginia bulk terminals, due to increased business activity in
2006 relative to 2005.
The segment's earnings from equity investments and other income items
remained essentially flat across both comparable periods. Income tax expenses
decreased $1.9 million (52%) and $3.7 million (49%) in the second quarter and
first six months of 2006, respectively, compared to the same periods a year-ago.
The quarter-to-quarter decrease was primarily due to a $1.8 million reduction in
expense associated with a June 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. In addition to this reserve
reversal, the decrease in segment income tax expenses in the first half of 2006,
relative to the first half of 2005, resulted from lower combined taxable
earnings from all tax-paying terminal entities.
Compared to the same periods in 2005, non-cash depreciation, depletion and
amortization charges increased $4.5 million (32%) in the second quarter of 2006,
and $9.6 million (37%) in the first six months of 2006. In addition to increases
associated with normal capital spending, the periodic increase reflected higher
depreciation charges due to the terminal acquisitions we have made since the
second quarter of 2005. Collectively, these acquired terminal assets, listed
above, accounted for incremental depreciation expenses of $2.8 million and $7.0
million, respectively, in the second quarter and first half of 2006, when
compared to the same periods of 2005.
Other
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
---- ---- ---- ----
(In thousands-income/(expense))
General and administrative expenses.................. $ (63,336) $ (50,133) $(124,219) $(123,985)
Unallocable interest, net............................ (83,226) (66,627) (160,193) (126,674)
Minority interest.................................... (3,493) (2,454) (5,863) (4,842)
Interest and corporate administrative expenses..... $(150,055) $(119,214) $(290,275) $(255,501)
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.
74
Our total general and administrative expenses increased $13.2 million (26%)
in the second quarter of 2006, when compared to the second quarter of 2005. The
increase was primarily due to higher period-to-period corporate insurance
expenses, corporate service charges, and employee benefit costs. The increase in
insurance expenses was partly due to incremental expenses related to the
cancellation of certain commercial insurance polices in the second quarter of
2006, as well as to the overall variability in year-to-year commercial property
and medical insurance costs. Pursuant to certain provisions that gave us the
right to cancel the policies prior to maturity, we took advantage of the
opportunity to reinsure at lower rates. The increase in corporate overhead costs
was due in part to spending associated with new acquisitions made since the
second quarter of 2005, as well as to a general trend of higher wage and benefit
costs that is influenced by changes in workforce and compensation levels, and
the achievement of incentive compensation targets.
For the first six months of 2006, our general and administrative expenses
remained essentially flat when compared to the same prior year period. In the
first half of 2006, higher administrative expenses, due principally to the same
factors that affected second quarter results, were largely offset by lower
unallocated litigation and environmental settlement expenses. In the first half
of 2005, we recognized litigation and environmental settlement expenses of $30.4
million, consisting of the following:
o 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;
o an $8.4 million expense related to settlements of environmental
matters at certain of our operating sites located in the State of
California; and
o a $3.0 million decrease in expense related to favorable settlements of
obligations that Enron Corp. had to us in conjunction with derivatives
we were accounting for as hedges under Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities."
Unallocable interest expense, net of interest income, increased $16.6
million (25%) and $33.5 million (26%), respectively, in the second quarter and
first six months of 2006, compared to the same year-earlier periods. The
increases were due to both higher average borrowings and higher effective
interest rates.
Our average debt levels for the first half of 2006 increased 10% versus the
first half of 2005, mainly due to higher capital spending and to the acquisition
of external assets and businesses since the end of the second quarter of 2005.
Our capital spending (including payments for pipeline project construction
costs) and acquisition outlays were funded by our commercial paper borrowings.
Additionally, for the comparable six 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 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 increases in our average borrowing rates reflect a general rise in
variable interest rates since the end of the second quarter of 2005. The
weighted average interest rate on all of our borrowings increased 8% and 10%,
respectively, in the second quarter and first six months of 2006, compared to
the same prior year periods. 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, increased $1.0 million in both the second quarter and first six months of
2006, compared to the same periods a
75
year ago. The increases were 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. For the six months ended 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 60% equity and 40% 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):
June 30, December 31,
------------ ------------
2006 2005
------------ ------------
Long-term debt, excluding market value of interest
rate swaps......................................... $ 4,642,890 $ 5,220,887
Minority interest.................................. 39,846 42,331
Partners' capital, excluding accumulated other
comprehensive loss................................. 4,668,301 4,693,414
------------ ------------
Total capitalization............................. 9,351,037 9,956,632
Short-term debt, less cash and cash equivalents.... 1,072,282 (12,108)
------------ ------------
Total invested capital........................... $ 10,423,319 $ 9,944,524
============ ============
Capitalization:
Long-term debt, excluding market value of interest
rate swaps....................................... 49.7% 52.4%
Minority interest................................ 0.4% 0.4%
Partners' capital, excluding accumulated other
comprehensive loss.............................. 49.9% 47.2%
------------ ------------
100.0% 100.0%
============ ============
Invested Capital:
Total debt, less cash and cash equivalents and
excluding Market value of interest rate swaps.. 54.8% 52.4%
Partners' capital and minority interest, excluding
accumulated other comprehensive loss........... 45.2% 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 borrowings
under our credit facilities, 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.
76
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, including total
debt to total capital. 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 $1.6 billion five-year senior unsecured revolving credit facility
that matures August 18, 2010;
o our $250 million nine-month unsecured revolving credit facility that
matures November 21, 2006;
o our $1.85 billion short-term commercial paper program (which is
supported by our two bank credit facilities, with the amount available
for borrowing under our credit facilities being reduced by our
outstanding commercial paper borrowings); and
o cash from operations (discussed following).
Borrowings under our two credit facilities can be used for general
corporate purposes and as a backup for our commercial paper program. There were
no borrowings under our five-year credit facility as of December 31, 2005, and
there were no borrowings under either credit facility as of June 30, 2006.
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 two bank credit facilities was $321.3 million as of June 30, 2006. As
of June 30, 2006, our outstanding short-term debt was $1,105.0 million.
Currently, we believe our liquidity to be adequate.
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.
77
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 revolving credit facilities 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 June 30, 2006, our total liability balance due on the various series
of our senior notes was $4,490.1 million, and the total liability balance due on
the long-term borrowings of our operating partnerships and subsidiaries was
$162.3 million. For additional information regarding our debt and credit
facilities, 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 $531.4 million for the six
months ended June 30, 2006, versus $588.2 million in the comparable period of
2005. The period-to-period decrease of $56.8 million (10%) in cash flow from
operations consisted of:
o a $144.6 million decrease in cash inflows relative to net changes in
working capital items--mainly due to timing differences that resulted
in higher cash outflows with regard to our net accounts payables and
receivables, and to higher payments for natural gas and carbon dioxide
imbalance settlements, pipeline rights-of-way and short-term natural
gas storage;
o a $62.5 million increase in cash from overall higher partnership
income--net of non-cash items including depreciation charges,
undistributed earnings from equity investments, gains from the sale of
assets, and litigation and environmental expenses that impacted
earnings but not cash. The higher partnership income reflects the
increase in cash earnings from our four reportable business segments
in the first six months of 2006, as discussed above in "-Results of
Operations";
o a $13.3 million increase related to higher distributions received from
equity investments--chiefly due to higher distributions received from
Red Cedar Gathering Company in the first six months of 2006. The
increase in distributions received from Red Cedar resulted from higher
year-over-year net income in the first half of 2006 versus the first
half of 2005, and also from the fact that Red Cedar had higher capital
expansion spending in the first half of 2005, and funded a large
portion of the expenditures with retained cash; and
o a $12.0 million increase in cash inflows relative to net changes in
non-current assets and liabilities--represents offsetting changes in
cash from various long-term asset and liability accounts, but on a net
basis, reflects $11.9 million in property tax refunds received in the
second quarter of 2006 from various counties in the State of Arizona.
The refunds resulted from successful litigation, ending in December
2005, 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.
78
Investing Activities
Net cash used in investing activities was $940.1 million for the six month
period ended June 30, 2006, compared to $586.8 million in the comparable 2005
period. The $353.3 million (60%) increase in cash used in investing activities
was primarily attributable to:
o a $219.6 million (64%) increase in capital expenditures--including
expansion and maintenance projects, our capital expenditures were
$561.2 million in the first half of 2006, compared to $341.6 million
in the same prior-year period. The increase was largely driven by
higher spending on natural gas pipeline and natural gas storage
expansion projects. Our sustaining capital expenditures were $60.7
million for the first six months of 2006, compared to $53.0 million
for the first six months of 2005. Sustaining capital expenditures are
defined as capital expenditures which do not increase the capacity of
an asset. Our forecasted expenditures for the second half of 2006 for
sustaining capital expenditures are approximately $106.0 million. This
amount has been committed primarily for the purchase of plant and
equipment. All of our capital expenditures, with the exception of
sustaining capital expenditures, are discretionary;
o a $172.5 million (89%) increase due to higher expenditures made for
strategic business acquisitions--in the first half of 2006, our
acquisition outlays totaled $365.8 million, which primarily consisted
of $244.6 million for the acquisition of Entrega Gas Pipeline LLC,
$61.6 million for the acquisition of bulk terminal operations, and
$58.7 million for the purchase of additional oil and gas properties.
In the first six months of last year, we spent $193.3 million, which
primarily included $183.8 million for the acquisition of Texas Petcoke
terminal assets from Trans-Global Solutions, Inc., and $6.2 million
for the acquisition of our 64.5% gross working interest in the
Claytonville oil field unit located in West Texas;
o a $6.1 million (19%) increase due to higher payments for margin and
restricted deposits--including a $13.5 million payment 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. Although the FERC has not yet formally approved
the settlement, we believe final approval will be received by the end
of 2006;
o a $39.3 million decrease 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 by
the $42.5 million we received from Momentum Energy Group, LLC for the
combined sale of our Douglas natural gas gathering system and Painter
Unit fractionation facility in the second quarter of 2006; and
o a $7.7 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 half of this year relative to the first half of
last year.
In addition, we recently made the following announcements related to our
investing activities:
o On June 1, 2006, we announced that we had completed and fully placed
into service our $210 million expansion of our Pacific operations'
East Line pipeline segment. The completion of the project included the
construction of a new pump station, a 490,000 barrel tank facility
near El Paso, Texas, and upgrades to existing stations and terminals
between El Paso and Phoenix, Arizona. Initially proposed in October
2002, the expansion also includes the replacement of 160 miles of
8-inch diameter pipe between El Paso and Tucson, Arizona, and 84 miles
of 8-inch diameter pipe between Tucson and Phoenix with new
state-of-the-art 12-inch and 16-inch diameter pipe, respectively. We
announced the completion of the pipeline portion of the project on
April 19, 2006, and new transportation tariffs designed to recover
construction costs of the expansion went into effect June 1, 2006.
In addition, we continue working on our second East Line expansion
project, which we announced on August 4, 2005. This second expansion
consists of replacing approximately 140 miles of 12-inch diameter pipe
between El Paso and Tucson with 16-inch diameter pipe, constructing
additional pump stations, and adding new storage tanks at Tucson. The
project is expected to cost approximately $145 million. We are
currently
79
working on engineering design and obtaining necessary pipeline
permits, and construction is expected to begin in May 2007. The
project, scheduled for completion in the fourth quarter of 2007, will
increase East Line capacity by another 8% and will provide the
platform for further incremental expansions through horsepower
additions to the system;
o On June 8, 2006, we announced an approximate $76 million expansion
project that will significantly increase capacity at our North Dayton,
Texas natural gas storage facility. The project involves the
development of a new underground cavern that will add an estimated 5.5
billion cubic feet of incremental working natural gas storage
capacity. Currently, two existing storage caverns at the facility
provide approximately 4.2 billion cubic feet of working gas capacity.
Our North Dayton natural gas storage facility is connected to our
Texas Intrastate natural gas pipeline system, and the expansion will
greatly enhance storage options for natural gas coming from new and
growing supply areas located in East Texas and from liquefied natural
gas along the Texas Gulf Coast. Drilling for the third cavern began in
late-June 2006, and the additional capacity is expected to be
available in the spring of 2009 after the cavern is completed to its
target size; and
o On June 21, 2006, we announced that we will begin construction this
summer on a new $133 million crude oil tank farm located in Edmonton,
Alberta, Canada, located slightly north of KMI's Trans Mountain
Pipeline crude oil storage facility. In addition, we have entered into
long-term contracts with customers for all of the available capacity
at the facility, with options to extend the agreements beyond the
original terms. Situated on approximately 24 acres, the new storage
facility will have nine tanks with a combined storage capacity of
approximately 2.2 million barrels for crude oil. Service is expected
to begin in the third quarter of 2007, and when completed, the tank
farm will serve as a premier blending and storage hub for Canadian
crude oil. The tank farm will have access to more than 20 incoming
pipelines and several major outbound systems, including a connection
with KMI's 710-mile Trans Mountain Pipeline system, which currently
transports up to 225,000 barrels per day of heavy crude oil and
refined products from Edmonton to marketing terminals and refineries
located in the greater Vancouver, British Columbia area and Puget
Sound in Washington state.
Financing Activities
Net cash provided by financing activities amounted to $429.2 million for
the six months ended June 30, 2006. For the same six month period last year, our
financing activities provided net cash of $36.3 million. The $392.9 million
increase in cash inflows provided by financing activities was primarily due to:
o a $418.1 million increase from overall debt financing
activities--which include our issuances and payments of debt and our
debt issuance costs. The increase was primarily due to a $715.7
million increase from higher net commercial paper borrowings in the
first half of 2006. The increase 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. Effective June 30, 2006, West2East Pipeline LLC
(and its subsidiary Rockies Express Pipeline, LLC) was deconsolidated
and will subsequently be accounted for under the equity method of
accounting. Generally accepted accounting principles require us to
include its cash inflows and outflows in our consolidated statement of
cash flows for the six months ended June 30, 2006; however, following
the change to the equity method, Rockies Express' debt balances are
not included in our consolidated balance sheet as of June 30, 2006.
The overall increase from debt financings activities was partly offset
by a $294.4 million decrease due to net changes in the principal
amount of senior notes outstanding. On March 15, 2005, we 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 their ownership interest in Rockies
Express Pipeline LLC. In the first quarter of 2006, Sempra contributed
$80.0 million for its original 33 1/3% share of the purchase price of
Entrega Pipeline LLC;
80
o a $45.6 million increase from net changes in cash book
overdrafts--which represent checks issued but not yet endorsed; and
o a $174.9 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 $631.1 million in the first half of 2006, compared to $456.2
million in the first half of 2005. The overall increase in
period-to-period distributions included incremental minority interest
distributions of $105.2 million paid from our Rockies Express Pipeline
LLC subsidiary to Sempra Energy in the second quarter 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. 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, our overall
distributions increased $69.7 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.
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.
81
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 May 15, 2006, we paid a quarterly distribution of $0.81 per unit for the
first quarter of 2006. This distribution was 7% greater than the $0.76
distribution per unit we paid in May 2005 for the first 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 May 15, 2006 to our general partner (for the first quarter of
2006) was $128.3 million. Our general partner's incentive distribution that we
paid in May 2005 to our general partner (for the first quarter of 2005) was
$111.1 million. Our general partner's incentive distribution for the
distribution that we declared for the second quarter of 2006 was $129.0 million.
Our general partner's incentive distribution for the distribution that we
declared for the second quarter of 2005 was $115.7 million.
Litigation and Environmental
As of June 30, 2006, we have recorded a total reserve for environmental
claims, without discounting and without regard to anticipated insurance
recoveries, in the amount of $68.4 million. In addition, we have recorded a
receivable of $31.7 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 June 30, 2006, we have recorded a total reserve for
legal fees, transportation rate cases and other litigation liabilities in the
amount of $133.7 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.
82
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 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, 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;
83
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;
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.
84
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, 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. 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 June 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, 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 June 30, 2006 that has
materially affected, or is reasonably likely to materially affect, our internal
control over financial reporting.
85
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 May 29, 2006, KMI announced that its board of directors had received a
proposal from investors led by Richard D. Kinder, Chairman and CEO of KMI, to
acquire all of the outstanding shares of KMI for $100 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, while the
proposal is outstanding, our senior management's attention may be diverted from
the management of our daily operations. KMI's announcement stated that its board
of directors had formed a special committee to consider the proposal, and KMI
subsequently announced that the committee had retained independent financial
advisors and legal counsel to assist it in its work. In response to the
proposal, Moody's Investor Services placed both our long-term and short-term
debt ratings under review for possible downgrade. Standard & Poor's put our
long-term debt rating on credit watch with negative implications. There can be
no assurance that any definitive offer will be made, that any agreement will be
executed, or that the management proposal or any other transaction will be
approved or consummated. Accordingly, no assurance can be given that the
consummation of any particular transaction will not result in substantially more
debt at KMI and 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 to
furnish supplementally to the Securities and Exchange Commission a
copy of each such instrument upon request.
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.
86
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.
__________
* Asterisk indicates exhibits incorporated by reference as indicated; all
other exhibits are filed herewith, except as noted otherwise.
87
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: August 7, 2006