F O R M 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2005
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 1-11234
KINDER MORGAN ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0380342
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
500 Dallas Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-369-9000
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X] No [ ]
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 154,403,326 common units outstanding as of October 26, 2005.
1
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
PART I. FINANCIAL INFORMATION
Item 1: Financial Statements (Unaudited)...................................................................... 3
Consolidated Statements of Income - Three and Nine Months Ended September 30, 2005 and 2004....... 3
Consolidated Balance Sheets - September 30, 2005 and December 31, 2004............................ 4
Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2005 and 2004............. 5
Notes to Consolidated Financial Statements........................................................ 6
Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations................. 55
Critical Accounting Policies and Estimates........................................................ 55
Results of Operations............................................................................. 55
Financial Condition............................................................................... 70
Information Regarding Forward-Looking Statements.................................................. 76
Item 3: Quantitative and Qualitative Disclosures About Market Risk............................................ 78
Item 4: Controls and Procedures............................................................................... 78
` PART II. OTHER INFORMATION
Item 1: Legal Proceedings..................................................................................... 79
Item 2: Unregistered Sales of Equity Securities and Use of Proceeds........................................... 79
Item 3: Defaults Upon Senior Securities....................................................................... 79
Item 4: Submission of Matters to a Vote of Security Holders................................................... 79
Item 5: Other Information..................................................................................... 79
Item 6: Exhibits.............................................................................................. 79
Signature............................................................................................. 81
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Unit Amounts)
(Unaudited)
Three Months Ended Nine Months Ended
September 30 September 30,
2005 2004 2005 2004
--------- --------- ----------- ---------
Revenues
Natural gas sales............................................ $ 1,975,583 $ 1,485,585 $ 4,820,732 $ 4,261,372
Services..................................................... 470,469 389,794 1,369,496 1,142,215
Product sales and other...................................... 185,202 139,280 539,313 390,510
--------- --------- --------- ---------
2,631,254 2,014,659 6,729,541 5,794,097
--------- --------- --------- ---------
Costs and Expenses
Gas purchases and other costs of sales....................... 1,970,579 1,475,241 4,795,923 4,231,876
Operations and maintenance................................... 156,486 116,807 448,621 347,396
Fuel and power............................................... 44,951 39,109 132,329 110,621
Depreciation, depletion and amortization..................... 85,356 72,214 258,644 209,623
General and administrative................................... 47,073 37,816 171,058 125,527
Taxes, other than income taxes............................... 28,198 20,636 80,249 59,712
--------- --------- --------- ---------
2,332,643 1,761,823 5,886,824 5,084,755
--------- --------- --------- ---------
Operating Income............................................... 298,611 252,836 842,717 709,342
Other Income (Expense)
Earnings from equity investments............................. 20,512 20,645 69,422 61,723
Amortization of excess cost of equity investments............ (1,407) (1,394) (4,233) (4,182)
Interest, net................................................ (68,348) (46,365) (192,387) (140,178)
Other, net................................................... 2,880 149 2,208 403
Minority Interest.............................................. (1,806) (2,789) (6,648) (7,332)
--------- --------- --------- ---------
Income Before Income Taxes..................................... 250,442 223,082 711,079 619,776
Income Taxes................................................... (5,055) (5,740) (20,245) (15,462)
---------- ---------- ---------- ----------
Net Income..................................................... $ 245,387 $ 217,342 $ 690,834 $ 604,314
========= ========= ========= =========
General Partner's interest in Net Income........................ $ 122,744 $ 100,320 $ 351,724 $ 287,851
Limited Partners' interest in Net Income....................... 122,643 117,022 339,110 316,463
--------- --------- --------- ---------
Net Income..................................................... $ 245,387 $ 217,342 $ 690,834 $ 604,314
========= ========= ========= =========
Basic Limited Partners' Net Income per Unit ................... $ 0.58 $ 0.59 $ 1.61 $ 1.62
========= ========= ========= =========
Diluted Limited Partners' Net Income per Unit ................. $ 0.57 $ 0.59 $ 1.61 $ 1.62
========= ========= ========= =========
Weighted average number of units used in computation of Limited Partners' Net
Income per unit:
Basic.......................................................... 213,192 196,854 210,001 195,112
========= ========= ========= =========
Diluted........................................................ 213,496 196,937 210,199 195,196
========= ========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
3
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
September 30, December 31,
ASSETS 2005 2004
---- ----
Current Assets
Cash and cash equivalents................................ $ - $ -
Restricted deposits...................................... - -
Accounts, notes and interest receivable, net
Trade................................................. 1,001,060 739,798
Related parties....................................... 5,041 12,482
Inventories
Products.............................................. 25,173 17,868
Materials and supplies................................ 12,330 11,345
Gas imbalances
Trade................................................. 17,593 24,653
Related parties....................................... - 980
Other current assets..................................... 214,117 46,045
----------- -----------
1,275,314 853,171
Property, Plant and Equipment, net......................... 8,693,661 8,168,680
Investments................................................ 410,896 413,255
Notes receivable
Trade.................................................... 1,944 1,944
Related parties.......................................... 110,126 111,225
Goodwill................................................... 786,038 732,838
Other intangibles, net..................................... 210,565 15,284
Deferred charges and other assets.......................... 336,105 256,545
----------- -----------
Total Assets............................................... $11,824,649 $10,552,942
=========== ===========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts.................................. $ 36,648 $ 29,866
Trade................................................. 917,971 685,034
Related parties....................................... 6,408 16,650
Current portion of long-term debt........................ - -
Accrued interest......................................... 39,886 56,930
Accrued taxes............................................ 66,798 26,435
Deferred revenues........................................ 12,876 7,825
Gas imbalances
Trade................................................. 24,409 32,452
Related parties....................................... 708 -
Accrued other current liabilities........................ 738,134 325,663
----------- -----------
1,843,838 1,180,855
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding........................................... 5,187,273 4,722,410
Market value of interest rate swaps................... 115,053 130,153
------------ ------------
5,302,326 4,852,563
Deferred revenues........................................ 8,255 14,680
Deferred income taxes.................................... 58,120 56,487
Asset retirement obligations............................. 36,773 37,464
Other long-term liabilities and deferred credits......... 1,030,379 468,727
----------- -----------
6,435,853 5,429,921
Commitments and Contingencies (Note 3)
Minority Interest.......................................... 40,597 45,646
----------- -----------
Partners' Capital
Common Units............................................. 2,675,823 2,438,011
Class B Units............................................ 113,873 117,414
i-Units.................................................. 1,784,709 1,694,971
General Partner.......................................... 117,558 103,467
Accumulated other comprehensive loss..................... (1,187,602) (457,343)
------------ ------------
3,504,361 3,896,520
Total Liabilities and Partners' Capital.................... $11,824,649 $10,552,942
============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
4
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Increase/(Decrease) in Cash and Cash Equivalents In Thousands)
(Unaudited)
Nine Months Ended
September 30,
2005 2004
-------- ---------
Cash Flows From Operating Activities
Net income................................................................ $ 690,834 $ 604,314
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization................................. 258,644 209,623
Amortization of excess cost of equity investments........................ 4,233 4,182
Earnings from equity investments......................................... (69,422) (61,723)
Distributions from equity investments...................................... 51,552 49,425
Changes in components of working capital, net of effects of acquisitions:
Accounts receivable...................................................... (249,056) (41,294)
Other current assets..................................................... (394) 27,984
Inventories.............................................................. (7,172) (4,960)
Accounts payable......................................................... 222,739 69,811
Accrued liabilities...................................................... (18,275) (43,295)
Accrued taxes............................................................ 40,722 33,322
Other, net................................................................. (22,805) (9,519)
----------- -----------
Net Cash Provided by Operating Activities.................................... 901,600 837,870
---------- ----------
Cash Flows From Investing Activities
Acquisitions of assets..................................................... (289,751) (142,534)
Additions to property, plant and equip. for expansion and maintenance (597,186) (565,231)
projects.....................................................................
Sale of investments, property, plant and equipment, net of removal costs... 2,987 859
Contributions to equity investments........................................ (1,202) (7,000)
Natural gas stored underground and natural gas liquids line-fill........... (20,208) 219
Other...................................................................... (211) 511
----------- ----------
Net Cash Used in Investing Activities........................................ (905,571) (713,176)
---------- ----------
Cash Flows From Financing Activities
Issuance of debt........................................................... 3,812,933 4,410,926
Payment of debt............................................................ (3,401,190) (4,123,527)
Debt issue costs........................................................... (5,723) (2,152)
Repayments from (Loans to) related parties................................. - (97,223)
Increase in cash book overdrafts........................................... 6,782 --
Proceeds from issuance of common units..................................... 285,407 238,075
Proceeds from issuance of i-units.......................................... - 14,925
Contributions from minority interest....................................... 4,509 3,641
Distributions to partners:
Common units............................................................. (337,994) (287,677)
Class B units............................................................ (12,115) (11,052)
General Partner.......................................................... (337,633) (275,412)
Minority interest........................................................ (8,754) (7,221)
Other, net................................................................. (2,063) (4,900)
----------- -----------
Net Cash Provided by (Used in) Financing Activities.......................... 4,159 (141,597)
---------- -----------
Effect of exchange rate changes on cash and cash equivalents................. (188) --
------------ ------------
Increase in Cash and Cash Equivalents........................................ - (16,903)
Cash and Cash Equivalents, beginning of period............................... - 23,329
---------- ----------
Cash and Cash Equivalents, end of period..................................... $ - $ 6,426
=========== ==========
Noncash Investing and Financing Activities:
Assets acquired by the issuance of units................................... 49,635 --
Assets acquired by the assumption of liabilities........................... 68,045 13,932
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, 2004.
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.
Proposed Acquisition
On August 1, 2005, KMI and Terasen Inc. announced a definitive agreement
whereby KMI will acquire all of the outstanding shares of Terasen Inc., a
provider of energy and utility services based in Vancouver, British Columbia,
Canada. The total purchase price, including the debt held within the Terasen
companies, is expected to be approximately US$5.6 billion. Under the
transaction, Terasen shareholders will be able to elect, for each Terasen share
held, either (i) C$35.75 in cash, (ii) 0.3331 shares of KMI common stock, or
(iii) C$23.25 in cash plus 0.1165 shares of KMI common stock. All elections will
be subject to proration in the event total cash elections exceed approximately
65% of the total consideration to be paid or total stock elections exceed
approximately 35%. The transaction was unanimously approved by each company's
board of directors and by a special committee of independent Terasen directors
created by the Terasen board to oversee the process. On October 18, 2005, the
transaction was approved by a vote of Terasen shareholders. The transaction is
also subject to regulatory approvals and other conditions, and is expected to
close by year-end 2005.
Terasen owns two core businesses: (i) a natural gas distribution business
serving approximately 875,000 customers in British Columbia and (ii) a refined
products and crude oil transportation pipeline business with three pipelines,
(a) Trans Mountain Pipeline, extending from Edmonton to Vancouver and Washington
State, (b) Corridor Pipeline, extending from the Athabasca oilsands to Edmonton
and (c) a one-third interest in the Express and Platte pipeline systems
extending from Alberta to the U.S. Rocky Mountain and Midwest regions. In
addition, Terasen owns a water and utility services business that operates 90
water and wastewater systems in over 50 communities throughout British Columbia,
Alberta and Alaska.
Income Taxes - Realization of Deferred Tax Assets
At December 31, 2004, KMI had a capital loss carryforward of approximately
$56.1 million. A capital loss carryforward can be utilized to reduce capital
gain during the five years succeeding the year in which a capital loss is
incurred. The amounts and the years in which KMI's capital loss carryforward
expires are $52.5 million during 2005, $1.6 million during 2006 and $2.0 million
during 2008. During the third quarter of 2005, KMI sold its interest in the
Wrightsville, Arkansas power facility, generating a capital loss for tax
purposes of $68.7 million. For tax purposes, KMI is required to apply its
capital gains from the sale of Kinder Morgan Mangement shares to the capital
loss from the Wrightsville power facility first, before applying them to its
capital loss carryforwards.
Our common units and Kinder Morgan Management shares are specific assets
that KMI can sell to generate capital gain. KMI sold approximately 2.1 million
Kinder Morgan Management shares during the first nine months of 2005, generating
a gain for tax purposes of approximately $41.8 million. On October 31, 2005, KMI
sold 1,586,965 Kinder Morgan Management shares that it owned, generating a gain
for tax purposes of $36.4 million. KMI owned approximately 11.7 million Kinder
Morgan Management shares at November 1, 2005. KMI plans to sell additional
6
Kinder Morgan Management shares that it owns to offset the remaining capital
loss carryforward of approximately $43 million that expires this year.
Basis of Presentation
Our consolidated financial statements include our accounts and those of our
operating partnerships and their majority-owned and controlled subsidiaries. All
significant intercompany items have been eliminated in consolidation. Certain
amounts from prior periods have been reclassified to conform to the current
presentation.
Net Income Per Unit
We compute Basic Limited Partners' Net Income per Unit by dividing our
limited partners' interest in net income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the maximum potential dilution that could occur if units whose issuance
depends on the market price of the units at a future date were considered
outstanding, or if, by application of the treasury stock method, options to
issue units were exercised, both of which would result in the issuance of
additional units that would then share in our net income.
2. Acquisitions and Joint Ventures
During the first nine months of 2005, we completed or made adjustments for
the following acquisitions. Each of the acquisitions was accounted for under the
purchase method and the assets acquired and liabilities assumed were recorded at
their estimated fair market values as of the acquisition date. The preliminary
allocation of assets and liabilities 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.
Allocation of Purchase Price
-------------------------------------------------------------------
(in millions)
-------------------------------------------------------------------
-------------------------------------------------------------------
Ref. Date Acquisition Property Deferred
Purchase Current Plant & Charges Minority
Price Assets Equipment & Other Goodwill Interest
----- --------------------------------------------------------------- --------- ------------ ---------- --------------------
(1) 1/02 Kinder Morgan Materials Services LLC...... $ 14.4 $0.9 $13.5 $ - $ - $ -
(2) 8/04 Kinder Morgan Wink Pipeline, L.P.......... 100.3 0.1 77.4 22.8 - -
(3) 10/04 Kinder Morgan River Terminals LLC......... 89.7 10.3 40.7 16.6 22.1 -
(4) 11/04 Charter Products Terminals................ 75.2 3.7 56.5 3.0 13.1 (1.1)
(5) 12/04 Kinder Morgan Fairless Hills Terminal..... 7.5 0.3 5.9 1.3 - -
(6) 1/05 Claytonville Oil Field Unit .............. 6.5 - 6.5 - - -
(7) 4/05 Texas Petcoke Terminal Region ............ 247.4 - 72.4 162.7 12.3 -
(8) 7/05 Terminal Assets .......................... 36.2 0.5 35.7 - - -
(9) 7/05 General Stevedores, L.P. ................. 8.9 0.6 8.1 0.2 - -
(10) 8/05 North Dayton Natural Gas Storage Facility 101.6 - 101.6 - - -
erminal Assets .......................... $
(11) 8-9/05 T 4.3 $ 0.4 $3.9 $ - $ - $ -
(1) Kinder Morgan Materials Services LLC
Effective January 1, 2002, we acquired all of the equity interests of Kinder
Morgan Materials Services LLC, formerly Laser Materials Services LLC, for an
aggregate consideration of $14.4 million, consisting of approximately $11.1
million in cash and the assumption of approximately $3.3 million of liabilities,
including long-term debt of $0.4 million. In the first quarter of 2005, we paid
$0.3 million to the previous owners for final earn-out provisions pursuant to
the purchase and sale agreement. Kinder Morgan Materials Services LLC currently
operates approximately 60 transload facilities in 20 states. The facilities
handle dry-bulk products, including aggregates, plastics and liquid chemicals.
The acquisition of Kinder Morgan Materials Services LLC expanded our growing
terminal operations and is part of our Terminals business segment.
7
(2) Kinder Morgan Wink Pipeline, L.P.
Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P. from KPL Pipeline Company, LLC and RHC Holdings,
L.P. for a purchase price of approximately $100.3 million, consisting of $89.9
million in cash and the assumption of approximately $10.4 million of
liabilities, including debt of $9.5 million. In September 2004, we paid the $9.5
million outstanding debt balance. We renamed the limited partnership Kinder
Morgan Wink Pipeline, L.P., and since August 31, 2004, we have included its
results as part of our CO2 business segment. In the second quarter of 2005, we
made our final allocation of purchase price to acquired assets, resulting in
offsetting adjustments to intangibles and property, plant and equipment in the
amount of $1.0 million. The acquisition included a 450-mile crude oil pipeline
system, consisting of four mainline sections, numerous gathering systems and
truck off-loading stations. The mainline sections, all in Texas, have a total
capacity of 115,000 barrels of crude oil per day. As part of the transaction, we
entered into a long-term throughput agreement with Western Refining Company,
L.P. to transport crude oil into Western's 107,000 barrel per day refinery in El
Paso, Texas. The acquisition allows us to better manage crude oil deliveries
from our oil field interests in West Texas. Our allocation of the purchase price
to assets acquired and liabilities assumed was based on an independent appraisal
of fair market values, which was completed in the second quarter of 2005. The
$22.8 million of deferred charges and other assets in the table above represents
the fair value of the intangible long-term throughput agreement.
(3) Kinder Morgan River Terminals LLC
Effective October 6, 2004, we acquired Global Materials Services LLC and its
consolidated subsidiaries from Mid-South Terminal Company, L.P. for
approximately $89.7 million, consisting of $31.8 million in cash and $57.9
million of assumed liabilities, including debt of $33.7 million. Global
Materials Services LLC, which we renamed Kinder Morgan River Terminals LLC,
operates a network of 21 river terminals and two rail transloading facilities
primarily located along the Mississippi River system. The network provides
loading, storage and unloading points for various bulk commodity imports and
exports. As of our acquisition date, we expected to invest an additional $9.4
million over the next two years to expand and upgrade the terminals, which are
located in 11 Mid-Continent states. The acquisition further expands and
diversifies our customer base and complements our existing terminal facilities
located along the lower-Mississippi River system. The acquired terminals are
included in our Terminals business segment. In the third quarter of 2005, we
made purchase price adjustments to the acquired assets based on a preliminary
independent appraisal of fair market values, which is expected to be completed
in the fourth quarter of 2005. The $22.1 million of goodwill was assigned to our
Terminals business segment, and the entire amount is expected to be deductible
for tax purposes. The $16.6 million of deferred charges and other assets in the
table above includes $12.9 million representing the fair value of intangible
customer relationships, which encompass both the contractual life of customer
contracts plus any future customer relationship value beyond the contract life.
(4) Charter Products Terminals
Effective November 5, 2004, we acquired ownership interests in nine refined
petroleum products terminals in the southeastern United States from Charter
Terminal Company and Charter-Triad Terminals, LLC for approximately $75.2
million, consisting of $72.4 million in cash and $2.8 million of assumed
liabilities. Three terminals are located in Selma, North Carolina, and the
remaining facilities are located in Greensboro and Charlotte, North Carolina;
Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta, South
Carolina. We fully own seven of the terminals and jointly own the remaining two.
The nine facilities have a combined 3.2 million barrels of storage. All of the
terminals are connected to products pipelines owned by either Plantation Pipe
Line Company or Colonial Pipeline Company. The acquisition complements the other
terminals we own in the Southeast and increased our southeast terminal storage
capacity 76% (to 7.7 million barrels) and terminal throughput capacity 62% (to
over 340,000 barrels per day). The acquired terminals are included as part of
our Products Pipelines business segment. Our allocation of the purchase price to
assets acquired and liabilities assumed was based on a preliminary independent
appraisal of fair market values, which is expected to be completed in the fourth
quarter of 2005. The $13.1 million of goodwill was assigned to our Products
Pipelines business segment and the entire amount is expected to be deductible
for tax purposes.
8
(5) Kinder Morgan Fairless Hills Terminal
Effective December 1, 2004, we acquired substantially all of the assets used
to operate the major port distribution facility located at the Fairless
Industrial Park in Bucks County, Pennsylvania for an aggregate consideration of
approximately $7.5 million, consisting of $7.2 million in cash and $0.3 million
in assumed liabilities. The facility, referred to as our Kinder Morgan Fairless
Hills Terminal, was purchased from Novolog Bucks County, Inc. and is located
along the Delaware River. It is the largest port on the East Coast for the
handling of semi-finished steel slabs, which are used as feedstock by domestic
steel mills. The port operations at Fairless Hills also include the handling of
other types of steel and specialized cargo that caters to the construction
industry and service centers that use steel sheet and plate. In the second
quarter of 2005, after completing a final inventory count, we allocated $0.3
million of our purchase price that was originally allocated to property, plant
and equipment to current assets (materials and supplies-parts inventory). The
terminal acquisition expanded our presence along the Delaware River and
complemented our existing Mid-Atlantic terminal facilities. We include its
operations in our Terminals business segment.
(6) Claytonville Oil Field Unit
Effective January 31, 2005, we acquired an approximate 64.5% gross working
interest in the Claytonville oil field unit located in Fisher County, Texas from
Aethon I L.P. The field is located nearly 30 miles east of the SACROC unit in
the Permian Basin of West Texas. Our purchase price was approximately $6.5
million, consisting of $6.2 million in cash and the assumption of $0.3 million
of liabilities. Following our acquisition, we became the operator of the field,
which at the time of acquisition was producing approximately 200 barrels of oil
per day. The acquisition of this ownership interest complemented our existing
carbon dioxide assets in the Permian Basin, and as of our acquisition date and
pending further studies as to the technical and economic feasibility of carbon
dioxide injection, we may invest an additional $30 million in the field in order
to increase production. The acquired operations are included as part of our CO2
business segment.
(7) Texas Petcoke Terminal Region
Effective April 29, 2005, we acquired seven bulk terminal operations from
Trans-Global Solutions, Inc. for an aggregate consideration of approximately
$247.4 million, consisting of $186.1 million in cash, $46.3 million in common
units, and an obligation to pay an additional $15 million on April 29, 2007, two
years from closing. We will settle the $15 million liability by issuing
additional common units. All of the acquired assets are located in the State of
Texas, and include facilities at the Port of Houston, the Port of Beaumont and
the TGS Deepwater Terminal located on the Houston Ship Channel. We combined the
acquired operations into a new terminal region called the Texas Petcoke region,
as certain of the terminals have contracts in place to provide petroleum coke
handling services for major Texas oil refineries. The acquisition complemented
our existing Gulf Coast terminal facilities and expanded our pre-existing
petroleum coke handling operations. The acquired operations are included as part
of our Terminals business segment. Our allocation of the purchase price to
assets acquired and liabilities assumed was based on a preliminary independent
appraisal of fair market values, which is expected to be completed in the fourth
quarter of 2005. The $12.3 million of goodwill was assigned to our Terminals
business segment and the entire amount is expected to be deductible for tax
purposes. The $162.7 million of deferred charges and other assets in the table
above represents the fair value of intangible customer relationships, which
encompass both the contractual life of customer contracts plus any future
customer relationship value beyond the contract life.
(8) July 2005 Terminal Assets
In July 2005, we acquired three terminal facilities in separate transactions
for an aggregate consideration of approximately $36.2 million in cash. For the
three terminals combined, as of the acquisition date, we expected to invest
approximately $14 million subsequent to acquisition in order to enhance the
terminals' operational efficiency. The largest of the transactions was the
purchase of a refined petroleum products terminal in New York Harbor from
ExxonMobil Oil Corporation. The second acquisition involved a dry-bulk river
terminal located in the State of Kentucky, and the third involved a
liquids/dry-bulk facility located in Blytheville, Arkansas. The operations of
all three facilities are included in our Terminals business segment.
9
The New York Harbor terminal, located on Staten Island and referred to as
the Kinder Morgan Staten Island terminal, complemented our existing Northeast
liquids terminal facilities located in Carteret and Perth Amboy, New Jersey. At
the time of acquisition, the terminal had storage capacity of 2.3 million
barrels for gasoline, diesel and fuel oil, and we expect to bring several idle
tanks back into service that would add another 550,000 barrels of capacity. In
addition, we plan to rebuild a ship berth with the ability to accommodate tanker
vessels. As part of the transaction, ExxonMobil has entered into a long-term
storage capacity agreement with us and will continue to utilize a portion of the
terminal.
The dry-bulk terminal, located along the Ohio River in Hawsville, Kentucky,
primarily handles wood chips and finished paper products. The acquisition
complemented our existing terminal assets located in the Ohio River Valley and
further expanded our wood-chip handling businesses. As part of the transaction,
we assumed a long-term handling agreement with Weyerhauser Company, an
international forest products company, and we plan to expand the terminal in
order to increase utilization and provide storage services for additional
products.
The assets acquired at the liquids/dry-bulk facility in Blytheville,
Arkansas consist of storage and supporting infrastructure for 40,000 tons of
anhydrous ammonia, 9,500 tons of urea ammonium nitrate solutions and 40,000 tons
of urea. As part of the transaction, we have entered into a long-term agreement
to sublease all of the existing anhydrous ammonia and urea ammonium nitrate
terminal assets to Terra Nitrogen Company, L.P. The terminal is one of only two
facilities in the United States that can handle imported fertilizer and provide
shipment west on railcars, and the acquisition of the facility has positioned us
to take advantage of the increase in fertilizer imports that has resulted from
the recent decrease in domestic production.
(9) 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 $2.1 million in cash, $3.4 million in common units, and
$3.4 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. Our allocation of the purchase price to assets
acquired and liabilities assumed is preliminary, pending final determination of
working capital balances at the time of acquisition. We expect these final
working capital adjustments to be made in the fourth quarter of 2005.
(10) Natural Gas Storage Facility
Effective August 1, 2005, we acquired a natural gas storage facility in
Liberty County, Texas, from Texas Genco LLC for an aggregate consideration of
approximately $101.6 million, consisting of $50.9 million in cash, $49.2 million
in assumed debt, and a $1.5 million purchase price liability that will be paid
in the fourth quarter of 2005. The facility, referred to as our North Dayton
storage facility, has approximately 6.3 billion cubic feet of total capacity,
consisting of 4.2 billion cubic feet of working capacity and 2.1 billion cubic
feet of pad (cushion) gas. The acquisition complemented our existing Texas
intrastate natural gas pipeline group assets and positioned us to pursue
expansions at the facility that will provide needed services to utilities, the
growing liquefied natural gas industry along the Texas Gulf Coast, and other
natural gas storage users. Additionally, as part of the transaction, we entered
into a long-term storage capacity and transportation agreement with Texas Genco,
one of the largest wholesale electric power generating companies in the United
States, with over 13,000 megawatts of generation capacity. The North Dayton
storage facility's operations are included in our Natural Gas Pipelines business
segment.
(11) August and September 2005 Terminal Assets
In August and September 2005, we acquired certain terminal facilities and
assets, including both real and personal property, in two separate transactions
for an aggregate consideration of approximately $4.3 million in cash. In August
2005, we spent $1.9 million to acquire the Kinder Morgan Blackhawk terminal from
White Material Handling, Inc., and in September 2005, we spent $2.4 million to
acquire a repair shop and related assets from Trans-Global Solutions, Inc. The
Kinder Morgan Blackhawk terminal consists of approximately 46 acres of land,
10
storage buildings, and related equipment located in Black Hawk County, Iowa. The
terminal primarily stores and transfers fertilizer and salt and further expands
our Midwest region bulk terminal operations. The acquisition of the repair shop,
located in Jefferson County, Texas, near Beaumont, consists of real and personal
property, including parts inventory. The acquisition facilitated and expanded
the earlier acquisition of our Texas Petcoke terminals from Trans-Global
Solutions effective April 29, 2005. The operations of both acquisitions are
included in our Terminals business segment.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement
information for the nine months ended September 30, 2005 and 2004, assumes that
all of the acquisitions we have made and joint ventures we have entered into
since January 1, 2004, including the ones listed above, had occurred as of the
beginning of the period presented. We have prepared these unaudited pro forma
financial results for comparative purposes only. These unaudited pro forma
financial results may not be indicative of the results that would have occurred
if we had completed these acquisitions and joint ventures as of the beginning of
the period presented or the results that will be attained in the future. Amounts
presented below are in thousands, except for the per unit amounts:
Pro Forma
Nine Months Ended September 30,
2005 2004
------------- -------------
(Unaudited)
Revenues.......................................................... $ 6,762,832 $ 5,968,369
Operating Income.................................................. 855,643 768,816
Net Income........................................................ $ 697,266 $ 654,415
Basic Limited Partners' Net Income per unit....................... $ 1.64 $ 1.84
Diluted Limited Partners' Net Income per unit..................... $ 1.64 $ 1.83
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
11
regulatory litigation expenses and certain pipeline reconditioning costs
incurred by SFPP. The initial decision also held SFPP's Watson Station gathering
enhancement service was subject to FERC jurisdiction and ordered SFPP to file a
tariff for that service.
The FERC subsequently reviewed the initial decision, and issued a series of
orders in which it adopted certain rulings made by the administrative law judge,
changed others and modified a number of its own rulings on rehearing. Those
orders began in January 1999, with FERC Opinion No. 435, and continued through
June 2003.
The FERC affirmed that all but one of SFPP's West Line rates are
"grandfathered" and that complainants had failed to satisfy the threshold burden
of demonstrating "substantially changed circumstances" necessary to challenge
those rates. The FERC further held that the one West Line rate that was not
grandfathered did not need to be reduced. The FERC consequently dismissed all
complaints against the West Line rates in Docket Nos. OR92-8 et al. without any
requirement that SFPP reduce, or pay any reparations for, any West Line rate.
The FERC initially modified the initial decision's ruling regarding the
capital structure to be used in computing SFPP's "starting rate base" to be more
favorable to SFPP, but later reversed that ruling. The FERC also made certain
modifications to the calculation of the income tax allowance and other cost of
service components, generally to SFPP's disadvantage.
On multiple occasions, the FERC required SFPP to file revised East Line
rates based on rulings made in the FERC's various orders. SFPP was also directed
to submit compliance filings showing the calculation of the revised rates, the
potential reparations for each complainant and in some cases potential refunds
to shippers. SFPP filed such revised East Line rates and compliance filings in
March 1999, July 2000, November 2001 (revised December 2001), October 2002 and
February 2003 (revised March 2003). Most of those filings were protested by
particular SFPP shippers. The FERC has held that certain of the rates SFPP filed
at the FERC's directive should be reduced retroactively and/or be subject to
refund; SFPP has challenged the FERC's authority to impose such requirements in
this context.
While the FERC initially permitted SFPP to recover certain of its
litigation, pipeline reconditioning and environmental costs, either through a
surcharge on prospective rates or as an offset to potential reparations, it
ultimately limited recovery in such a way that SFPP was not able to make any
such surcharge or take any such offset. Similarly, the FERC initially ruled that
SFPP would not owe reparations to any complainant for any period prior to the
date on which that party's complaint was filed, but ultimately held that each
complainant could recover reparations for a period extending two years prior to
the filing of its complaint (except for Navajo, which was limited to one month
of pre-complaint reparations under a settlement agreement with SFPP's
predecessor). The FERC also ultimately held that SFPP was not required to pay
reparations or refunds for Watson Station gathering enhancement fees charged
prior to filing a FERC tariff for that service.
In April 2003, SFPP paid complainants and other shippers reparations and/or
refunds as required by FERC's orders. In August 2003, SFPP paid shippers an
additional refund as required by FERC's most recent order in the Docket No.
OR92-8 et al. proceedings. We made aggregate payments of $44.9 million in 2003
for reparations and refunds pursuant to a FERC order.
Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond
Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for
review of FERC's Docket OR92-8 et al. orders in the United States Court of
Appeals for the District of Columbia Circuit. Certain of those petitions were
dismissed by the Court of Appeals as premature, and the remaining petitions were
held in abeyance pending completion of agency action. However, in December 2002,
the Court of Appeals returned to its active docket all petitions to review the
FERC's orders in the case 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 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
12
orders involving SFPP, the court held, among other things, that the FERC had not
adequately justified its policy of providing an oil pipeline limited partnership
with an income tax allowance equal to the proportion of its limited partnership
interests owned by corporate partners. By its terms, the portion of the opinion
addressing SFPP only pertained to SFPP, L.P. and was based on the record in that
case.
The Court of Appeals held that, in the context of the Docket No. OR92-8, et
al. proceedings, all of SFPP's West Line rates were grandfathered other than the
charge for use of SFPP's Watson Station gathering enhancement facility and the
rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded
that the FERC had a reasonable basis for concluding that the addition of a West
Line origin point at East Hynes, California did not involve a new "rate" for
purposes of the Energy Policy Act. It rejected arguments from West Line Shippers
that certain protests and complaints had challenged West Line rates prior to the
enactment of the Energy Policy Act.
The Court of Appeals also held that complainants had failed to satisfy their
burden of demonstrating substantially changed circumstances, and therefore could
not challenge grandfathered West Line rates in the Docket No. OR92-8 et al.
proceedings. It specifically rejected arguments that other shippers could
"piggyback" on the special Energy Policy Act exception permitting Navajo to
challenge grandfathered West Line rates, which Navajo had withdrawn under a
settlement with SFPP. The court remanded to the FERC the changed circumstances
issue "for further consideration" in light of the court's decision regarding
SFPP's tax allowance. While, the FERC had previously held in the OR96-2
proceeding (discussed following) that the tax allowance policy should not be
used as a stand-alone factor in determining when there have been substantially
changed circumstances, the FERC's May 4, 2005 income tax allowance policy
statement (discussed following) may affect how the FERC addresses the changed
circumstances and other issues remanded by the court.
The Court of Appeals upheld the FERC's rulings on most East Line rate
issues; however, it found the FERC's reasoning inadequate on some issues,
including the tax allowance.
The court 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:
- Navajo's argument that its prior settlement with SFPP's predecessor
did not limit its right to seek reparations;
13
- 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;
- 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
- Chevron's argument that its reparations period should begin two years
before its September 1992 protest regarding the six-inch line reversal
rather than its August 1993 complaint against East Line rates.
On September 2, 2004, BP West Coast Products, ChevronTexaco, ConocoPhillips
and ExxonMobil filed a petition for rehearing and rehearing en banc asking the
Court of Appeals to reconsider its ruling that West Line rates were not subject
to investigation at the time the Energy Policy Act was enacted. On September 3,
2004, SFPP filed a petition for rehearing asking the court to confirm that the
FERC has the same discretion to address on remand the income tax allowance issue
that administrative agencies normally have when their decisions are set aside by
reviewing courts because they have failed to provide a reasoned basis for their
conclusions. On October 4, 2004, the Court of Appeals denied both petitions
without further comment.
On November 2, 2004, the Court of Appeals issued its mandate remanding the
Docket No. OR92-8 proceedings to the FERC. SFPP and shipper parties subsequently
filed various pleadings with the FERC regarding the proper nature and scope of
the remand proceedings. On December 2, 2004, the FERC issued a Notice of Inquiry
and opened a new proceeding (Docket No. PL05-5) to consider how broadly the
court's ruling on the tax allowance issue in BP West Coast Products, LLC, v.
FERC should affect the range of entities the FERC regulates. The FERC sought
comments on whether the court's ruling applies only to the specific facts of the
SFPP proceeding, or also extends to other capital structures involving
partnerships and other forms of ownership. Comments were filed by numerous
parties, including our Rocky Mountain natural gas pipelines, in the first
quarter of 2005. On May 4, 2005, the FERC adopted a policy statement in Docket
No. PL05-5, providing that all entities owning public utility assets - oil and
gas pipelines and electric utilities - would be permitted to include an income
tax allowance in their cost-of-service rates to reflect the actual or potential
income tax liability attributable to their public utility income, regardless of
the form of ownership. Any tax pass-through entity seeking an income tax
allowance would have to establish that its partners or members have an actual or
potential income tax obligation on the entity's public utility income. The FERC
expressed the intent to implement its policy in individual cases as they arise.
Subject to that case-specific implementation, the policy appears to provide an
opportunity for partnership-owned pipelines to seek allowances based upon their
entire income paid to partners, rather than the partial allowance provided under
the prior Lakehead approach. We expect the final adoption and implementation by
the FERC of the policy statement in individual cases will be subject to review
of the United States Court of Appeals for the District of Columbia Circuit. The
FERC's June 1, 2005 Order on Remand and Rehearing (discussed following) required
further briefing with respect to the SFPP income tax allowance and may result in
further proceedings on that issue.
On December 17, 2004, the Court of Appeals issued orders directing that the
petitions for review relating to FERC orders issued after November 2001, 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.
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).
14
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 and required further briefing on the income tax allowance issue in
light of the FERC's May 4, 2005 policy statement. 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 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 currently scheduled to go to hearing in
January 2006. However, 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.
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.
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.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at 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 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
Line at five cents per barrel. Several shippers protested that rate.
In December 1997, SFPP filed an application for authority to charge a
market-based rate for the Sepulveda service, which application was protested by
several parties. On September 30, 1998, the FERC issued an order finding that
SFPP lacks market power in the Watson Station destination market and set a
hearing to determine whether SFPP possessed market power in the origin market.
In December 2000, an administrative law judge found that SFPP possessed
market power over the Sepulveda origin market. On February 28, 2003, the FERC
issued an order upholding that decision. SFPP filed a request for rehearing of
that order on March 31, 2003. The FERC denied SFPP's request for rehearing on
July 9, 2003.
As part of its February 28, 2003 order denying SFPP's application for
market-based ratemaking authority, the FERC remanded to the ongoing litigation
in Docket No. OR96-2, et al. the question of whether SFPP's current rate for
service on the Sepulveda pipeline is just and reasonable. A hearing in this
proceeding was 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.
15
OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar
Diamond Shamrock Corporation filed a complaint at FERC (Docket No. OR97-2)
challenging SFPP's West Line rates, claiming they were unjust and unreasonable
and no longer subject to grandfathering. In October 1997, ARCO, Mobil and Texaco
filed a complaint at the FERC (Docket No. OR98-1) challenging the justness and
reasonableness of all of SFPP's interstate rates, raising claims against SFPP's
East and West Line rates similar to those that have been at issue in Docket Nos.
OR92-8, et al. discussed above, but expanding them to include challenges to
SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno,
Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line. In
November 1997, Ultramar filed a similar, expanded complaint (Docket No. OR98-2).
Tosco Corporation filed a similar complaint in April 1998. The shippers seek
both reparations and prospective rate reductions for movements on all of SFPP's
lines. The FERC accepted the complaints and consolidated them into one
proceeding (Docket No. OR96-2, et al.), but held them in abeyance pending a FERC
decision on review of the initial decision in Docket Nos. OR92-8, et al.
In a companion order to Opinion No. 435, the FERC gave the complainants an
opportunity to amend their complaints in light of Opinion No. 435, which the
complainants did in January 2000. In August 2000, Navajo and Western filed
complaints against SFPP's East Line rates and Ultramar filed an additional
complaint updating its pre-existing challenges to SFPP's interstate pipeline
rates. These complaints were consolidated with the ongoing proceeding in Docket
No. OR96-2, et al.
A hearing in this consolidated proceeding was held from October 2001 to
March 2002. A FERC administrative law judge issued his initial decision 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 are necessary. As
discussed below, those issues have been addressed in the non-binding phase two
initial decision issued by the presiding administrative law judge. The FERC's
phase one order also did not address the "grandfathered" status of the Watson
Station fee, noting that it would address that issue once it was ruled on by the
Court of Appeals in its review of the FERC's Opinion No. 435 orders; as noted
above, the FERC held in its June 1, 2005 order that the Watson Station fee is
not grandfathered. Several of the participants in the proceeding requested
rehearing of the FERC's phase one order. The FERC denied those requests in its
June 1, 2005 order. In addition, several participants, including SFPP, filed
petitions with the United States Court of Appeals for the District of Columbia
Circuit for review of the FERC's phase one order. On August 13, 2004, the FERC
filed a motion to dismiss the pending petitions for review of the phase one
order, which Petitioners, including SFPP, answered on August 30, 2004. On
December 20, 2004, the Court 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 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, which motions
were filed in June and July of 2005; at least two such motions requested that
the Court simultaneously review appeals of the March 26, 2004 phase one order
and the June 1, 2005 order. Court action is now pending.
The FERC's phase one order also held that SFPP failed to seek authorization
for the accounting entries necessary to reflect in SFPP's books, and thus in its
annual report to FERC ("FERC Form 6"), the purchase price adjustment ("PPA")
arising from SFPP's 1998 acquisition by us. The phase one order directed SFPP to
file for permission to reflect the PPA in its FERC Form 6 for the calendar year
1998 and each subsequent year. In its April 26, 2004 compliance filing, SFPP
noted that it had previously requested such permission and that the FERC's
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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 the likelihood that the FERC's
policy statement and its decision in these cases will be appealed to the federal
courts.
On September 9, 2004, the presiding administrative law judge issued his
non-binding initial decision in the phase two portion of this proceeding. If
affirmed by the FERC, the phase two initial decision would establish the basis
for prospective rates and the calculation of reparations for complaining
shippers with respect to the West Line and East Line. However, as with the phase
one initial decision, the phase two initial decision must be fully reviewed by
the FERC, which may accept, reject or modify the decision. A FERC order on phase
two of the case is expected during the fourth quarter of 2005. Any such order
may be subject to further FERC review, review by the United States Court of
Appeals for the District of Columbia Circuit, or both.
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. As the
timing for implementation of rate reductions and the payment of reparations is
extended, total estimated reparations and the interest accruing on the
reparations increase. For each calendar quarter that implementation of the rate
reductions sought is deferred, we estimate that reparations and accrued interest
accumulates by approximately $9 million. We now assume that any potential rate
reductions will be implemented no earlier than the fourth quarter of 2005 and
that reparations and accrued interest thereon will be paid no earlier than the
fourth quarter of 2006; 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 FERC's June 1, 2005 order, the FERC's income tax allowance
inquiry in Docket No. PL05-5 and the application of the FERC's new policy
statement on income tax allowances to SFPP in the OR92-8 and OR96-2 proceedings
(described above). If the phase two initial decision were to be largely adopted
by the FERC, the estimated reparations and rate reductions would be larger than
noted above; however, we continue to estimate the combined annual impact of the
rate reductions and the capital costs associated with financing the payment of
reparations sought by shippers and accrued interest thereon to be approximately
15 cents of distributable cash flow per unit. We believe, however, that the
ultimate resolution of these complaints will be for amounts substantially less
than the amounts sought.
Chevron complaint OR02-4 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
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consolidation and for back-dating. On November 21, 2003, Chevron filed a
petition for review of the FERC's October 28, 2003 Order at the Court of Appeals
for the District of Columbia Circuit.
On August 18, 2003, SFPP filed a motion to dismiss Chevron's petition for
review in OR02-4 on the basis that Chevron lacks standing to bring its appeal
and that the case is not ripe for review. Chevron answered on September 10,
2003. SFPP's motion was pending, when the Court of Appeals, on December 8, 2003,
granted Chevron's motion to hold the case in abeyance pending the outcome of the
appeal of the Docket No. OR92-8, et al. proceeding. On January 8, 2004, the
Court of Appeals granted Chevron's motion to have its appeal of the FERC's
decision in OR03-5 consolidated with Chevron's appeal of the FERC's decision in
the OR02-4 proceeding. Following motions to dismiss by 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, 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. On March 14, 2005 and June 13, 2005,
Valero and Chevron, respectively, filed untimely motions to intervene in the
consolidated proceedings. FERC action on those motions is pending. The
complaints continue to be held in abeyance.
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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. An investigation
and hearing regarding the rate increase is proceeding, with a hearing scheduled
to commence in January 2006.
Trailblazer Pipeline Company
On March 22, 2005, Marathon Oil Company filed a formal complaint with FERC
alleging that Trailblazer Pipeline Company violated the FERC's Negotiated Rate
Policy Statement and the Natural Gas Act by failing to offer a recourse rate
option for its Expansion 2002 capacity and by charging negotiated rates higher
than the applicable recourse rates. Marathon is requesting that the FERC require
Trailblazer to refund all amounts paid by Marathon above Trailblazer's Expansion
2002 recourse rate since the facilities went into service in May 2002, with
interest. In addition, Marathon is asking the FERC to require Trailblazer to
bill Marathon the Expansion 2002 recourse rate for future billings. Marathon
estimates the amount of Trailblazer's refund to date is over $15 million.
Trailblazer filed its response to Marathon's complaint on April 13, 2005. On May
20, 2005, the FERC issued an order denying the Marathon complaint and found that
(i) Trailblazer did not violate FERC policy and regulations and (ii) there is
insufficient justification to initiate further action under Section 5 of the
Natural Gas Act to invalidate and change the negotiated rate. On June 17, 2005,
Marathon filed its Request for Rehearing. On July 18, 2005, the FERC issued a
procedural order titled "Order Granting Rehearing for Further Consideration,"
which allows additional time to act on the rehearing request.
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 within the fourth quarter of
2005.
The CPUC subsequently issued a resolution approving a 2001 request by SFPP
to raise its California rates to reflect increased power costs. The resolution
approving the requested rate increase also required SFPP to submit cost data for
2001, 2002, and 2003, and to assist the CPUC in determining whether SFPP's
overall rates for California intrastate transportation services are reasonable.
The resolution reserves the right to require refunds, from the date of issuance
of the resolution, to the extent the CPUC's analysis of cost data to be
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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 in the fourth quarter of 2005.
On November 22, 2004, SFPP filed an application with the CPUC requesting a
$9 million 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. The CPUC is
not expected to resolve the matter before the first quarter of 2006.
We currently believe the CPUC complaints seek approximately $15 million in
tariff reparations and prospective annual tariff reductions, the aggregate
average annual impact of which would be approximately $31 million. There is no
way to quantify the potential extent to which the CPUC could determine that
SFPP's existing California rates are unreasonable. With regard to the amount of
dollars potentially subject to refund as a consequence of the CPUC resolution
requiring the provision by SFPP of cost-of-service data, referred to above, such
refunds could total about $6 million per year from October 2002 to the
anticipated date of a CPUC decision.
SFPP believes the submission of the required, representative cost data
required by the CPUC indicates that SFPP's existing rates for California
intrastate services remain reasonable and that no refunds are justified.
We believe that the resolution of such matters will not have a material
adverse effect on our business, financial position, results of operations or
cash flows.
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. In addition, since many of our assets are subject to regulation, we are
subject to potential future changes in applicable rules and regulations that may
have an adverse effect on our business, financial position, results of
operations or cash flows.
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. Trial, originally scheduled for July 25, 2005, has been
rescheduled for June 12, 2006.
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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 is set for June 12, 2006.
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 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 has 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. Bailey has filed a petition for writ of
certiorari in the United States Supreme Court. By order of the Houston federal
district court, the counter-claim plaintiffs filed their respective
counter-claims in the Bailey Houston Federal Court Action on June 29, 2005. The
counter-claim plaintiffs asserted 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
counter-claim plaintiffs seek actual damages, treble damages, punitive damages,
a constructive trust and accounting, and declaratory relief. Kinder Morgan CO2
Company, L.P. and the Shell plaintiffs have filed a motion for partial summary
judgment and intend to seek dismissal of all of the counter-claim plaintiffs'
claims through appropriate motions. No current trial date is set.
On March 1, 2004, Bridwell Oil Company, one of the named
defendants/counter-claim 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,
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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.
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 dioxide. The Court denied
plaintiffs' motion for summary judgment concerning alleged underpayment of
McElmo Dome overriding royalties on March 2, 2005. The parties are continuing to
engage in discovery. No trial date is currently set.
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) 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. 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 are engaged in a 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.
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ARB, Inc. Dispute
ARB, Inc, a general contractor engaged by SFPP, L.P. to build a 20-inch
diameter, 70-mile pipeline from Concord to Sacramento, California, and numerous
third party contractors recorded liens against SFPP, L.P. based on an assertion
that SFPP, L.P. owed ARB, Inc. and third party contractors additional payments
ranging from $13.1 million to $16.8 million on the project. SFPP, L.P. engaged
construction claims specialists and auditors to review project records and
determine what additional payments, if any, should be made. On or about
September 15, 2005, SFPP, L.P. agreed to settle all disputes with ARB, Inc. and
third party contractors for substantially less than the recorded lien amounts.
As part of the settlement, all recorded liens and other potential claims arising
from the construction project were released with prejudice.
RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et
al. (Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District).
On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with the
First Supplemental Petition filed by RSM Production Corporation on behalf of the
County of Zapata, State of Texas and Zapata County Independent School District
as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition to 15
other defendants, including two other Kinder Morgan affiliates. Certain entities
we acquired in the Kinder Morgan Tejas acquisition are also defendants in this
matter. The Petition alleges that these taxing units relied on the reported
volume and analyzed heating content of natural gas produced from the wells
located within the appropriate taxing jurisdiction in order to properly assess
the value of mineral interests in place. The suit further alleges that the
defendants undermeasured the volume and heating content of that natural gas
produced from privately owned wells in Zapata County, Texas. The Petition
further alleges that the County and School District were deprived of ad valorem
tax revenues as a result of the alleged undermeasurement of the natural gas by
the defendants. On December 15, 2001, the defendants filed motions to transfer
venue on jurisdictional grounds. On June 12, 2003, plaintiff served discovery
requests on certain defendants. On July 11, 2003, defendants moved to stay any
responses to such discovery.
United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil
Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado).
This action was filed on June 9, 1997 pursuant to the federal False Claims
Act and involves allegations of mismeasurement of natural gas produced from
federal and Indian lands. The Department of Justice has decided not to intervene
in support of the action. The complaint is part of a larger series of similar
complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately
330 other defendants). Certain entities we acquired in the Kinder Morgan Tejas
acquisition are also defendants in this matter. An earlier single action making
substantially similar allegations against the pipeline industry was dismissed by
Judge Hogan of the U.S. District Court for the District of Columbia on grounds
of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed
individual complaints in various courts throughout the country. In 1999, these
cases were consolidated by the Judicial Panel for Multidistrict Litigation, and
transferred to the District of Wyoming. The multidistrict litigation matter is
called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions
to dismiss were filed and an oral argument on the motion to dismiss occurred on
March 17, 2000. On July 20, 2000, the United States of America filed a motion to
dismiss those claims by Grynberg that deal with the manner in which defendants
valued gas produced from federal leases, referred to as valuation claims. Judge
Downes denied the defendant's motion to dismiss on May 18, 2001. The United
States' motion to dismiss most of plaintiff's valuation claims has been granted
by the court. Grynberg has appealed that dismissal to the 10th Circuit, which
has requested briefing regarding its jurisdiction over that appeal.
Subsequently, Grynberg's appeal was dismissed for lack of appellate
jurisdiction. Discovery to determine issues related to the Court's subject
matter jurisdiction arising out of the False Claims Act is complete. Briefing
has been completed and oral arguments on jurisdiction were held before the
Special Master on March 17 and 18, 2005. On May 7, 2003, Grynberg sought leave
to file a Third Amended Complaint, which adds allegations of undermeasurement
related to carbon dioxide production. Defendants have filed briefs opposing
leave to amend. Neither the Court nor the Special Master has ruled on Grynberg's
Motion to Amend.
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.
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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
on jurisdictional grounds of the Kinder Morgan defendants. 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. We expect that the Federal Court in Wyoming
may adopt the recommendations in this report and enter the formal dismissal
order in the fourth quarter of this year. The District Court has scheduled an
oral argument for 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' fees. The Complaint was served on
the Kinder Morgan Defendants on October 21, 2004. On November 18, 2004, the
Centerpoint Defendants removed the case to the United States District Court,
Western District of Arkansas, Texarkana Division, Civ. Action No. 04-4154. On
January 26, 2005, the Plaintiffs moved to remand the case back to state court,
which motion was granted on June 2, 2005. On July 11, 2005, the Kinder Morgan
Defendants filed a Motion to Dismiss the Complaint, which motion is currently
pending. On October 3, 2005, the Court issued a Scheduling and Case Management
Order in which it ordered that discovery could proceed, scheduled a hearing on
certain of the Kinder Morgan Defendants' Motions to Dismiss for February 14,
2006, deferred certain other motions to August 15, 2006, and scheduled a class
certification hearing, if necessary, for March 16, 2006. 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.
Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party
in interest for Enron Helium Company, a division of Enron Corp., Enron Liquids
Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder
Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252 (189th
Judicial District Court, Harris County, Texas)
On September 1, 2000, Plaintiff Exxon Mobil Corporation filed its Original
Petition and Application for Declaratory Relief against Kinder Morgan Operating
L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder
Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P.,
Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron
Helium Company. Plaintiff added Enron Corp. as party in interest for Enron
Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a
Defendant. The claims against Enron Corp. were severed into a separate cause of
action. Plaintiff's claims are based on a Gas Processing Agreement entered into
on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company
relating to gas produced in the Hugoton Field in Kansas and processed at the
Bushton Plant, a natural gas processing facility located in Kansas. Plaintiff
also asserts claims relating to the Helium Extraction Agreement entered between
Enron Helium Company (a division of Enron Corp.) and Mobil Oil Corporation dated
March 14, 1988. Plaintiff alleges that Defendants failed to deliver propane and
to allocate plant products to Plaintiff as required by the Gas Processing
Agreement and originally sought damages of approximately $5.9 million.
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Plaintiff filed its Third Amended Petition on February 25, 2003. In its
Third Amended Petition, Plaintiff alleges claims for breach of the Gas
Processing Agreement and the Helium Extraction Agreement, requests a declaratory
judgment and asserts claims for fraud by silence/bad faith, fraudulent
inducement of the 1997 Amendment to the Gas Processing Agreement, civil
conspiracy, fraud, breach of a duty of good faith and fair dealing, negligent
misrepresentation and conversion. As of April 7, 2003, Plaintiff alleged
economic damages for the period from November 1987 through March 1997 in the
amount of $30.7 million. On May 2, 2003, Plaintiff added claims for the period
from April 1997 through February 2003 in the amount of $12.9 million. On June
23, 2003, Plaintiff filed a Fourth Amended Petition that reduced its total claim
for economic damages to $30.0 million. On October 5, 2003, Plaintiff filed a
Fifth Amended Petition that purported to add a cause of action for embezzlement.
On February 10, 2004, Plaintiff filed its Eleventh Supplemental Responses to
Requests for Disclosure that restated its alleged economic damages for the
period of November 1987 through December 2003 as approximately $37.4 million.
The matter went to trial on June 21, 2004. On June 30, 2004, the jury returned a
unanimous verdict in favor of all defendants as to all counts. Final Judgment
was entered in favor of the defendants on August 19, 2004. Plaintiff has
appealed the jury's verdict to the 14th Court of Appeals for the State of Texas.
Briefing on the appeal was completed in September 2005, and the appeal has been
set for argument in November 2005.
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. 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 is claiming approximately $13 million in damages. The parties are
in the discovery phase. A trial date has been set for September 18, 2006. KMTP
will defend the case vigorously, and based upon the information available to
date, it believes that the claims against it are without merit and will be more
than offset by its claims against Cannon-Interests.
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.
Leukemia Cluster Litigation
We are a party to several lawsuits in Nevada that allege that the plaintiffs
have developed leukemia as a result of exposure to harmful substances. Based on
the information available to date, our own preliminary investigation, and the
positive results of investigations conducted by State and Federal agencies, we
believe that the claims against us in these matters are without merit and intend
to defend against them vigorously. The following is a summary of these cases.
Marie Snyder, et al v. City of Fallon, United States Department of the
Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas
Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District
Court, District of Nevada)("Snyder"); Frankie Sue Galaz, et al v. United States
of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy
Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No.
cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)("Galaz
I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial District Court,
State of Nevada, County of Washoe) ("Galaz II"); Frankie Sue Galaz, et al v. The
United States of America, the City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC (United States District
Court, District of Nevada)("Galaz III")
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On July 9, 2002, we were served with a purported Complaint for Class Action
in the Snyder case, in which the plaintiffs, on behalf of themselves and others
similarly situated, assert that a leukemia cluster has developed in the City of
Fallon, Nevada. The Complaint alleges that the plaintiffs have been exposed to
unspecified "environmental carcinogens" at unspecified times in an unspecified
manner and are therefore "suffering a significantly increased fear of serious
disease." The plaintiffs seek a certification of a class of all persons in
Nevada who have lived for at least three months of their first ten years of life
in the City of Fallon between the years 1992 and the present who have not been
diagnosed with leukemia.
The Complaint purports to assert causes of action for nuisance and "knowing
concealment, suppression, or omission of material facts" against all defendants,
and seeks relief in the form of "a court-supervised trust fund, paid for by
defendants, jointly and severally, to finance a medical monitoring program to
deliver services to members of the purported class that include, but are not
limited to, testing, preventative screening and surveillance for conditions
resulting from, or which can potentially result from exposure to environmental
carcinogens," incidental damages, and attorneys' fees and costs.
The defendants responded to the Complaint by filing Motions to Dismiss on
the grounds that it fails to state a claim upon which relief can be granted. On
November 7, 2002, the United States District Court granted the Motion to Dismiss
filed by the United States, and further dismissed all claims against the
remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs
filed a Motion for Reconsideration and Leave to Amend, which was denied by the
Court on December 30, 2002. Plaintiffs filed a Notice of Appeal to the United
States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit
affirmed the dismissal of this case.
On December 3, 2002, plaintiffs filed an additional Complaint for Class
Action in the Galaz I matter asserting the same claims in the same court on
behalf of the same purported class against virtually the same defendants,
including us. On February 10, 2003, the defendants filed Motions to Dismiss the
Galaz I Complaint on the grounds that it also fails to state a claim upon which
relief can be granted. This motion to dismiss was granted as to all defendants
on April 3, 2003. Plaintiffs have filed a Notice of Appeal to the United States
Court of Appeals for the 9th Circuit. On November 17, 2003, the 9th Circuit
dismissed the appeal, upholding the District Court's dismissal of the case.
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. Briefing of the appeal has been completed
and the parties are awaiting a decision.
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
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and several Kinder Morgan related entities and individuals and additional
unrelated defendants ("Jernee"). Plaintiffs in the Jernee matter claim that
defendants negligently and intentionally failed to inspect, repair and replace
unidentified segments of their pipeline and facilities, allowing "harmful
substances and emissions and gases" to damage "the environment and health of
human beings." Plaintiffs claim that "Adam Jernee's death was caused by leukemia
that, in turn, is believed to be due to exposure to industrial chemicals and
toxins." Plaintiffs purport to assert claims for wrongful death, premises
liability, negligence, negligence per se, intentional infliction of emotional
distress, negligent infliction of emotional distress, assault and battery,
nuisance, fraud, strict liability, and aiding and abetting, and seek unspecified
special, general and punitive damages. The Jernee case has been consolidated for
pretrial purposes with the Sands case (see below). The Court has ordered the
Plaintiffs to file Amended Complaints in both matters by November 7, 2005, and
the Defendants to file renewed Motions to Dismiss by December 5, 2005.
Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326
(Second Judicial District Court, State of Nevada, County of Washoe) ("Sands").
On August 28, 2003, a separate group of plaintiffs, represented by the
counsel for the plaintiffs in the Jernee matter, individually and on behalf of
Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court
against us and several Kinder Morgan related entities and individuals and
additional unrelated defendants ("Sands"). Plaintiffs in the Sands matter claim
that defendants negligently and intentionally failed to inspect, repair and
replace unidentified segments of their pipeline and facilities, allowing
"harmful substances and emissions and gases" to damage "the environment and
health of human beings." Plaintiffs claim that Stephanie Suzanne Sands' death
was caused by leukemia that, in turn, is believed to be due to exposure to
industrial chemicals and toxins. Plaintiffs purport to assert claims for
wrongful death, premises liability, negligence, negligence per se, intentional
infliction of emotional distress, negligent infliction of emotional distress,
assault and battery, nuisance, fraud, strict liability, and aiding and abetting,
and seek unspecified special, general and punitive damages. The Kinder Morgan
defendants were served with the Complaint on January 10, 2004. The Sands case
has been consolidated for pretrial purposes with the Jernee case (see above).
The Court has ordered the Plaintiffs to file Amended Complaints in both matters
by November 7, 2005, and the Defendants to file renewed Motions to Dismiss by
December 5, 2005.
Pipeline Integrity and Ruptures
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 us and SFPP, LP. The
Plaintiffs are homebuilders who constructed a subdivision known as Silver Creek
II located in Tucson, Arizona. Plaintiffs allege that, as a result of a July 30,
2003 pipeline rupture and accompanying release of petroleum products, soil and
groundwater adjacent to, on and underlying portions of Silver Creek II became
contaminated. Plaintiffs allege that they have incurred and continue to incur
costs, damages and expenses associated with the delay of closings of home sales
within Silver Creek II and damage to their reputation and goodwill as a result
of the rupture and release. Plaintiffs' complaint purports to assert claims for
negligence, breach of contract, trespass, nuisance, strict liability,
subrogation and indemnity, and negligence per se. Plaintiffs seek "no less than
$1,500,000 in compensatory damages and necessary response costs," a declaratory
judgment, interest, punitive damages and attorneys' fees and costs. The parties
have agreed to submit the claims to arbitration and are currently engaged in
discovery. We dispute the legal and factual bases for many of Plaintiffs'
claimed compensatory damages, deny that punitive damages are appropriate under
the facts, and intend to vigorously defend this action.
Walnut Creek, California Pipeline Rupture
On November 9, 2004, Mountain Cascade, Inc., a third-party contractor on a
water main replacement project hired by East Bay Municipal Utility District,
struck and ruptured an underground petroleum pipeline owned and operated by
SFPP, LP 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.
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
27
location of the pipeline properly prior to the excavation of the site by the
contractor. CalOSHA 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 plan to appeal 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 this accident, the following wrongful death, personal injury
and/or property damage claims have been filed against us, which cases have been
consolidated for pretrial purposes in the Superior Court of California, Contra
Costa County.
Juana Lilian Arias, et. al v. Kinder Morgan, Inc., Kinder Morgan Energy
Partners, L.P., Mountain Cascade, Inc., and Does 1-30, No. RG05195567 (Superior
Court, Alameda County, California). This complaint for personal injuries and
wrongful death was filed on January 26, 2005. Plaintiffs allege that Victor
Javier Rodriguez was killed as a result of the rupture by Mountain Cascade, Inc.
of SFPP, LP's petroleum pipeline in Walnut Creek, California and the resulting
explosion and fire. Plaintiffs allege that defendants failed to properly locate
and mark the location of the petroleum pipeline. The complaint purports to
assert claims for negligence, unfair competition, strict liability and
intentional misrepresentation. Plaintiffs seek unspecified general damages,
incidental damages, economic damages, disgorgement of profits, exemplary
damages, interest, attorneys' fees and costs.
Marilu Angeles, et. al v. Kinder Morgan, Inc., Kinder Morgan Energy
Partners, L.P., Mountain Cascade, Inc., Does 1-30 and Mariel Hernandez, No.
RG05195680 (Superior Court, Alameda County, California). This complaint for
personal injuries and wrongful death was filed on January 26, 2005. Plaintiffs
allege that Israel Hernandez was killed as a result of the rupture by Mountain
Cascade, Inc. of SFPP, LP's petroleum pipeline in Walnut Creek, California and
the resulting explosion and fire. Plaintiffs allege that defendants failed to
properly locate and mark the location of the petroleum pipeline. The complaint
purports to assert claims for negligence, unfair competition, strict liability
and intentional misrepresentation. Plaintiffs seek unspecified general damages,
incidental damages, economic damages, disgorgement of profits, exemplary
damages, interest, attorneys' fees and costs.
Jeremy and Johanna Knox v. Mountain Cascade, Inc, Kinder Morgan Energy
Partners of Houston, Inc., and Does 1 to 50, No. C 05-00281 (Superior Court,
Contra Costa County, California). This complaint for personal injuries was filed
on February 2, 2005. Plaintiffs allege that Jeremy Knox was injured as a result
of the rupture by Mountain Cascade, Inc. of SFPP, LP's petroleum pipeline in
Walnut Creek, California and the resulting explosion and fire. Plaintiffs allege
that defendants failed to properly locate and mark the location of the petroleum
pipeline. Plaintiffs assert claims for negligence, loss of consortium, and
exemplary damages in an unspecified amount.
Laura Reyes et al. v. East Bay Municipal Utility District, Mountain
Cascade, Inc. and Kinder Morgan Energy Partners, L.P , Kinder Morgan G.P., Inc.;
SFPP, L.P.; Camp Dresser & McKee Inc.; Carollo Engineers; Comforce Technical
Services, Inc. et al.; No. RG05207720 (Superior Court, Alameda County,
California). This complaint was originally filed on or about April 14, 2005, and
a Second Amended Complaint was filed on June 23, 2005. The suit is brought on
behalf of Laura Reyes, wife of deceased welder Miguel Reyes, and their three
minor children. The complaint, as amended, includes claims of wrongful death and
negligence, strict liability, unfair business practices, and intentional
misrepresentation, and seeks unspecified compensatory and exemplary damages.
Patrick and Victoria Farley v. Mountain Cascade, Inc., Kinder Morgan Energy
Partners of Houston, Inc.; East Bay Municipal Utility District; Carollo
Engineers, P.C.; Comforce Technical Services; and Does 1-100; No. 05-01573
(Superior Court, Contra Costa County, California). Plaintiffs allege that
Patrick Farley was injured as a result of the rupture by Mountain Cascade, Inc.
of SFPP, L.P.'s petroleum pipeline in Walnut Creek, California and the resulting
explosion and fire. Plaintiffs allege that defendants failed to properly locate
and mark the location of the petroleum pipeline. Plaintiffs assert claims for
negligence, loss of consortium, and exemplary damages in an unspecified amount.
Maria Ramos, individually and as successor in interest to Javier Ramos,
Erica Ramos, Ramona Ramos, Gicelda Ramos, Jasmin Ramos, and Gerardo Ramos, by
and through their guardian ad litem Maria Ramos v. East Bay Municipal Utility
District; Kinder Morgan, Inc.; Kinder Morgan Energy Partners, L.P.; Kinder
Morgan G.P., Inc.; SFPP, L.P.; City of Walnut Creek; Contra Costa County and
Does 1-100; No. C-05-01840 (Superior Court, Contra Costa County, California).
This complaint for personal injuries and wrongful death was filed on September
21, 2005. Plaintiffs allege that Javier Ramos was killed as a result of the
rupture by Mountain Cascade, Inc. of SFPP, L.P.'s petroleum pipeline in Walnut
Creek, California and the resulting explosion and fire. Plaintiffs allege that
the Kinder Morgan Defendants failed to properly locate and mark the location of
the petroleum pipeline. The complaint purports to assert claims for negligence,
unfair competition, strict liability and intentional misrepresentation.
Plaintiffs seek unspecified general damages, incidental damages, economic
damages, exemplary damages, interest, attorneys' fees and costs.
Chong Im, Kevin C. Im and Jackie Im, individually and as successor in
interest to Tae Im v. Kinder Morgan Inc.; Kinder Morgan Energy partners, L.P.;
East Bay Municipal Utility District; SFPP, L.P.; Camp Dresser & McKee, Inc.;
Carollo Engineers; Comforce Technical Services, Inc.; and Does 1-100: No.
C-05-02077 (Superior Court, Contra Costa County, California). This complaint for
personal injuries and wrongful death was filed on September 30, 2005. Plaintiffs
allege that Tae Im was killed as a result of the rupture by Mountain Cascade,
Inc. of SFPP, L.P.'s petroleum pipeline in Walnut Creek, California and the
resulting explosion and fire. Plaintiffs allege that the Kinder Morgan
Defendants failed to properly locate and mark the location of the petroleum
pipeline. The complaint purports to assert claims for negligence, willful
misconduct, and strict liability. Plaintiffs seek unspecified general damages,
incidental damages, economic damages, exemplary damages, interest, attorneys'
fees and costs.
United States Automobile Association v. East Bay Municipal Utilities
District; Mountain Cascade, Inc.; Kinder Morgan Energy Partners, L.P.; SFPP,
L.P.; Kinder Morgan G.P., Inc; Kinder Morgan, Inc,; Matamoros Pipeline, Inc.;
Carollo Engineers, P.C.; and Does 1-100; No. MSCO5-02128 (Superior Court, Contra
Costa County, California). Plaintiff United States Automobile Association
("USAA") filed this subrogation action against the defendants in order to
recover approximately $1.8 million plus interest and costs which USAA paid to
its insured, Enos Chabot, for damages to its insured's house, allegedly caused
as a result of the rupture by Mountain Cascade, Inc. of SFPP, L.P.'s petroleum
pipeline in Walnut Creek, California and the resulting explosion and fire.
Plaintiff asserts causes of action for negligence, strict liability, res ipsa,
and negligence per se against the defendants.
Based upon our initial investigation of the cause of the rupture of SFPP,
LP's petroleum pipeline by Mountain Cascade, Inc. and the resulting explosion
and fire, we intend to deny liability for the resulting deaths, injuries and
damages, to vigorously defend against such claims, and to seek contribution and
indemnity from the responsible parties.
Cordelia, California
On April 28, 2004, we discovered a spill of diesel fuel into a marsh near
Cordelia, California from a section of our Pacific operations' 14-inch Concord
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to Sacramento, California products 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 us. The damaged section of the
pipeline was removed and replaced, and the pipeline resumed operations on May 2,
2004. We have completed recovery of free flowing diesel from the marsh and have
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. We are 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.
In April 2005, we were informed by the office of the Attorney General of
California that the office was contemplating filing criminal charges against us
claiming discharge of diesel fuel arising from the April 2004 rupture from a
section of our Pacific operations' 14-inch Concord to Sacramento, California
products pipeline and the failure to make timely notice of the discharge to
appropriate state agencies. In addition, we were told that the California
Attorney General was also contemplating filing charges alleging other releases
and failures to provide timely notice regarding certain environmental incidents
at certain of our facilities in California.
On April 26, 2005, we announced that we had entered into an agreement with
the Attorney General of the State of California and the District Attorney of
Solano County, California, to settle misdemeanor charges of the unintentional,
non-negligent discharge of diesel fuel resulting from this release and the
failure to provide timely notice of a threatened discharge to appropriate state
agencies as well as other potential claims in California regarding alleged
notice and discharge incidents. In addition to the charges settled by this
agreement, we entered into an agreement in principle to settle similar
additional misdemeanor charges in Los Angeles County, California, in connection
with the unintentional, non-negligent release of approximately five gallons of
diesel fuel at our Carson refined petroleum products terminal in Los Angeles
Harbor in May 2004.
Under the settlement agreement related to the Cordelia, California incident,
SFPP, L.P. agreed to plead guilty to four misdemeanors and to pay approximately
$5.2 million in fines, penalties, restitution, environmental improvement project
funding, and enforcement training in the State of California, and agreed to be
placed on informal, unsupervised probation for a term of three years. Under the
settlement agreement related to the Carson terminal incident, we agreed to plead
guilty to two additional misdemeanors and to pay approximately $0.2 million in
fines and penalties.
In addition, we are 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. In the first nine months of 2005, we have included a
combined $8.4 million as general and administrative expense related to these
environmental issues, and we have made payments in the amount of $0.4 million as
of September 30, 2005. Since the April 2004 release in the Suisun Marsh area
near Cordelia, California, we have cooperated fully with federal and state
agencies and have worked diligently to remediate the affected areas. As of
September 30, 2005, the remediation was substantially complete.
Baker, California
In November 2004, our CALNEV pipeline, which transports refined petroleum
products from Colton, California to Las Vegas, Nevada, experienced a failure in
the line 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.
29
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. 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.
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.
Long Beach, California
In May 2005, our SFPP, L.P. pipeline in Long Beach, California experienced
a failure at the block valve and affected a limited area adjacent to the
pipeline. The release was located along the Southern California Edison power
line right-of-way and also affected a botanical nursery. Initial remediation has
been conducted and no further remediation appears to be necessary. All agency
requirements have been met and this site will be closed upon completion of the
remediation.
El Paso, Texas
In May 2005, our SFPP, L.P. pipeline in El Paso, Texas experienced a
failure on the 12-inch line located on the Fort Bliss Army Base. Initial
remediation has been conducted and we are conducting an evaluation to determine
the extent of impacts. All agency requirements have been met and this site will
be closed upon completion of the remediation.
Plant City, Florida
In September 2005, our Central Florida Pipeline, which transports refined
petroleum products from Tampa, Florida to Orlando, Florida, experienced a
pipeline release of diesel fuel affecting approximately two acres of land.
Several residential properties and commercial properties were impacted by the
release. Initial remedial measures have been implemented involving removal of
impacted soils, vegetation and restoration of the landowner's properties. All
agency requirements have been met and we are in the process of implementing
long-term site assessment and remediation activities.
Proposed Office of Pipeline Safety Civil Penalty and Compliance Order
On July 15, 2004, the U.S. Department of Transportation's Office of Pipeline
Safety ("OPS") issued a Proposed Civil Penalty and Proposed Compliance Order
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. As a
result of the alleged violations, the OPS seeks to have us implement a number of
changes to our integrity management program and also seeks to impose a proposed
civil penalty of approximately $0.3 million. We have already addressed a number
of the concerns identified by the OPS and intend to continue to work with the
OPS to ensure that our integrity management program satisfies all applicable
regulations. However, we dispute some of the OPS findings and disagree that
civil penalties are appropriate, and therefore have requested an administrative
hearing on these matters according to the U.S. Department of Transportation
regulations. An administrative hearing was held on April 11 and 12, 2005. We
have provided supplemental information to the hearing officer and to the OPS. It
30
is anticipated that the decision in this matter and potential administrative
order will be issued by the end of the first quarter of 2006.
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 U.S. Department of Transportation's Pipeline and Hazardous
Materials Safety Administration ("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. 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. The Corrective Order requires 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.
While we expect to appeal certain elements in the Corrective Order, we have
been working, and will continue to work, cooperatively with PHMSA to resolve the
matters identified in the Order. 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 do not expect that our compliance with the Corrective Order will
have a material adverse effect on our business, financial position, results of
operations or cash flows.
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.
As of June 30, 2005, we had conducted an internal investigation of the
allegations and discovered no evidence of wrongdoing or improper activities at
these two terminals. Furthermore, we are contacting customers of these terminals
during the applicable time period and will offer 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. We are fully cooperating with federal law
enforcement authorities in this investigation. In September 2005, we responded
to a subpoena in this matter by producing a large volume of documents, which, we
understand, is being reviewed by the FBI and auditors from the Tennessee Valley
Authority, which is a customer of the Cora and Grand Rivers terminals. 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.
Environmental Matters
We are subject to environmental cleanup and enforcement actions from time to
time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) generally imposes joint and several
liability for cleanup and enforcement costs on current or predecessor owners and
operators of a site, 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.
31
We are currently involved in the following governmental proceedings related
to compliance with environmental regulations associated with our assets and have
established a reserve to address the costs associated with the cleanup:
- several groundwater and soil remediation efforts under administrative
orders or related state remediation programs issued by the California
Regional Water Quality Control Board and several other state agencies
for assets associated with SFPP, L.P.;
- groundwater and soil remediation efforts under administrative orders
issued by various regulatory agencies on those assets purchased from GATX
Corporation, comprising Kinder Morgan Liquids Terminals LLC, KM Liquids
Terminals L.P., CALNEV Pipe Line LLC and Central Florida Pipeline LLC;
- groundwater and soil remediation efforts under administrative orders or
related state remediation programs issued by various regulatory agencies
on those assets purchased from ExxonMobil; ConocoPhillips; and Charter
Triad, comprising Kinder Morgan Southeast Terminals, LLC.; and
- groundwater and soil remediation efforts under administrative orders or
related state remediation programs issued by various regulatory agencies
on those assets comprising Plantation Pipe Line Company.
San Diego, California
In June 2004, we entered into discussions with the City of San Diego with
respect to impacted groundwater beneath the City's stadium property in San Diego
resulting from operations at the Mission Valley terminal facility. The City has
requested that SFPP work with the City as they seek to re-develop options for
the stadium area including future use of both groundwater aquifer and real
estate development. The City of San Diego and SFPP are working cooperatively
towards a settlement and a long-term plan as SFPP continues to remediate the
impacted groundwater. We do not expect the cost of any settlement and
remediation plan to be material. This site has been, and currently is, under the
regulatory oversight and order of the California Regional Water Quality Control
Board.
Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids
Terminals, Inc. and ST Services, Inc.
On April 23, 2003, Exxon Mobil Corporation filed the Complaint in the
Superior Court of New Jersey, Gloucester County. We filed our answer to the
Complaint on June 27, 2003, in which we denied ExxonMobil's claims and
allegations as well as included counterclaims against ExxonMobil. The lawsuit
relates to environmental remediation obligations at a Paulsboro, New Jersey
liquids terminal owned by ExxonMobil from the mid-1950s through November 1989,
by GATX Terminals Corp. from 1989 through September 2000, and owned currently by
ST Services, Inc. Prior to selling the terminal to GATX Terminals, ExxonMobil
performed an environmental site assessment of the terminal required prior to
sale pursuant to state law. During the site assessment, ExxonMobil discovered
items that required remediation and the New Jersey Department of Environmental
Protection issued an order that required ExxonMobil to perform various
remediation activities to remove hydrocarbon contamination at the terminal.
ExxonMobil, we understand, is still remediating the site and has not been
removed as a responsible party from the state's cleanup order; however,
ExxonMobil claims that the remediation continues because of GATX Terminals'
storage of a fuel additive, MTBE, at the terminal during GATX Terminals'
ownership of the terminal. When GATX Terminals sold the terminal to ST Services,
the parties indemnified one another for certain environmental matters. When GATX
Terminals was sold to us, GATX Terminals' indemnification obligations, if any,
to ST Services may have passed to us. Consequently, at issue is any
indemnification obligations we may owe to ST Services in respect to
environmental remediation of MTBE at the terminal. The Complaint seeks any and
all damages related to remediating MTBE at the terminal, and, according to the
New Jersey Spill Compensation and Control Act, treble damages may be available
for actual dollars incorrectly spent by the successful party in the lawsuit for
remediating MTBE at the terminal. The parties have recently completed 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 mediation is currently scheduled for
November 2, 2005.
32
Other Environmental
On March 30, 2004, the Texas Commission on Environmental Quality (TCEQ)
issued a Notice of Enforcement Action related to our CO2 segment's Snyder Gas
Plant. On August 4, 2005, we received an executed settlement agreement with the
TCEQ for approximately $0.3 million, of which approximately $0.1 million was
applied to a supplemental environmental project in Scurry County, Texas.
Our review of assets related to Kinder Morgan Interstate Gas Transmission
LLC indicates possible environmental impacts from petroleum and used oil
releases into the soil and groundwater at nine sites. Additionally, our review
of assets related to Kinder Morgan Texas Pipeline and Kinder Morgan Tejas
indicates possible environmental impacts from petroleum releases into the soil
and groundwater at nine sites. Further delineation and remediation of any
environmental impacts from these matters will be conducted. Reserves have been
established to address these issues.
See "--Pipeline Integrity and Ruptures" above for information with respect
to the environmental impact of recent ruptures of some of our pipelines.
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.
Although no assurance can be given, we believe that the ultimate resolution
of the environmental matters set forth in this note will not have a material
adverse effect on our business, financial position, results of operations or
cash flows. However, we are not able to reasonably estimate when the eventual
settlements of these claims will occur. Many factors may change in the future
affecting our reserve estimates, such as regulatory changes, groundwater and
land use near our sites, and changes in cleanup technology. As of September 30,
2005, we have accrued an environmental reserve of $26.7 million.
Other
We are a defendant in various lawsuits arising from the day-to-day
operations of our businesses. Although no assurance can be given, we believe,
based on our experiences to date, that the ultimate resolution of such items
will not have a material adverse impact on our business, financial position,
results of operations or cash flows.
4. Asset Retirement Obligations
We account for our legal obligations associated with the retirement of
long-lived assets pursuant to Statement of Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides
accounting and reporting guidance for legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction
or normal operation of a long-lived asset.
SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. Under SFAS No. 143,
the fair value of asset retirement obligations are recorded as liabilities on a
discounted basis when they are incurred, which is typically at the time the
assets are installed or acquired. Amounts recorded for the related assets are
increased by the amount of these obligations. Over time, the liabilities will be
accreted for the change in their present value and the initial capitalized costs
will be depreciated over the useful lives of the related assets. The liabilities
are eventually extinguished when the asset is taken out of service.
In our CO2 business segment, we are required to plug and abandon oil and
gas wells that have been removed from service and to remove our surface wellhead
equipment and compressors. As of September 30, 2005, we have
33
recognized asset retirement obligations in the aggregate amounts of $35.9
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 September 30, 2005, we have recognized
asset retirement obligations in the aggregate amounts of $1.7 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 September 30, 2005 with "Accrued other current liabilities" in our
accompanying consolidated balance sheet. The remaining $36.8 million obligation
is reported separately as a non-current liability. No assets are legally
restricted for purposes of settling our asset retirement obligations. A
reconciliation of the beginning and ending aggregate carrying amount of our
asset retirement obligations for each of the nine months ended September 30,
2005 and 2004 is as follows (in thousands):
Nine Months Ended September 30,
-------------------------------
2005 2004
------------ ------------
Balance at beginning of period........ $ 38,274 $ 35,708
Liabilities incurred................ 521 130
Liabilities settled................. (1,497) (516)
Accretion expense................... 807 1,559
Revisions in estimated cash flows... (522) -
------------ ------------
Balance at end of period.............. $ 37,583 $ 36,881
============ ============
5. Distributions
On August 12, 2005, we paid a cash distribution of $0.78 per unit to our
common unitholders and our Class B unitholders for the quarterly period ended
June 30, 2005. KMR, our sole i-unitholder, received 909,009 additional i-units
based on the $0.78 cash distribution per common unit. The distributions were
declared on July 20, 2005, payable to unitholders of record as of July 29, 2005.
On October 19, 2005, we declared a cash distribution of $0.79 per unit for
the quarterly period ended September 30, 2005. The distribution will be paid on
November 14, 2005, to unitholders of record as of October 31, 2005. 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 $0.79 distribution
per common unit. The number of i-units distributed will be 932,292. For each
outstanding i-unit that KMR holds, a fraction of an i-unit (0.016360) will be
issued. The fraction was determined by dividing:
- $0.79, the cash amount distributed per common unit
by
- $48.288, the average of KMR's limited liability shares' closing market
prices from October 13-26, 2005, the ten consecutive trading days
preceding the date on which the shares began to trade ex-dividend under
the rules of the New York Stock Exchange.
6. Intangibles
Our intangible assets include goodwill, lease value, contracts and
agreements. All of our intangible assets having definite lives are being
34
amortized on a straight-line basis over their estimated useful lives. Following
is information related to our intangible assets still subject to amortization
and our goodwill (in thousands):
September 30, December 31,
2005 2004
Goodwill
Gross carrying amount.... $ 800,180 $ 746,980
Accumulated amortization. (14,142) (14,142)
----------- -----------
Net carrying amount...... 786,038 732,838
----------- -----------
Lease value
Gross carrying amount.... 6,592 6,592
Accumulated amortization. (1,134) (1,028)
----------- -----------
Net carrying amount...... 5,458 5,564
----------- -----------
Contracts and other
Gross carrying amount.... 210,480 10,775
Accumulated amortization. (5,373) (1,055)
----------- -----------
Net carrying amount...... 205,107 9,720
----------- -----------
Total intangibles, net..... $ 996,603 $ 748,122
=========== ===========
Amortization expense on our intangibles consisted of the following (in
thousands):
Three Months Ended September 30, Nine Months Ended September 30,
2005 2004 2005 2004
Lease value............ $ 35 $ 35 $ 106 $ 105
Contracts and other.... 3,487 205 4,318 535
----------- ----------- ----------- -----------
Total amortization..... $ 3,522 $ 240 $ 4,424 $ 640
=========== =========== =========== ===========
As of September 30, 2005, our weighted average amortization period for our
intangible assets was approximately 23.3 years. Our estimated amortization
expense for these assets for each of the next five fiscal years is approximately
$10.7 million, $10.4 million, $10.3 million, $10.1 million and $10.1 million,
respectively.
Goodwill
Changes in the carrying amount of goodwill for the nine months ended
September 30, 2005 are summarized as follows (in thousands):
Products Natural Gas
Pipelines Pipelines CO2 Terminals Total
Balance as of December 31, 2004.... $ 263,182 $ 250,318 $ 46,101 $ 173,237 $ 732,838
Acquisitions and purchase price 13,088 12,092 - 28,020 53,200
adjs...............................
Disposals........................ - - - - -
Impairments...................... - - - - -
----------- ----------- ----------- ----------- -----------
Balance as of September 30, 2005... $ 276,270 $ 262,410 $ 46,101 $ 201,257 $ 786,038
=========== =========== =========== =========== ===========
Equity Method Goodwill
In addition, pursuant to ABP No. 18, any premium paid by an investor, which
is analogous to goodwill, must be identified. The premium, representing excess
cost over underlying fair value of net assets accounted for under the equity
method of accounting, is referred to as equity method goodwill, and is not
subject to amortization but rather to impairment testing. The impairment test
under APB No. 18 considers whether the fair value of the equity investment as a
whole, not the underlying net assets, has declined and whether that decline is
other than temporary. This test requires equity method investors to continue to
assess impairment of investments in investees by considering whether declines in
the fair values of those investments, versus carrying values, may be other than
temporary in nature. 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
well as the amortization period for such assets, to determine whether current
events or circumstances warrant adjustments to our carrying value and/or revised
estimates of useful lives in accordance with APB Opinion No. 18.
35
7. Debt
Our outstanding short-term debt as of September 30, 2005 was $546.7 million.
The balance consisted of:
- $538.7 million of commercial paper borrowings;
- a $5 million portion of 7.84% senior notes (our subsidiary, Central
Florida Pipe Line LLC, is the obligor on the notes);
- a $4.2 million portion of 8.85% senior notes (our subsidiary, Kinder
Morgan Texas Pipeline, L.P., is the obligor on the notes); and
- an offset of $1.2 million (which represents the net of other borrowings
and the accretion of discounts on our senior note issuances).
As of September 30, 2005, we intended and had the ability to refinance all
of our short-term debt on a long-term basis under our unsecured long-term credit
facility. Accordingly, such amounts have been classified as long-term debt in
our accompanying consolidated balance sheet.
The weighted average interest rate on all of our borrowings was
approximately 5.069% during the third quarter of 2005 and 4.591% during the
third quarter of 2004.
Credit Facility
On August 5, 2005, we increased our existing bank facility from $1.25
billion to $1.6 billion, and we extended the maturity one year to August 18,
2010. Wachovia Bank, National Association continues as the administrative agent.
The borrowing rates decreased slightly under the extended agreement, and there
were minor changes to the financial covenants as compared to the covenants under
our previous bank facility.
There were no borrowings under our five-year credit facility as of September
30, 2005, and no borrowings under our previous facility as of December 31, 2004.
The amount available for borrowing under our credit facility as of September 30,
2005 was reduced by:
- our outstanding commercial paper borrowings ($538.7 million as of
September 30, 2005);
- a combined $609 million in four 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;
- a combined $50 million in two letters of credit that support tax-exempt
bonds; and
- $8.1 million of other letters of credit supporting other obligations of
us and our subsidiaries.
36
Interest Rate Swaps
Information on our interest rate swaps is contained in Note 10.
Commercial Paper Program
On August 5, 2005, we increased our commercial paper program by $350 million
to provide for the issuance of up to $1.6 billion. Our new $1.6 billion
unsecured 5-year credit facility supports our commercial paper program, and
borrowings under our commercial paper program reduce the borrowings allowed
under our credit facility. As of September 30, 2005, we had $538.7 million of
commercial paper outstanding with an average interest rate of 3.7404%.
Senior Notes
On March 15, 2005, we paid $200 million to retire the principal amount of
our 8.0% senior notes that matured on that date. We borrowed the necessary funds
under our commercial paper program.
On March 15, 2005, we closed a public offering of $500 million in principal
amount of 5.80% senior notes due March 15, 2035 at a price to the public of
99.746% per note. In the offering, we received proceeds, net of underwriting
discounts and commissions, of approximately $494.4 million. We used the proceeds
to reduce the outstanding balance on our commercial paper borrowings.
International Marine Terminals Debt
Since February 1, 2002, we have owned a 66 2/3% interest in International
Marine Terminals partnership. The principal assets owned by IMT are dock and
wharf facilities financed by the Plaquemines Port, Harbor and Terminal District
(Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities Revenue
Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B.
On March 15, 2005, these bonds were refunded and the maturity date was
extended from March 15, 2006 to March 15, 2025. No other changes were made under
the bond provisions. The bonds are backed by two letters of credit issued by KBC
Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit
Reimbursement Agreement relating to the letters of credit in the amount of $45.5
million was entered into by IMT and KBC Bank. In connection with that agreement,
we agreed to guarantee the obligations of IMT in proportion to our ownership
interest. Our obligation is approximately $30.3 million for principal, plus
interest and other fees.
General Stevedores, L.P. Debt
Effective July 31, 2005, we acquired all of the partnership interests in
General Stevedores, L.P. (see Note 3). As part of our purchase price, we assumed
approximately $3.0 million in principal amount of outstanding debt, primarily
consisting of commercial bank loans. In August 2005, we paid the $3.0 million
outstanding debt balance, and following our repayment, General Stevedores, L.P.
had no outstanding debt.
Kinder Morgan Texas Pipeline, L.P. Debt
Effective August 1, 2005, we acquired a natural gas storage facility in
Liberty County, Texas (see Note 3). As part of our purchase price, we assumed an
aggregate principal amount of $49.2 million of privately placed unsecured senior
notes. Our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the obligor on the
notes. The unsecured senior notes have a fixed annual interest rate of 8.85% and
the assumed principal amount, along with interest, is due in monthly
installments of approximately $0.7 million. The final payment is due January 2,
2014.
Additionally, the unsecured senior notes may be prepaid at any time in
amounts of at least $1.0 million at a price equal to the higher of par value or
the present value of the remaining scheduled payments of principal and interest
on the portion being prepaid. The notes also contain certain covenants similar
to those contained in our current five-year, unsecured revolving credit
facility. We do not believe that these covenants will materially affect
distributions to our partners.
37
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 basis, the obligations of
the Cortez Pipeline Company partners under the Throughput and Deficiency
Agreement.
Due to our indirect ownership of Cortez Pipeline Company through Kinder
Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez
Capital Corporation. Shell Oil Company shares our several guaranty obligations
jointly and severally; however, we are obligated to indemnify Shell for
liabilities it incurs in connection with such guaranty. With respect to Cortez's
long-term revolving credit facility, Shell is 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 September 30, 2005, the debt facilities of Cortez Capital Corporation
consisted of:
- $75 million of Series D notes due May 15, 2013;
- a $125 million short-term commercial paper program; and
- a $125 million five-year committed revolving credit facility due
December 22, 2009 (to support the above-mentioned $125 million
commercial paper program).
As of September 30, 2005, Cortez Capital Corporation had $100.1 million of
commercial paper outstanding with an average interest rate of 3.6582%, the
average interest rate on the Series D notes was 7.14%, and there were no
borrowings under the credit facility.
Red Cedar Gathering Company Debt
In October 1998, Red Cedar Gathering Company sold $55 million in aggregate
principal amount of Senior Notes due October 31, 2010. The $55 million was sold
in 10 different notes in varying amounts with identical terms.
The Senior Notes are collateralized by a first priority lien on the
ownership interests, including our 49% ownership interest, in Red Cedar
Gathering Company. The Senior Notes are also guaranteed by us and the other
owner of Red Cedar Gathering Company jointly and severally. The principal is to
be repaid in seven equal installments beginning on October 31, 2004 and ending
on October 31, 2010. As of September 30, 2005, $47.1 million in principal amount
of notes were outstanding.
38
Nassau County, Florida Ocean Highway and Port Authority Debt
Nassau County, Florida Ocean Highway and Port Authority is a political
subdivision of the State of Florida. During 1990, Ocean Highway and Port
Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal
amount of $38.5 million for the purpose of constructing certain port
improvements located in Fernandino Beach, Nassau County, Florida. A letter of
credit was issued as security for the Adjustable Demand Revenue Bonds and was
guaranteed by the parent company of Nassau Terminals LLC, the operator of the
port facilities. In July 2002, we acquired Nassau Terminals LLC and became
guarantor under the letter of credit agreement. In December 2002, we issued a
$28 million letter of credit under our credit facilities and the former letter
of credit guarantee was terminated. Principal payments on the bonds are made on
the first of December each year and reductions are made to the letter of credit.
As of September 30, 2005, the value of this letter of credit outstanding under
our credit facility was $25.9 million.
Certain Relationships and Related Transactions
In conjunction with our acquisition of Natural Gas Pipelines assets from KMI
on December 31, 1999, December 31, 2000, and November 1, 2004, KMI became a
guarantor of approximately $733.5 million of our debt. KMI would be obligated to
perform under this guarantee only if we and/or our assets were unable to satisfy
our obligations.
For additional information regarding our debt facilities, see Note 9 to our
consolidated financial statements included in our Form 10-K for the year ended
December 31, 2004.
8. Partners' Capital
As of September 30, 2005 and December 31, 2004, our partners' capital
consisted of the following limited partner units:
September 30, December 31,
2004 2005
----------- -----------
Common units.................. 154,403,326 147,537,908
Class B units................. 5,313,400 5,313,400
i-units....................... 56,986,081 54,157,641
----------- -----------
Total limited partner units. 216,702,807 207,008,949
=========== ===========
The total limited partner units represent our limited partners' interest and
an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights.
As of September 30, 2005, our common unit totals consisted of 140,047,591
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. As of December 31, 2004, our common unit total consisted of
133,182,173 units held by third parties, 12,631,735 units held by KMI and its
consolidated affiliates (excluding our general partner) and 1,724,000 units held
by our general partner.
On August 16, 2005, we issued, in a public offering, 5,000,000 of our common
units at a price of $51.25 per unit, less commissions and underwriting expenses.
At the time of the offering, we granted the underwriters a 30-day option to
purchase up to an additional 750,000 common units from us on the same terms and
conditions, and pursuant to this option, we issued an additional 750,000 common
units on September 9, 2005 upon exercise of this option. After commissions and
underwriting expenses, we received net proceeds of $283.6 million for the
issuance of these 5,750,000 common units, and we used the proceeds to reduce the
borrowings under our commercial paper program.
On both September 30, 2005 and December 31, 2004, our Class B units were
held entirely by KMI and our i-units were held entirely by KMR. All of our Class
B units were issued to 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.
39
Our i-units are a separate class of limited partner interests in us. All of
our i-units are owned by KMR and are not publicly traded. In accordance with its
limited liability company agreement, KMR's activities are restricted to being a
limited partner in us, and controlling and managing our business and affairs and
the business and affairs of our operating limited partnerships and their
subsidiaries. Through the combined effect of the provisions in our partnership
agreement and the provisions of KMR's limited liability company agreement, the
number of outstanding KMR shares and the number of i-units will at all times be
equal.
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 909,009 i-units from us on August 12,
2005. These additional i-units distributed were based on the $0.78 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 $0.78 per unit paid on August 12, 2005 for
the second quarter of 2005 required an incentive distribution to our general
partner of $115.7 million. Our distribution of $0.71 per unit paid on August 13,
2004 for the second quarter of 2004 required an incentive distribution to our
general partner of $94.9 million. The increased incentive distribution to our
general partner paid for the second quarter of 2005 over the distribution paid
for the second quarter of 2004 reflects the increase in the amount distributed
per unit as well as the issuance of additional units.
Our declared distribution for the third quarter of 2005 of $0.79 per unit
will result in an incentive distribution to our general partner of approximately
$121.5 million. This compares to our distribution of $0.73 per unit and
incentive distribution to our general partner of approximately $99.1 million for
the third quarter of 2004.
9. Comprehensive Income
SFAS No. 130, "Accounting for Comprehensive Income," requires that
enterprises report a total for comprehensive income. For the three and nine
months ended September 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 the three and nine months ended September 30, 2004, the only difference
between our net income and our comprehensive income was the unrealized gain or
loss on derivatives utilized for hedging purposes. For more information on our
hedging activities, see Note 10. Our total comprehensive income is as follows
(in thousands):
40
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ ----------------------
2005 2004 2005 2004
---------- --------- ----------- ----------
Net income.................................................... $ 245,387 $ 217,342 $ 690,834 $ 604,314
Foreign currency translation adjustments ..................... 8 - (596) -
Change in fair value of derivatives used for hedging purposes. (259,826) (268,212) (1,016,695) (504,234)
Reclassification of change in fair value of derivatives to net income 141,361 45,002 287,032 118,214
---------- --------- ----------- ----------
Comprehensive income/(loss)................................. $ 126,930 $ (5,868) $ (39,425) $ 218,294
========== ========= =========== ==========
10. Risk Management
Hedging Activities
Certain of our business activities expose us to risks associated with
changes in the market price of natural gas, natural gas liquids, crude oil and
carbon dioxide. We use energy financial instruments to reduce our risk of
changes in the prices of natural gas, natural gas liquids and crude oil markets
(and carbon dioxide to the extent contracts are tied to crude oil prices) as
discussed below. These risk management instruments are also called derivatives,
which are defined as a financial instrument or other contract which derives its
value from the value of some other financial instrument or variable. The value
of a derivative (for example, options, swaps, futures contracts, etc.) is a
function of the underlying (for example, a specified interest rate, commodity
price, foreign exchange rate, or other variable) and the notional amount (for
example, a number of currency units, shares, commodities, or other units
specified in a derivative instrument), and while the value of the underlying
changes due to changes in market conditions, the notional amount remains
constant throughout the life of the derivative contract.
Current accounting standards require derivatives to be reflected as assets
or liabilities at their fair market values and the fair value of our risk
management instruments reflects the estimated amounts that we would receive or
pay to terminate the contracts at the reporting date, thereby taking into
account the current unrealized gains or losses on open contracts. We have
available market quotes for substantially all of the financial instruments that
we use, including: commodity futures and options contracts, fixed-price swaps,
and basis swaps.
Pursuant to our management's approved risk management policy, we are to
engage in these activities as a hedging mechanism against price volatility
associated with:
- pre-existing or anticipated physical natural gas, natural gas liquids
and crude oil sales;
- pre-existing or anticipated physical carbon dioxide sales that have
pricing tied to crude oil prices;
- natural gas purchases; and
- system use and storage.
Our risk management activities are 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.
Specifically, our risk management committee is a separately designated
standing committee comprised of 15 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. Our risk management committee is chaired by our Chief Financial
Officer and is charged with the following three responsibilities:
- establish and review risk limits consistent with our risk tolerance
philosophy;
- recommend to the audit committee of our general partner's delegate any
changes, modifications, or amendments to our trading policy; and
41
- address and resolve any other high-level risk management issues.
Our derivatives hedge the commodity price risks derived from our normal
business activities, which include the sale of natural gas, natural gas liquids,
oil and carbon dioxide, and these derivatives have been designated by us as cash
flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that
hedge exposure to variable cash flows of forecasted transactions as cash flow
hedges and the effective portion of the derivative's gain or loss is initially
reported as a component of other comprehensive income (outside earnings) and
subsequently is reclassified into earnings when the hedged forecasted
transaction affects earnings. If the transaction results in an asset or
liability, amounts in accumulated other comprehensive income should be
reclassified into earnings when the asset or liability affects earnings through
cost of sales, depreciation, interest expense, etc. To be considered effective,
changes in the value of the derivative or its resulting cash flows must
substantially offset changes in the value or cash flows of the item being
hedged. The ineffective portion of the gain or loss and any component excluded
from the computation of the effectiveness of the derivative instrument is
reported in earnings immediately. In addition, in conjunction with the purchase
of exchange-traded derivatives or when the market value of our derivatives with
specific counterparties exceeds established limits, we are required to provide
collateral to our counterparties, which may include posting letters of credit or
placing funds in margin accounts (reported as "Restricted deposits" in the
accompanying interim consolidated balance sheet). As of September 30, 2005, we
had four outstanding letters of credit totaling $609 million in support of our
hedging of commodity price risks associated with the sale of natural gas,
natural gas liquids, crude oil and carbon dioxide.
The gains and losses that are included in "Accumulated other comprehensive
loss" in our accompanying consolidated balance sheets are primarily related to
the derivative instruments associated with our commodity market risk hedging
activities, and these gains and losses are reclassified into earnings as the
hedged sales and purchases take place. Approximately $406.1 million of the
Accumulated other comprehensive loss balance of $1,187.6 million as of September
30, 2005 is expected to be reclassified into earnings during the next twelve
months.
During the nine months ended September 30, 2005 and 2004, we reclassified
$287.0 million and $118.2 million, respectively, of Accumulated other
comprehensive loss into earnings. The reclassification of Accumulated other
comprehensive loss into earnings during the nine months ended September 30, 2005
reduced the Accumulated other comprehensive loss balance of $457.3 million as of
December 31, 2004. None of the reclassification of Accumulated other
comprehensive loss into earnings during the first nine months of 2005 or 2004
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 ineffective portion of the gain or loss on a cash
flow hedging instrument is required to be recognized currently in earnings.
Accordingly, we recognized a loss of $1.9 million during the third quarter of
2005 and a loss of $2.3 million during the first nine months of 2005 as a result
of ineffective hedges, and we recognized a minimal amount (less than $0.1
million) of gain or loss during the third quarter and the first nine months of
2004 as a result of ineffective hedges. All gains and losses recognized as a
result of ineffective hedges are reported within the captions "Natural gas
sales" and "Gas purchases and other costs of sales" in our accompanying
consolidated statements of income. For each of the nine months ended September
30, 2005 and 2004, we did not exclude any component of the derivative
instruments' gain or loss from the assessment of hedge effectiveness.
The differences between the current market value and the original physical
contracts value associated with our commodity market hedging activities are
included within "Other current assets", "Accrued other current liabilities",
"Deferred charges and other assets" and "Other long-term liabilities and
deferred credits" in our accompanying consolidated balance sheets. The following
table summarizes the net fair value of our energy financial instruments
associated with our commodity market risk management activities and included on
our accompanying consolidated balance sheets as of September 30, 2005 and
December 31, 2004 (in thousands):
42
September 30, December 31,
2005 2004
------------------------------
Derivatives-net asset/(liability)
Other current assets............................... $ 201,439 $ 41,010
Deferred charges and other assets.................. 81,264 17,408
Accrued other current liabilities.................. (617,259) (218,967)
Other long-term liabilities and deferred credits... $ (871,110) $ (309,035)
Our over-the-counter swaps and options are with a number of parties, who
principally have investment grade credit ratings. We both owe money and are owed
money under these financial instruments; however, as of both September 30, 2005
and December 31, 2004, we were essentially in a net payable position and had
virtually no amounts owed to us from other parties. In addition, defaults by
counterparties under over-the-counter swaps and options could expose us to
additional commodity price risks in the event that we are unable to enter into
replacement contracts for such swaps and options on substantially the same
terms. Alternatively, we may need to pay significant amounts to the new
counterparties to induce them to enter into replacement swaps and options on
substantially the same terms. While we enter into derivative transactions
principally with investment grade counterparties and actively monitor their
credit ratings, it is nevertheless possible that from time to time losses will
result from counterparty credit risk in the future.
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.
Interest Rate Swaps
In order to maintain a cost effective capital structure, it is our policy to
borrow funds using a mix of fixed rate debt and variable rate debt. As of
September 30, 2005 and December 31, 2004, we were a party to interest rate swap
agreements with notional principal amounts of $2.1 billion and $2.3 billion,
respectively. We entered into these agreements for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt obligations.
As of September 30, 2005, 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:
- $200 million principal amount of our 5.35% senior notes due August 15,
2007;
- $250 million principal amount of our 6.30% senior notes due
February 1, 2009;
- $200 million principal amount of our 7.125% senior notes due
March 15, 2012;
- $250 million principal amount of our 5.0% senior notes due
December 15, 2013;
- $200 million principal amount of our 5.125% senior notes due
November 15, 2014;
- $300 million principal amount of our 7.40% senior notes due
March 15, 2031;
- $200 million principal amount of our 7.75% senior notes due
March 15, 2032;
- $400 million principal amount of our 7.30% senior notes due
August 15, 2033; and
- $100 million principal amount of our 5.80% senior notes due
March 15, 2035.
These swap agreements have termination dates that correspond to the
maturity dates of the related series of senior notes, therefore, as of September
30, 2005, 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. These interest rate swaps have been designated as
fair value hedges as defined by SFAS No. 133. SFAS No. 133
43
designates derivatives that hedge a recognized asset or liability's exposure to
changes in their fair value as fair value hedges and the gain or loss on fair
value hedges are to be recognized in earnings in the period of change together
with the offsetting loss or gain on the hedged item attributable to the risk
being hedged. The effect of that accounting is to reflect in earnings the extent
to which the hedge is not effective in achieving offsetting changes in fair
value.
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.
As of December 31, 2004, we also had swap agreements that effectively
converted the interest expense associated with $100 million of our variable rate
debt to fixed rate debt. Half of these agreements, converting $50 million of our
variable rate debt to fixed rate debt, matured on August 1, 2005, and the
remaining half matured on September 1, 2005. These swaps were designated as a
cash flow hedge of the risk associated with changes in the designated benchmark
interest rate (in this case, one-month LIBOR) related to forecasted payments
associated with interest on an aggregate of $100 million of our portfolio of
commercial paper.
Our interest rate swaps meet the conditions required to assume no
ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed for fair value hedges by SFAS No. 133.
Accordingly, we adjust the carrying value of each swap to its fair value each
quarter, with an offsetting entry to adjust the carrying value of the debt
securities whose fair value is being hedged. We record interest expense equal to
the variable rate payments or fixed rate payments under the swaps. Interest
expense is accrued monthly and paid semi-annually.
The differences between fair value and the original carrying value
associated with our interest rate swap agreements are included within "Deferred
charges and other assets" and "Other long-term liabilities and deferred credits"
in our accompanying consolidated balance sheets. The offsetting entry to adjust
the carrying value of the debt securities whose fair value was being hedged is
recognized as "Market value of interest rate swaps" on our accompanying
consolidated balance sheets.
The following table summarizes the net fair value of our interest rate swap
agreements associated with our interest rate risk management activities and
included on our accompanying consolidated balance sheets as of September 30,
2005 and December 31, 2004 (in thousands):
September 30, December 31,
2005 2004
------------ ------------
Derivatives-net asset/(liability)
Deferred charges and other assets................. $ 121,759 $ 132,210
Other long-term liabilities and deferred credits.. (6,706) (2,057)
--------- ----------
Market value of interest rate swaps............. $ 115,053 $ 130,153
========= ==========
We are exposed to credit related losses in the event of nonperformance by
counterparties to these interest rate swap agreements. While we enter into
derivative transactions primarily with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that from
time to time losses will result from counterparty credit risk.
11. Reportable Segments
We divide our operations into four reportable business segments:
- Products Pipelines;
- Natural Gas Pipelines;
44
- CO2; and
- 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 transmission, storage,
gathering and sale of natural gas. Our CO2 segment derives its revenues
primarily from the production and sale of crude oil from fields in the Permian
Basin of West Texas and from the transportation and marketing of carbon dioxide
used as a flooding medium for recovering crude oil from mature oil fields. Our
Terminals segment derives its revenues primarily from the transloading and
storing of refined petroleum products and dry and liquid bulk products,
including coal, petroleum coke, cement, alumina, salt, and chemicals.
Financial information by segment follows (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
2005 2004 2005 2004
-------------- -------------- -------------- -------------
Revenues
Products Pipelines................................. $ 181,903 $ 160,867 $ 527,818 $ 475,187
Natural Gas Pipelines.............................. 2,108,788 1,598,554 5,198,337 4,591,293
CO2................................................ 163,079 121,777 488,271 337,935
Terminals.......................................... 177,484 133,461 515,115 389,682
------------- ------------- ------------- -------------
Total consolidated revenues........................ $ 2,631,254 $ 2,014,659 $ 6,729,541 $ 5,794,097
============= ============= ============= =============
Operating expenses(a)
Products Pipelines................................. $ 60,613 $ 46,489 $ 169,739 $ 135,792
Natural Gas Pipelines.............................. 1,996,737 1,498,030 4,863,524 4,301,857
CO2................................................ 48,546 43,331 152,389 123,620
Terminals.......................................... 94,318 63,943 271,470 188,336
------------- ------------- ------------- -------------
Total consolidated operating expenses.............. $ 2,200,214 $ 1,651,793 $ 5,457,122 $ 4,749,605
============= ============= ============= =============
Depreciation, depletion and amortization
Products Pipelines................................. $ 19,849 $ 17,951 $ 59,071 $ 52,751
Natural Gas Pipelines.............................. 15,205 13,191 45,779 38,959
CO2................................................ 34,658 30,465 111,822 86,583
Terminals.......................................... 15,644 10,607 41,972 31,330
------------- ------------- ------------- -------------
Total consol. depreciation, depletion and amortization $ 85,356 $ 72,214 $ 258,644 $ 209,623
============= ============= ============= =============
Earnings from equity investments
Products Pipelines................................. $ 6,256 $ 7,658 $ 21,706 $ 21,610
Natural Gas Pipelines.............................. 8,705 5,280 25,733 14,558
CO2................................................ 5,533 7,711 21,932 25,552
Terminals.......................................... 18 (4) 51 3
------------- ------------- ------------- -------------
Total consolidated equity earnings................. $ 20,512 $ 20,645 $ 69,422 $ 61,723
============= ============= ============= =============
Amortization of excess cost of equity investments
Products Pipelines................................. $ 832 $ 819 $ 2,512 $ 2,461
Natural Gas Pipelines.............................. 70 70 208 208
CO2................................................ 505 505 1,513 1,513
Terminals.......................................... - - - -
------------- ------------- ------------- -------------
Total consol. amortization of excess cost of $ 1,407 $ 1,394 $ 4,233 $ 4,182
investments ============= ============= ============= =============
45
Three Months Ended Nine Months Ended
September 30, September 30,
2005 2004 2005 2004
-------------- -------------- -------------- -------------
Interest income
Products Pipelines................................. $ 1,147 $ 930 $ 3,445 $ 930
Natural Gas Pipelines.............................. 193 - 530 -
CO2................................................ - - - -
Terminals.......................................... - - - -
------------- ------------- ------------- -------------
Total segment interest income...................... 1,340 930 3,975 930
Unallocated interest income........................ 109 236 374 713
------------- ------------- ------------- -------------
Total consolidated interest income................. $ 1,449 $ 1,166 $ 4,349 $ 1,643
============= ============= ============= =============
Other, net - income (expense)
Products Pipelines................................. $ 633 $ 171 $ 998 $ 936
Natural Gas Pipelines.............................. 1,367 29 1,509 1,155
CO2................................................ (6) 10 (6) 42
Terminals.......................................... 886 (61) (293) (306)
------------- ------------- ------------- -------------
Total segment other, net - income (expense)........ 2,880 149 2,208 1,827
Loss from early extinguishment of debt............. - - - (1,424)
------------- ------------- ------------- -------------
Total consolidated Other, net - income (expense)... $ 2,880 $ 149 $ 2,208 $ 403
============= ============= ============= =============
Income tax benefit (expense)
Products Pipelines................................. $ (2,171) $ (2,784) $ (8,209) $ (8,968)
Natural Gas Pipelines.............................. (361) (622) (1,899) (1,395)
CO2................................................ (151) (49) (263) (96)
Terminals.......................................... (2,372) (2,285) (9,874) (5,003)
------------- ------------- ------------- -------------
Total consolidated income tax benefit (expense).... $ (5,055) $ (5,740) $ (20,245) $ (15,462)
============== ============== ============== ==============
Segment earnings
Products Pipelines................................. $ 106,474 $ 101,583 $ 314,436 $ 298,691
Natural Gas Pipelines.............................. 106,680 91,950 314,699 264,587
CO2................................................ 84,746 55,148 244,210 151,717
Terminals.......................................... 66,054 56,561 191,557 164,710
------------- ------------- ------------- -------------
Total segment earnings(b).......................... 363,954 305,242 1,064,902 879,705
Interest and corporate administrative expenses(c).. (118,567) (87,900) (374,068) (275,391)
------------- ------------- ------------- -------------
Total consolidated net income...................... $ 245,387 $ 217,342 $ 690,834 $ 604,314
============= ============= ============= =============
Segment earnings before depreciation, depletion, amortization And amortization
of excess cost of equity investments(d)
Products Pipelines................................. $ 127,155 $ 120,353 $ 376,019 $ 353,903
Natural Gas Pipelines.............................. 121,955 105,211 360,686 303,754
CO2................................................ 119,909 86,118 357,545 239,813
Terminals.......................................... 81,698 67,168 233,529 196,040
------------- ------------- ------------- -------------
Total segment earnings before DD&A................. 450,717 378,850 1,327,779 1,093,510
Total consol. depreciation, depletion and (85,356) (72,214) (258,644) (209,623)
amortization..........................................
Total consol. amortization of excess cost of (1,407) (1,394) (4,233) (4,182)
investments...........................................
Interest and corporate administrative expenses..... (118,567) (87,900) (374,068) (275,391)
------------- ------------- ------------- -------------
Total consolidated net income ..................... $ 245,387 $ 217,342 $ 690,834 $ 604,314
============= ============= ============= =============
Capital expenditures
Products Pipelines................................. $ 82,592 $ 104,154 $ 180,309 $ 171,116
Natural Gas Pipelines.............................. 31,707 23,831 64,854 77,904
CO2................................................ 92,603 65,423 219,545 224,630
Terminals.......................................... 48,675 32,298 132,478 91,581
------------- ------------- ------------- -------------
Total consolidated capital expenditures(e)......... $ 255,577 $ 225,706 $ 597,186 $ 565,231
============= ============= ============= =============
September 30, December 31,
2005 2004
------------- --------------
Assets
Products Pipelines........................... $ 3,826,238 $ 3,651,657
Natural Gas Pipelines........................ 4,162,390 3,691,457
CO2.......................................... 1,796,313 1,527,810
Terminals.................................... 1,999,351 1,576,333
------------- --------------
Total segment assets......................... 11,784,292 10,447,257
Corporate assets(f).......................... 40,357 105,685
------------- --------------
Total consolidated assets.................... $ 11,824,649 $ 10,552,942
============= ==============
46
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than
income taxes.
(b) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses,
depreciation, depletion and amortization, and amortization of excess
cost of equity investments.
(c) Includes unallocated interest income, interest and debt expense, general
and administrative expenses, minority interest expense and loss from
early extinguishment of debt (2004 only).
(d) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses.
(e) Includes sustaining capital expenditures of $42,845 and $36,776 for the
three months ended September 30, 2005 and 2004 respectively, and
includes sustaining capital expenditures of $95,801 and $82,870 for the
nine months ended September 30, 2005 and 2004, respectively. Sustaining
capital expenditures are defined as capital expenditures which do not
increase the capacity of an asset.
(f) Includes cash, cash equivalents, 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 September 30, 2005 and 2004, we
reported (in thousands) total consolidated interest expense of $69,797 and
$47,531, respectively. For the nine months ended September 30, 2005 and 2004, we
reported (in thousands) total consolidated interest expense of $196,736 and
$141,821, respectively.
12. Pensions and Other Post-retirement Benefits
In connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk
Terminals, Inc. in 1998, we acquired certain liabilities for pension and
post-retirement benefits. We provide medical and life insurance benefits to
current employees, their covered dependents and beneficiaries of SFPP and Kinder
Morgan Bulk Terminals. We also provide the same benefits to former salaried
employees of SFPP. Additionally, we will continue to fund these costs for those
employees currently in the plan during their retirement years. SFPP's
post-retirement benefit plan is frozen, and no additional participants may join
the plan.
The noncontributory defined benefit pension plan covering the former
employees of Kinder Morgan Bulk Terminals is the Kinder Morgan, Inc. Retirement
Plan. The benefits under this plan are based primarily upon years of service and
final average pensionable earnings; however, benefit accruals were frozen as of
December 31, 1998.
Net periodic benefit costs for these plans include the following components
(in thousands):
Other Post-retirement Benefits
Three Months Ended September 30, Nine Months Ended September 30,
2005 2004 2005 2004
Net periodic benefit cost
Service cost...................... $ 2 $ 28 $ 6 $ 84
Interest cost..................... 77 97 231 291
Amortization of prior service cost (29) (31) (87) (93)
Actuarial gain.................... (127) (244) (381) (732)
------ ------ ------ ------
Net periodic benefit cost......... $ (77) $ (150) $ (231) $ (450)
====== ====== ====== ======
Our net periodic benefit cost for each of the first three quarters of 2005
was a credit of $77,000, which resulted in increases to income, largely due to
amortizations of an actuarial gain and a negative prior service cost, primarily
related to the following:
- 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
- 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.
47
As of September 30, 2005, we estimate our overall net periodic
post-retirement benefit cost for the year 2005 will be an annual credit of
approximately $0.3 million. This amount could change in the remaining months of
2005 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. As of December 31, 2004, the principal amount
receivable from this note was $96.3 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 December 31, 2004, and we included the
remaining $94.1 million balance within "Notes receivable-Related parties."
In June 2005, Plantation paid to us $1.1 million in principal amount under
the note, and as of September 30, 2005, the principal amount receivable from
this note was $95.2 million. We included $2.2 million of this balance within
"Accounts, notes and interest receivable, net-Related parties" on our
consolidated balance sheet as of September 30, 2005, and we included the
remaining $93.0 million balance within "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. As of both December 31, 2004 and September 30, 2005, we
included the principal amount of $17.1 million related to this note within
"Notes Receivable-Related parties" on our consolidated balance sheets.
Red Cedar Gathering Company
We own a 49% equity interest in the Red Cedar Gathering Company. Red Cedar
is a joint venture, and the Southern Ute Indian Tribe owns the remaining 51%
equity interest. On December 22, 2004, we entered into a $10 million unsecured
revolving credit facility due July 1, 2005, with the Southern Ute Indian Tribe
and us, as lenders, and Red Cedar, as borrower. Subject to the terms of the
agreement, the lenders may severally, but not jointly, make advances to Red
Cedar up to a maximum outstanding principal amount of $10 million. On April 1,
2005, the maximum outstanding principal amount was automatically reduced to $5
million.
In January 2005, Red Cedar borrowed funds of $4 million from its owners
pursuant to this credit agreement, and we loaned Red Cedar approximately $2.0
million, which corresponded to our 49% ownership interest. The interest on all
advances made under this credit facility were calculated as simple interest on
the combined outstanding balance of the credit agreement at 6% per annum based
upon a 360 day year. In March 2005, Red Cedar paid the $4 million outstanding
balance under this revolving credit facility, and the facility expired on July
1, 2005.
48
KM Insurance, Ltd.
KM Insurance, Ltd. ("KMIL"), is a Bermuda insurance company and wholly-owned
subsidiary of KMI. KMIL was formed during the second quarter of 2005 as a Class
2 Bermuda insurance company, the sole business of which is to issue policies for
KMI and us to secure the deductible portion of our workers compensation,
automobile liability, and general liability policies placed in the commercial
insurance market. We accrue for the cost of insurance, which is included in the
related party general and administrative expenses.
14. Regulatory Matters
FERC Order No. 2004
On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards
of Conduct to become effective February 9, 2004. Every interstate natural gas
pipeline was required to file a compliance plan by that date and was required to
be in full compliance with the Standards of Conduct by June 1, 2004. The primary
change from existing regulation is to make such standards applicable to an
interstate natural gas pipeline's interaction with many more affiliates
(referred to as "energy affiliates"), including intrastate/Hinshaw natural gas
pipelines (in general, a Hinshaw pipeline is a pipeline that receives gas at or
within a state boundary, is regulated by an agency of that state, and all the
gas it transports is consumed within that state), processors and gatherers and
any company involved in natural gas or electric markets (including natural gas
marketers) even if they do not ship on the affiliated interstate natural gas
pipeline. Local distribution companies are excluded, however, if they do not
make sales to customers not physically attached to their system. The Standards
of Conduct require, among other things, separate staffing of interstate
pipelines and their energy affiliates (but support functions and senior
management at the central corporate level may be shared) and strict limitations
on communications from an interstate pipeline to an energy affiliate.
Kinder Morgan Interstate Gas Transmission LLC filed for clarification and
rehearing of Order No. 2004 on December 29, 2003. In the request for rehearing,
Kinder Morgan Interstate Gas Transmission LLC asked that intrastate/Hinshaw
pipeline affiliates not be included in the definition of energy affiliates. On
February 19, 2004, Kinder Morgan Interstate Gas Transmission LLC and Trailblazer
Pipeline Company filed exemption requests with the FERC. The pipelines seek a
limited exemption from the requirements of Order No. 2004 for the purpose of
allowing their affiliated Hinshaw and intrastate pipelines, which are subject to
state regulation and do not make any sales to customers not physically attached
to their system, to be excluded from the rule's definition of energy affiliate.
Separation from these entities would be the most burdensome requirement of the
new rules for us.
On April 16, 2004, the FERC issued Order No. 2004-A. The FERC extended the
effective date of the new Standards of Conduct from June 1, 2004, to September
1, 2004. Otherwise, the FERC largely denied rehearing of Order No. 2004, but
provided further clarification or adjustment in several areas. The FERC
continued the exemption for local distribution companies which do not make
off-system sales, but clarified that the local distribution company exemption
still applies if the local distribution company is also a Hinshaw pipeline. The
FERC also clarified that a local distribution company can engage in certain
sales and other energy affiliate activities to the limited extent necessary to
support sales to customers located on its distribution system, and sales
necessary to remain in balance under pipeline tariffs, without becoming an
energy affiliate. The FERC declined to exempt natural gas producers. The FERC
also declined to exempt natural gas intrastate and Hinshaw pipelines, processors
and gatherers, but did clarify that such entities will not be energy affiliates
if they do not participate in gas or electric commodity markets, interstate
capacity markets (as capacity holder, agent or manager), or in financial
transactions related to such markets.
The FERC also clarified further the personnel and functions which can be
shared by interstate natural gas pipelines and their energy affiliates,
including senior officers and risk management personnel, and the permissible
role of holding or parent companies and service companies. The FERC also
clarified that day-to-day operating information can be shared by interconnecting
entities. Finally, the FERC clarified that an interstate natural gas pipeline
and its energy affiliate can discuss potential new interconnects to serve the
energy affiliate, but subject to very onerous posting and record-keeping
requirements.
49
On July 21, 2004, Kinder Morgan Interstate Gas Transmission LLC and
Trailblazer Pipeline Company filed additional joint requests with the interstate
natural gas pipelines owned by KMI asking for limited exemptions from certain
requirements of FERC Order 2004 and asking for an extension of the deadline for
full compliance with Order 2004 until 90 days after the FERC has completed
action on the pipelines' various rehearing and exemption requests. These
exemptions request relief from the independent functioning and information
disclosure requirements of Order 2004. The exemption requests propose to treat
as energy affiliates, within the meaning of Order 2004, two groups of employees:
- individuals in the Choice Gas Commodity Group within KMI's retail
operations; and
- commodity sales and purchase personnel within our Texas intrastate
natural gas operations.
Order 2004 regulations governing relationships between interstate pipelines
and their energy affiliates would apply to relationships with these two groups.
Under these proposals, certain critical operating functions could continue to be
shared.
On August 2, 2004, the FERC issued Order No. 2004-B. In this order, the FERC
extended the effective date of the new Standards of Conduct from September 1,
2004 to September 22, 2004. Also in this order, among other actions, the FERC
denied the request for rehearing made by the interstate pipelines of KMI and us
to clarify the applicability of the local distribution company and parent
company exemptions to them. In addition, the FERC denied the interstate
pipelines' request for a 90 day extension of time to comply with Order 2004.
On September 20, 2004, the FERC issued an order which conditionally granted
the July 21, 2004 joint requests for limited exemptions from the requirements of
the Standards of Conduct described above. In that order, FERC directed Kinder
Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company and the
affiliated interstate pipelines owned by KMI to submit compliance plans
regarding these exemptions within 30 days. These compliance plans were filed on
October 19, 2004, and set out certain steps taken by us to assure that employees
in the Choice Gas Commodity Group of KMI and the commodity sales and purchase
personnel of our Texas intrastate organizations do not have access to restricted
interstate natural gas pipeline information or receive preferential treatment as
to interstate natural gas pipeline services. The FERC will not enforce
compliance with the independent functioning requirement of the Standards of
Conduct as to these employees until 30 days after it acts on these compliance
filings. In all other respects, we were required to comply with the Standards of
Conduct as of September 22, 2004.
We have implemented compliance with the Standards of Conduct as of September
22, 2004, subject to the exemptions described in the prior paragraph. Compliance
includes, among other things, the posting of compliance procedures and
organizational information for each interstate pipeline on its Internet website,
the posting of discount and tariff discretion information and the implementation
of independent functioning for energy affiliates not covered by the prior
paragraph (electric and gas gathering, processing or production affiliates).
On December 21, 2004, the FERC issued Order No. 2004-C. In this order, the
FERC granted rehearing on certain issues and also clarified certain provisions
in the previous FERC 2004 orders. The primary impact on us from Order 2004-C is
the granting of rehearing and allowing local distribution companies to
participate in hedging activity related to on-system sales and still qualify for
exemption from being an energy affiliate.
By an order issued on April 19, 2005, the FERC accepted the compliance plans
filed by us without modification, but subject to further amplification and
clarification as to the intrastate group in three areas:
- further description and explanation of the information or events
relating to intrastate pipeline business that the shared transmission
function personnel may discuss with our commodity sales and purchase
personnel within our Texas intrastate natural gas operations;
- additional posting of organizational information about the commodity
sales and purchase personnel within our Texas intrastate natural gas
operations; and
50
- clarification that the president of our intrastate natural gas pipeline
group has received proper training and will not be a conduit for
improperly sharing transmission or customer information with our
commodity sales and purchase personnel within our Texas intrastate
natural gas operations.
Our interstate pipelines made a compliance filing on May 18, 2005.
FERC Policy statement re: Use of Gas Basis Differentials for Pricing
On July 25, 2003, the FERC issued a Modification to Policy Statement stating
that FERC regulated natural gas pipelines will, on a prospective basis, no
longer be permitted to use gas basis differentials to price negotiated rate
transactions. Effectively, we will no longer be permitted to use commodity price
indices to structure transactions on our FERC regulated natural gas pipelines.
Negotiated rates based on commodity price indices in existing contracts will be
permitted to remain in effect until the end of the contract period for which
such rates were negotiated. Moreover, in subsequent orders in individual
pipeline cases, the FERC has allowed negotiated rate transactions using pricing
indices so long as revenue is capped by the applicable maximum rate(s).
Rehearing on this aspect of the Modification to Policy Statement has been sought
by several pipelines, but the FERC has not yet acted on rehearing. Price indexed
contracts currently constitute an insignificant portion of our contracts on our
FERC regulated natural gas pipelines; consequently, we do not believe that this
Modification to Policy Statement will have a material impact on our operations,
financial results or cash flows.
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. Comments, along with responses to specific questions posed
by FERC concerning the Notice of Proposed Accounting Release, were due January
19, 2005. We filed our comments on January 19, 2005, asking the FERC to modify
the accounting release to allow capitalization of pipeline assessment costs
associated with projects involving 100 feet or more of pipeline being replaced
or recoated (including discontinuous sections) and to adopt an effective date
for the final rule which is no earlier than January 1, 2006.
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 include those to:
- prepare a plan to implement the program;
- identify high consequence areas;
- develop and maintain a record keeping system; and
- inspect affected pipeline segments.
The costs of modifying the pipeline to permit in-line inspections, such as
installing pig launchers and receivers, are to be capitalized, as are certain
costs associated with developing or enhancing computer software or to add or
replace other items of plant.
The Interstate Natural Gas Association of America sought rehearing of the
FERC's June 30, 2005 order. The FERC denied INGAA's request for rehearing on
September 19, 2005. We are currently reviewing the effects of this
51
order on our financial statements; however, we do not believe that this order
will have a material impact on our operations, financial results or cash flows.
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 have filed for rehearing.
Index of Customer Audit
On July 14, 2005, the FERC commenced an audit of TransColorado Gas
Transmission Company, as well as a number of other interstate gas pipelines, to
test compliance with the FERC's requirements related to the filing and posting
of the Index of Customers report. On September 21, 2005, the FERC's staff issued
a draft audit report which cited two minor issues with TransColorado's Index of
Customers filings and postings. Subsequently, on October 11, 2005, the FERC
issued a final order which closed its examination, citing the minor issues
contained in its draft report and approving the corrective actions planned or
already taken by TransColorado. TransColorado has implemented corrective actions
and has applied those actions to its most recent Index of Customer filing, dated
October 1, 2005. No further compliance action is expected and TransColorado
anticipates operating in compliance with applicable FERC rules regarding the
filing and posting of its future Index of Customers reports.
15. Recent Accounting Pronouncements
SFAS No. 123R
In December 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:
- 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;
- when measuring fair value, companies can choose an option-pricing model
that appropriately reflects their specific circumstances and the
economics of their transactions;
- 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
- public companies are allowed to select from three alternative transition
methods - each having different reporting implications.
In April 2005, both the FASB and the Securities and Exchange Commission
decided to delay the effective date for public companies to implement SFAS No.
123R (revised 2004). The new Statement is now effective for public companies for
annual periods beginning after June 15, 2005 (January 1, 2006, for us). We are
currently reviewing the effects of this accounting Statement; however, we have
not granted common unit options since May 2000 and we do not expect the adoption
of this Statement to have any material effect on our consolidated financial
statements.
52
FIN 47
In March 2005, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 47, "Accounting for Conditional Asset Retirement
Obligations--an interpretation of FASB Statement No. 143". This interpretation
clarifies that the term "conditional asset retirement obligation" as used in
SFAS No. 143, "Accounting for Asset Retirement Obligations," refers to a legal
obligation to perform an asset retirement activity in which the timing and (or)
method of settlement are conditional on a future event that may or may not be
within the control of the entity. The obligation to perform the asset retirement
activity is unconditional even though uncertainty exists about the timing and
(or) method of settlement. Thus, the timing and (or) method of settlement may be
conditional on a future event.
Accordingly, an entity is required to recognize a liability for the fair
value of a conditional asset retirement obligation if the fair value of the
liability can be reasonably estimated. The fair value of a liability for the
conditional asset retirement obligation should be recognized when
incurred-generally upon acquisition, construction, or development and (or)
through the normal operation of the asset. Uncertainty about the timing and (or)
method of settlement of a conditional asset retirement obligation should be
factored into the measurement of the liability when sufficient information
exists. FIN 47 also clarifies when an entity would have sufficient information
to reasonably estimate the fair value of an asset retirement obligation.
This Interpretation is effective no later than the end of fiscal years
ending after December 15, 2005 (December 31, 2005, for us). We are currently
reviewing the effects of this Interpretation.
SFAS No. 154
In June 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). Earlier application is permitted for accounting
changes and corrections of errors made occurring in fiscal years beginning after
June 1, 2005. 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
will 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.
53
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). We are currently reviewing the specific
effects of this Issue.
54
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 (i) our accompanying interim consolidated financial statements and related
notes (included elsewhere in this report), and (ii) 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, 2004.
Critical Accounting Policies and Estimates
Certain amounts included in or affecting our consolidated financial
statements and related disclosures must be estimated, requiring us to make
certain assumptions with respect to values or conditions that cannot be known
with certainty at the time the financial statements are prepared. These
estimates and assumptions affect the amounts we report for assets and
liabilities and our disclosure of contingent assets and liabilities at the date
of our financial statements. We evaluate these estimates on an ongoing basis,
utilizing historical experience, consultation with experts and other methods we
consider reasonable in the particular circumstances. Nevertheless, actual
results may differ significantly from our estimates. Any effects on our
business, financial position or results of operations resulting from revisions
to these estimates are recorded in the period in which the facts that give rise
to the revision become known.
In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, the fair
values used to determine possible asset impairment charges, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. Further information about us
and information regarding our accounting policies and estimates that we consider
to be "critical" can be found in our Annual Report on Form 10-K for the year
ended December 31, 2004. There have not been any significant changes in these
policies and estimates during the nine months ended September 30, 2005.
Results of Operations
Consolidated
Three Months Ended Nine Months Ended
September 30, September 30,
------------ ----------
2005 2004 2005 2004
---- ---- ---- ----
(In thousands)
Earnings before depreciation, depletion and amortization expense
and amortization of excess cost of equity investments
Products Pipelines........................................... $ 127,155 $ 120,353 $ 376,019 $ 353,903
Natural Gas Pipelines........................................ 121,955 105,211 360,686 303,754
CO2.......................................................... 119,909 86,118 357,545 239,813
Terminals.................................................... 81,698 67,168 233,529 196,040
----------- ----------- ----------- -----------
Segment earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments(a) 450,717 378,850 1,327,779 1,093,510
Depreciation, depletion and amortization expense................. (85,356) (72,214) (258,644) (209,623)
Amortization of excess cost of equity investments................ (1,407) (1,394) (4,233) (4,182)
Interest and corporate administrative expenses(b)................ (118,567) (87,900) (374,068) (275,391)
----------- ----------- ----------- ------------
Net income....................................................... $ 245,387 $ 217,342 $ 690,834 $ 604,314
=========== =========== =========== ============
- -------
(a) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses.
(b) Includes unallocated interest income, interest and debt expense, general
and administrative expenses, minority interest expense and loss from early
extinguishment of debt (2004 only).
55
Our consolidated net income for the quarterly period ending September 30,
2005 was $245.4 million ($0.57 per diluted unit), compared to $217.3 million
($0.59 per diluted unit) for the quarterly period ending September 30, 2004. Net
income for the nine months ended September 30, 2005 was $690.8 million ($1.61
per diluted unit), compared to $604.3 million ($1.62 per diluted unit) for the
first nine months of 2004. We earned total revenues of $2,631.3 million and
$2,014.7 million, respectively, in the three month periods ended September 30,
2005 and 2004, and revenues of $6,729.5 million and $5,794.1 million,
respectively, in the nine month periods ended September 30, 2005 and 2004.
The increases in our net income in both the third quarter and first nine
months of 2005 compared to the same prior year periods were broad-based,
attributable to higher segment earnings from each of our four reportable
business segments. Specifically, the increases were primarily due to:
- higher earnings from our oil and gas producing activities, resulting
from higher crude oil and natural gas processing plant liquids
production volumes, higher industry price levels for both crude oil and
natural gas processing plant liquids products, and higher third party
carbon dioxide sales and transport volumes;
- improved gross margin performance on our Texas intrastate natural gas
pipelines, higher revenues from both natural gas interstate
transportation and storage services, and higher earnings from our
natural gas gathering equity investees; and
- incremental earnings attributable to internal expansion projects and
strategic acquisitions completed since the end of the third quarter of
2004.
Because our partnership agreement requires us to distribute 100% of our
available cash to our partners on a quarterly basis (available cash consists
primarily of all our cash receipts, less cash disbursements and changes in
reserves), we look at each period's earnings before all non-cash depreciation,
depletion and amortization expenses, including amortization of excess cost of
equity investments, as an important measure of our success in maximizing returns
to our partners. We also use this measure of profit and loss internally for
evaluating segment performance and deciding how to allocate resources to our
business segments. In both the third quarter and first nine months of 2005, all
four of our reportable business segments reported increases in earnings before
depreciation, depletion and amortization compared to the same periods of 2004.
Furthermore, we declared a cash distribution of $0.79 per unit for the third
quarter of 2005 (an annualized rate of $3.16). This distribution is
approximately 8% higher than the $0.73 per unit distribution we made for the
third quarter of 2004. We expect to declare cash distributions of at least $3.13
per unit for 2005; however, no assurance can be given that we will be able to
achieve this level of distribution.
Third Quarter 2005 Hurricanes
On August 29, 2005, Hurricane Katrina struck the United States' Gulf Coast
causing wide-spread damage to residential and commercial real and personal
property. The assets we operate that were impacted by the storm include the
Plantation Pipe Line Company system, and several bulk and liquids terminal
facilities located in the States of Louisiana and Mississippi.
With regard to Plantation, a 3,100-mile refined petroleum products pipeline
which serves the southeastern United States and is owned approximately 51% by
us, the pipeline, equipment and storage tanks suffered no damage but service was
suspended for several days due to local electricity outages. On September 1,
2005, we resumed limited service on the pipeline. On September 2, 2005,
electricity was restored to all of the primary pump stations, and full service
was resumed. With regard to our Terminals segment's Lower Mississippi River
region, most of our owned terminal sites were minimally impacted and suffered no
significant structural damage. However, our Port of New Orleans facility,
located in Harvey, Louisiana, and our International Marine Terminals Partnership
facility, located in Port Sulphur, Louisiana and owned 66 2/3% by us, incurred
greater property damage. Both facilities have resumed limited service and
further damage assessments are necessary and in process. At two third-party
owned facilities which were damaged by Katrina, one located in DeLisle,
Mississippi and the other in Chalmette, Louisiana, we provide contract handling
services and other in-plant operations, and future activity at these two sites
is dependent upon resumption of operations by the owners of the facilities.
56
On September 23, 2005, Hurricane Rita struck the Texas-Louisiana Gulf Coast
causing minimal damage to our assets. However, both our Cypress Pipeline, which
transports natural gas liquids from Mont Belvieu, Texas to Lake Charles,
Louisiana, and our Gulf Coast liquids terminals facilities, which are located
along the Houston Ship Channel and can store up to 18 million barrels of refined
products and petrochemicals, were temporarily shut down, but resumed operations
shortly thereafter. In addition, seven terminal sites included in our Texas
Petcoke terminal region and which primarily handle petroleum coke temporarily
ceased operations as a result of crude oil refineries being shut down prior to
the storm. All of the terminals have either resumed service or will do so in
coordination with the start up of the associated refineries located along the
Texas-Louisiana border. Our Texas intrastate natural gas pipeline group also
operated throughout the storm. During the storm, average daily transport volumes
fell to about 50% of normal levels as a result of decreased demand from Gulf
Coast industrial customers, and access to natural gas storage was impacted due
to loss of electric power. But overall, only minor damage occurred to the
operating facilities, and we expect the utilization of our intrastate system
will continue to increase in conjunction with rising market demand for energy
after the hurricane.
We continue to evaluate the full effect of the storms on our operations and
presently, we expect that the costs incurred as a result of the two hurricanes
will be less than $10 million, including insurance deductibles and lost business
at our terminal sites (but excluding lost revenues from decreased volumes
transported on our pipelines). Essentially all losses related to the storms'
impact were included in our third quarter 2005 results, and we do not believe
that the resolution of any remaining matters will have a material adverse effect
on our business, financial position, results of operations or cash flows.
Products Pipelines
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
2005 2004 2005 2004
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 181,903 $ 160,867 $ 527,818 $ 475,187
Operating expenses(a)...................................... (60,613) (46,489) (169,739) (135,792)
Earnings from equity investments........................... 6,256 7,658 21,706 21,610
Interest income and Other, net-income (expense)............ 1,780 1,101 4,443 1,866
Income taxes............................................... (2,171) (2,784) (8,209) (8,968)
----------- ----------- ----------- -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity 127,155 120,353 376,019 353,903
investments................................................
Depreciation, depletion and amortization expense........... (19,849) (17,951) (59,071) (52,751)
Amortization of excess cost of equity investments.......... (832) (819) (2,512) (2,461)
----------- ----------- ----------- -----------
Segment earnings......................................... $ 106,474 $ 101,583 $ 314,436 $ 298,691
=========== =========== =========== ===========
Gasoline (MMBbl)........................................... 117.5 118.1 344.4 344.7
Diesel fuel (MMBbl)........................................ 41.7 41.6 122.8 120.8
Jet fuel (MMBbl)........................................... 29.3 30.5 88.1 88.4
----------- ----------- ----------- -----------
Total refined product volumes (MMBbl).................... 188.5 190.2 555.3 553.9
Natural gas liquids (MMBbl)................................ 8.4 10.2 26.1 31.1
----------- ----------- ----------- -----------
Total delivery volumes (MMBbl)(b)........................ 196.9 200.4 581.4 585.0
=========== =========== =========== ===========
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and power
expenses and taxes, other than income taxes.
(b) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
Our Products Pipelines segment reported earnings before depreciation,
depletion and amortization of $127.2 million on revenues of $181.9 million in
the third quarter of 2005. This compares to earnings before depreciation,
depletion and amortization of $120.4 million on revenues of $160.9 million in
the third quarter of 2004. For the comparable nine month periods, the segment
reported earnings before depreciation, depletion and amortization of $376.0
million on revenues of $527.8 million in 2005, and earnings before depreciation,
depletion and amortization of $353.9 million on revenues of $475.2 million in
2004.
The segment's overall $6.8 million (6%) increase in earnings before
depreciation, depletion and amortization in the third quarter of 2005 versus the
third quarter of 2004 included a $6.2 million increase in earnings before
57
depreciation, depletion and amortization from our Southeast product terminal
operations, including incremental earnings of $3.4 million from the refined
product terminal operations we acquired in November 2004 from Charter Terminal
Company and Charter-Triad Terminals, LLC. The $2.8 million (78%)
quarter-to-quarter increase in earnings before depreciation, depletion and
amortization from the Southeast terminals owned during both third quarters was
primarily due to higher product throughput revenues.
We also earned quarter-to-quarter increases of $5.5 million (8%) and $1.4
million (13%), respectively, from our Pacific and CALNEV product pipeline
operations. The increase from our Pacific operations was primarily revenue
driven: revenues from refined petroleum product deliveries increased $6.3
million (10%) and terminal service revenues increased $1.5 million (7%). The
increase in revenues from product deliveries was due to both a 2% increase in
delivery volumes and an 8% increase in average tariff rates. The increase in
tariffs was due to a FERC tariff index increase in July 2005 (a purchase price
index adjustment), and an increase in North Line tariff rates associated with
pipeline expansion that was completed since the end of the third quarter of
2004. The higher terminal revenues reflected incremental revenues from diesel
lubricity-improving injection services that we began offering in May 2005.
CALNEV's quarter-to-quarter increase in earnings before depreciation, depletion
and amortization was also due to higher product delivery revenues and higher
product terminal revenues. CALNEV's revenues from refined product deliveries
increased $0.9 million (8%), due primarily to an over 4% increase in
transportation volumes, and revenues from terminal operations increased $0.7
million (27%), as the increase in throughput led to increased terminaling and
ethanol blending services.
The segment's overall increase in earnings before depreciation, depletion
and amortization in the third quarter of 2005 versus the third quarter of 2004
was partially offset by a $5.5 million (129%) decrease from our North System and
a $1.2 million (13%) decrease from our operatorship of the Plantation Pipe Line
Company. The decrease from our North System was primarily due to a $5.0 million
loss recognized in September 2005 to account for differences between physical
and book natural gas liquids inventory. We expect to resolve the inventory
related issues during the fourth quarter of 2005, in which case there may be an
additional charge. The quarter-to-quarter decrease in earnings before
depreciation, depletion and amortization from Plantation was chiefly due to a
$1.5 million (20%) decrease in equity earnings from our approximate 51%
ownership interest. The decrease reflects lower overall net income earned by
Plantation in the third quarter of 2005, due primarily to lower transportation
revenues as a result of an almost 11% decrease in delivery volumes. The decrease
in Plantation's delivery volumes was due to pipeline disruptions caused by power
outages as a result of Hurricane Katrina, and decreased supply from some of the
refineries that transport products on its system, due to damages sustained from
Hurricanes Katrina and Dennis, both occurring in the third quarter of 2005.
The segment's overall $22.1 million (6%) increase in earnings before
depreciation, depletion and amortization in the first nine months of 2005 versus
the first nine months of 2004, included a $16.6 million increase from our
Southeast product terminal operations, which included incremental earnings of
$16.1 million from the combined terminal operations we acquired from Charter in
November 2004 and Exxon Mobil Corporation in March 2004. We also reported an
$11.2 million (6%) increase from our Pacific operations, a $2.0 million (8%)
increase attributable to our ownership interest in Plantation, and a $1.6
million (5%) increase from our CALNEV Pipeline. Partially offsetting the
year-over-year increase in segment earnings before depreciation, depletion and
amortization was a $6.0 million (43%) decrease in earnings from our North System
and a $3.1 million (16%) decrease from our petroleum pipeline transmix
processing operations.
The increases in earnings before depreciation, depletion and amortization
expenses for the comparative nine month periods from our Pacific operations and
our CALNEV Pipeline were mainly related to increases in operating revenues of
$19.1 million (8%) and $3.2 million (8%), respectively. The increases in
revenues were driven by both higher mainline delivery revenues and higher
product terminal revenues. The increase from Plantation was mainly due to the
recognition, in 2005, of incremental interest income of $2.5 million on our
long-term note receivable from Plantation. In July 2004, we loaned $97.2 million
to Plantation to allow it to pay all of its outstanding credit facility and
commercial paper borrowings and in exchange for this funding, we received a
seven year note receivable bearing interest at the rate of 4.72% per annum.
The year-over-year decrease in earnings before depreciation, depletion and
amortization from our North System was primarily due to the $5.0 million
inventory reconciliation reserve taken in the third quarter of 2005, as
discussed above, and to higher natural gas liquids storage expenses related to a
new contract agreement entered into in April
58
2004. The year-to-date decrease in earnings from our transmix operations was due
to both lower revenues and lower other income. The decrease in revenues was due
to a 9% decrease in processing volumes, largely resulting from the disallowance,
beginning in July 2004, of methyl tertiary-butyl ether (MTBE) blended transmix
in the State of Illinois. The decrease in other income was due to a $0.9 million
benefit taken from the reversal of certain short-term liabilities in the second
quarter of 2004.
Revenues for the segment increased $21.0 million (13%) in the third quarter
of 2005 compared to the third quarter of 2004. For the comparative nine month
periods, revenues increased $52.6 million (11%) in 2005 versus 2004. The
quarter-to-quarter increase in segment revenues included incremental revenues of
$9.5 million from our Southeast terminals, including $6.7 million attributable
to the Charter terminals we acquired since the end of the third quarter of 2004.
The remaining $2.8 million increase in revenues from our Southeast terminal
operations was largely attributable to higher product throughput revenues, with
significant contributions coming from our Greensboro, North Carolina and
Newington, Virginia facilities. Other quarter-to-quarter increases in revenues
include the combined $9.4 million (10%) increase from our Pacific operations and
CALNEV Pipeline, as discussed above, and a $1.3 million (14%) increase from our
Central Florida Pipeline, driven by a 14% increase in product delivery volumes
in the third quarter of 2005. For Central Florida, the increase in volumes in
2005 was largely due to hurricane-related pipeline disruptions in the State of
Florida during the third quarter of 2004.
The increase in segment revenues between the comparable nine month periods
included a $29.1 million increase from our Southeast terminals, including $28.4
million of incremental revenues from the terminals acquired since March 2004.
Other year-over-year increases in revenues include a $19.1 million (8%) increase
from our Pacific operations, a $3.2 million (8%) increase from our CALNEV
Pipeline, and a $2.8 million (10%) increase from our Central Florida Pipeline.
The overall increase in segment revenues was partially offset by a $2.0 million
(8%) decrease from our transmix processing operations, as described above.
Pacific's increase in revenues in the first nine months of 2005 relative
to 2004 included increases of $14.9 million (8%) from mainline delivery volumes
and $4.2 million (7%) from incremental terminal revenues. The increase from
refined product deliveries was primarily due to an almost 7% increase in average
tariff rates, and the increase from terminal revenues was due to higher product
storage, injection and blending services. The higher tariff rates included both
the Federal Energy Regulatory Commission approved 2004 annual indexed interstate
tariff increase and a requested rate increase with the California Public Utility
Commission. In November 2004, we filed an application with the CPUC requesting a
$9 million increase in existing intrastate transportation rates to reflect the
in-service date of our $95 million North Line expansion project. Pursuant to
CPUC regulations, this increase automatically became effective as of December
22, 2004, but is being collected subject to refund, pending resolution of
protests to the application by certain shippers. The CPUC may resolve
the matter in the fourth quarter of 2005.
The $3.2 million year-over-year increase in CALNEV's revenues consists of a
$1.5 million (5%) increase from refined product deliveries, and a $1.7 million
(21%) increase from expanded terminaling and ethanol blending operations. The
$2.8 million (10%) increase in Central Florida's revenues in the first nine
months of 2005 versus the same period in 2004, was due to an 11% increase in
transport volumes, which more than offset a slight (1%) drop in the average
tariff per barrel moved.
For the third quarter of 2005, total delivery volumes of refined products
were down 0.9% compared to the third quarter of 2004, with increases on Pacific,
Central Florida and CALNEV offset by a decrease on Plantation. The decrease from
Plantation was primarily due to the pipeline's temporary shutdown caused by
Hurricane Katrina, which contributed to a 10.3% decrease in gasoline delivery
volumes (gasoline deliveries account for approximately 65% of the total fuel
volumes transported by the pipeline). Excluding Plantation, segment deliveries
of gasoline, diesel fuel and jet fuel increased 4.2%, 3.6% and 0.4%,
respectively, in the third quarter of 2005 compared to the third quarter of
2004. Quarter-to-quarter deliveries of natural gas liquids were down 17.6% due
to low demand for propane on the North System, primarily due to a slower grain
drying season in 2005, and to the hurricane-related closure of a petrochemical
plant in Lake Charles, Louisiana that is served by our Cypress Pipeline.
The segment's operating expenses increased $14.1 million (30%) in the third
quarter of 2005, compared to the third quarter of 2004, and increased $33.9
million (25%) in the first nine months of 2005, compared to the first nine
months of 2004. Both periodic increases included the North System's $5.0 million
third quarter 2005 product
59
inventory reconciliation reserve adjustment discussed above.
Other items included in the increase in operating expenses in the third
quarter of 2005 versus the third quarter of 2004 are as follows:
- a $3.3 million increase from the Southeast terminal operations we
acquired in November 2004;
- a $2.6 million (14%) increase from our Pacific operations, due
primarily to higher overall operating, maintenance and labor expenses
associated with increased transportation volumes and terminal
operations;
- a $0.9 million (43%) increase from our Central Florida Pipeline
operations, due primarily to additional expense accruals related to a
pipeline release occurring in September 2005; and
- a $0.8 million (13%) increase from Plantation Pipe Line, due primarily
to higher labor expenses following timing differences that resulted in
an additional pay period in the third quarter of 2005 versus the third
quarter of 2004.
Other items included in the increase in operating expenses in the first nine
months of 2005 versus the first nine months of 2004 are as follows:
- a $12.3 million increase from the Southeast terminal operations we
acquired since March 2004;
- a $9.6 million (15%) increase from our combined Pacific and CALNEV
Pipeline operations, due primarily to higher repair, maintenance and
labor expenses associated with line wash-outs, clean-up work,
inspections, and environmental issues;
- a $1.9 million (19%) increase from our 49.8% proportionate interest in
the Cochin pipeline system, due primarily to higher labor and outside
services associated with additional health, safety and security work;
and
- a $1.3 million (10%) increase from our West Coast terminal operations,
due primarily to higher property tax expenses as a result of expense
reversals taken in the second quarter of 2004 pursuant to favorable
property reassessments.
In the third quarter of 2005, the segment's earnings from equity investments
decreased $1.4 million (18%) from the equity earnings reported in the third
quarter of 2004. The decrease was primarily due to the $1.5 million (20%)
decrease in equity earnings from our 51% ownership interest in Plantation Pipe
Line Company, discussed above. For the comparative nine month periods, the
segment's equity earnings were essentially flat, as higher year-over-year
earnings from our 50% investment in the Heartland Pipeline Company were largely
offset by lower equity earnings from our investment in Plantation.
The segment's income from allocable interest income and other income and
expense items increased $0.7 million (62%) in the third quarter of 2005 versus
the third quarter of 2004. The increase was mainly due to higher property sales
and miscellaneous discounts earned by our West Coast terminal and Pacific
operations. For the comparative nine month periods, income from interest and
other items increased $2.6 million (138%) in 2005 versus 2004. The increase
primarily relates to the incremental interest income of $2.5 million on our
long-term note receivable from Plantation, as discussed above.
The segment's income tax expenses decreased $0.6 million (22%) in the third
quarter of 2005 compared to the third quarter of 2004, primarily due to the
lower net income of Plantation Pipe Line Company. For the comparative nine month
periods, income tax expenses decreased $0.8 million (8%) in 2005, due primarily
to lower pre-tax earnings from the Canadian operations of the Cochin pipeline
system, largely attributable to a decrease in propane demand as a result of
warmer winter weather in 2005 versus 2004.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of equity investments, increased $1.9 million (10%)
in the third quarter of 2005, and $6.4 million (12%) in the first nine
60
months of 2005, when compared to the same periods last year. The increases were
primarily due to incremental depreciation charges associated with our Pacific
operations and to the inclusion of additional depreciation charges on the
Southeast terminal assets that we have owned for the entire nine months of 2005.
The increases from our Pacific operations related to higher depreciable costs as
a result of the capital spending we have made since the end of the third quarter
of 2004.
Natural Gas Pipelines
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
2005 2004 2005 2004
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 2,108,788 $ 1,598,554 $ 5,198,337 $ 4,591,293
Operating expenses(a)...................................... (1,996,737) (1,498,030) (4,863,524) (4,301,857)
Earnings from equity investments........................... 8,705 5,280 25,733 14,558
Interest income and Other, net-income (expense)............ 1,560 29 2,039 1,155
Income taxes............................................... (361) (622) (1,899) (1,395)
------------ ------------ ------------ ------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity 121,955 105,211 360,686 303,754
investments................................................
Depreciation, depletion and amortization expense........... (15,205) (13,191) (45,779) (38,959)
Amortization of excess cost of equity investments.......... (70) (70) (208) (208)
------------ ------------ ------------ ------------
Segment earnings......................................... $ 106,680 $ 91,950 $ 314,699 $ 264,587
============ ============ ============ ============
Natural gas transport volumes (Trillion Btus)(b)........... 359.4 361.4 1,004.5 1,007.1
============ ============ ============ ============
Natural gas sales volumes (Trillion Btus)(c)............... 239.3 260.9 688.6 748.8
============ ============ ============ ============
- ----------
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
(b) Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate
natural gas pipeline group, Trailblazer and TransColorado pipeline volumes.
TransColorado volumes are included for all periods (acquisition date
November 1, 2004).
(c) Represents Texas intrastate natural gas pipeline group.
Our Natural Gas Pipelines business segment reported earnings before
depreciation, depletion and amortization of $122.0 million on revenues of
$2,108.8 million in the third quarter of 2005. This compares to earnings before
depreciation, depletion and amortization of $105.2 million on revenues of
$1,598.6 million in the third quarter of 2004. For the nine month period ended
September 30, 2005, the segment reported earnings before depreciation, depletion
and amortization expenses of $360.7 million on revenues of $5,198.3 million, and
for the first nine months of 2004, earnings before depreciation, depletion and
amortization expenses of $303.8 million on revenues of $4,591.3 million.
The segment's overall $16.8 million (16%) increase in earnings before
depreciation, depletion and amortization expenses in the third quarter of 2005
compared to the third quarter of 2004 included increases of $12.9 million (24%)
from our Texas intrastate natural gas pipeline group, incremental earnings of
$10.5 million from our TransColorado Pipeline, and an increase of $3.4 million
(83%) from our 49% equity interest in the Red Cedar Gathering Company. The
incremental earnings from TransColorado reflect our acquisition of the pipeline
system from KMI effective November 1, 2004. The increase from Red Cedar was due
to higher revenues from sales of excess fuel gas and natural gas gathering, and
is included in the segment's earnings from equity investments, where we include
our proportionate share of Red Cedar's net income pursuant to the equity method
of accounting.
The overall quarter-to-quarter increase in segment earnings before
depreciation, depletion and amortization in the third quarter of 2005 compared
to the third quarter of 2004 was partially offset by a $9.9 million (31%)
decrease in earnings before depreciation, depletion and amortization expenses
from our Kinder Morgan Interstate Gas Transmission system (KMIGT), mainly due to
higher gas purchase costs and lower margins and volumes from operational sales
of natural gas. KMIGT's operational gas sales are the result of both lower fuel
recoveries pursuant to its transportation tariffs and recoveries of storage
cushion gas volumes.
61
For the comparative nine month periods, the $56.9 million (19%) overall
increase in segment earnings before depreciation, depletion and amortization
expenses in 2005 over 2004 included increases of $28.5 million from the
inclusion of TransColorado, $13.2 million (8%) from our Texas intrastate natural
gas pipeline group, $11.4 million (108%) from Red Cedar, and $9.0 million (31%)
from our Trailblazer Pipeline. Red Cedar's year-over-year increase in net income
was largely driven by incremental sales of excess fuel gas, the result of
favorable reductions in the amount of natural gas lost and used within the
system during gathering operations. The increase from our Trailblazer natural
gas pipeline system was mainly due to timing differences on the favorable
settlements of pipeline transportation imbalances in the first quarter of 2005.
For our Texas intrastate natural gas pipeline group, which includes our
Kinder Morgan Tejas, Kinder Morgan Texas, Mier-Monterrey Mexico and Kinder
Morgan North Texas pipelines, the increase in earnings before depreciation,
depletion and amortization expenses for both comparative periods was primarily
due to higher gross margins (revenues less cost of sales). Although total
natural gas sales volumes decreased 8% in both the three and nine month periods
of 2005 compared to 2004, largely due to lower electric generation demand and to
reduced sales to lower margin customers, the group earned higher margins in our
recurring sales business and incremental storage and service revenues. The
intrastate group operated throughout Hurricane Rita and experienced only minor
damage and some temporary service interruptions.
The segment's overall increase in earnings before depreciation, depletion
and amortization in the first nine months of 2005 compared to the first nine
months of 2004 was partially offset by a $4.5 million (37%) decrease in earnings
from our Casper Douglas natural gas gathering system and a $1.2 million (2%)
decrease in earnings from KMIGT. The decrease from Casper Douglas was primarily
due to lower natural gas sales volumes caused by both normal field declines and
higher fuel reimbursement charges that reduced volumes available for sale. The
year-over-year decrease in earnings from KMIGT was due to the third quarter 2005
decrease described above; partially offset by an $8.7 million increase in
earnings before depreciation, depletion and amortization in the first half of
2005 versus the first half of 2004 due to higher operational sales of natural
gas and favorable imbalance valuation adjustments.
Total segment revenues, including revenues from natural gas sales, increased
$510.2 million (32%) and $607.0 million (13%), respectively, in the third
quarter and first nine months of 2005, compared to the same year-earlier
periods. Combined operating expenses, including natural gas purchase costs,
increased $498.7 million (33%) and $561.7 million (13%), respectively, in the
third quarter and first nine months of 2005, when compared to the same periods
last year.
The increases in revenues and operating expenses in both comparative periods
were largely due to higher natural gas sales revenues and higher natural gas
cost of sales, due mainly to higher commodity prices and the sales activities of
our Texas intrastate natural gas pipeline group. For the intrastate group
combined, revenues from the sales of natural gas increased $500.2 million (34%)
in the third quarter of 2005 and $570.3 million (14%) in the first nine months
of 2005, when compared to the same periods of 2004. Similarly, costs of sales,
including natural gas purchase costs, increased $490.8 million (34%) in the
third quarter of 2005 and $563.9 million (14%) in the first nine months of 2005,
versus the same periods in 2004. The inclusion of the TransColorado Pipeline in
our 2005 results accounted for total revenue increases of $12.0 million and
$32.5 million, respectively, and incremental operating expenses of $1.5 million
and $4.1 million, respectively, in the third quarter and first nine months of
2005.
Our Texas intrastate group both purchases and sells significant volumes of
natural gas, which is often stored and/or transported on its pipelines. Our
objective is to match every purchase and sale, thus locking-in an acceptable
margin that is the equivalent of a transportation fee. In addition, we make use
of energy financial instruments, such as over-the-counter forward contracts and
both fixed price and basis swaps to help lock-in favorable margins from our
natural gas purchase and sales activities, thereby generating more stable
earnings during periods of fluctuating natural gas prices.
The purchase and sale activities from our Texas intrastate pipeline group
result in considerably higher revenues and operating expenses compared to the
interstate operations of our Rocky Mountain pipelines, which include our KMIGT,
Trailblazer and TransColorado pipelines. However, due to the fact that we sell
natural gas in the same
62
price environment in which it is purchased, the increases in our gas purchase
costs are largely offset by corresponding increases in our sales revenues. We
realize earnings by capturing the favorable differences between the changes in
our gas sales prices, on the one hand, and the changes in our gas purchase
prices and transportation costs, on the other hand. That is why we believe, with
regard to our results of operations analysis, that earnings before depreciation,
depletion and amortization is a better comparative performance indicator than
revenues and costs of sales because the mix of natural gas volumes between sales
and transportation service often affects revenues but not margin.
Earnings from equity investments increased $3.4 million (65%) and $11.2
million (77%), respectively, in the third quarter and first nine months of 2005,
when compared to the same periods last year. The increases were chiefly due to
higher net income earned by Red Cedar during 2005, as described above. The
segment's interest income and earnings from other income items increased $1.5
million and $0.9 million, respectively, in the third quarter and first nine
months of 2005, compared to the same periods last year. The increases were
mainly due to incremental gains from property disposals recognized in the third
quarter of 2005 by Kinder Morgan Tejas.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased $2.0 million (15%) and
$6.8 million (17%), respectively, in the third quarter and first nine months of
2005, when compared to the same periods last year. The increases were largely
due to the inclusion of depreciation expense on the acquired TransColorado
Pipeline and to higher depreciation expenses on the assets of our Texas
intrastate natural gas pipeline group, due to additional capital investments
made since the end of the third quarter of 2004.
CO2
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- -------------------
2005 2004 2005 2004
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 163,079 $ 121,777 $ 488,271 $ 337,935
Operating expenses(a)...................................... (48,546) (43,331) (152,389) (123,620)
Earnings from equity investments........................... 5,533 7,711 21,932 25,552
Other, net-income (expense)................................ (6) 10 (6) 42
Income taxes............................................... (151) (49) (263) (96)
----------- ----------- ------------ ------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments............................................ 119,909 86,118 357,545 239,813
Depreciation, depletion and amortization expense(b)........ (34,658) (30,465) (111,822) (86,583)
Amortization of excess cost of equity investments.......... (505) (505) (1,513) (1,513)
----------- ----------- ------------ ------------
Segment earnings......................................... $ 84,746 $ 55,148 $ 244,210 $ 151,717
=========== =========== ============ ============
Carbon dioxide volumes transported (Bcf)(c)................ 153.6 149.4 479.0 470.5
=========== =========== ============ ============
SACROC oil production (MBbl/d)(d).......................... 30.8 27.7 32.4 27.1
=========== =========== ============ ============
Yates oil production (MBbl/d)(d)........................... 24.1 20.2 24.0 18.8
=========== =========== ============ ============
Natural gas liquids sales volumes (MBbl/d)(e).............. 9.4 7.7 9.5 7.3
=========== =========== ============ ============
Realized weighted average oil price per Bbl(f)(g).......... $ 26.12 $ 25.21 $ 27.46 $ 25.28
=========== =========== ============ ============
Realized weighted average natural gas liquids price per $ 41.89 $ 33.05 $ 37.09 $ 29.25
=========== =========== ============ ============
Bbl(g)(h)..................................................
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) Includes depreciation, depletion and amortization expense associated with
oil and gas production activities and gas processing activities in the
amount of $30,195 for the third quarter of 2005, $26,901 for the third
quarter of 2004, $98,220 for the first nine months of 2005 and $75,501 for
the first nine months of 2004. Includes depreciation, depletion and
amortization expense associated with sales and transportation services
activities in the amount of $4,463 for the third quarter of 2005, $3,564
for the third quarter of 2004, $13,602 for the first nine months of 2005
and $11,082 for the first nine months of 2004.
(c) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos
pipeline volumes.
(d) Represents 100% of the production from the field. We own an approximate 97%
working interest in the SACROC unit and an approximate 50% working interest
in the Yates unit.
(e) Net to Kinder Morgan.
(f) Includes all Kinder Morgan crude oil production properties.
(g) Hedge gains/losses for oil and natural gas liquids are included with crude
oil.
63
(h) Includes production attributable to leasehold ownership and production
attributable to our ownership in processing plants and third party
processing agreements.
Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates. The segment's primary businesses involve the
production, transportation and marketing of carbon dioxide, commonly called CO2,
and the production and marketing of crude oil and natural gas. Our CO2 business
segment reported earnings before depreciation, depletion and amortization of
$119.9 million on revenues of $163.1 million in the third quarter of 2005. These
amounts compare to earnings before depreciation, depletion and amortization of
$86.1 million on revenues of $121.8 million in the same quarter last year. For
the nine month period ended September 30, 2005, the segment reported earnings
before depreciation, depletion and amortization of $357.5 million on revenues of
$488.3 million, and for the nine months ended September 30, 2004, the segment
reported earnings before depreciation, depletion and amortization of $239.8
million on revenues of $337.9 million.
Both the $33.8 million (39%) increase in earnings before depreciation,
depletion and amortization in the third quarter of 2005 over the third quarter
of 2004 and the $117.7 million (49%) increase in the first nine months of 2005
over the first nine months of 2004 were driven by higher earnings from the
segment's oil and natural gas producing activities, improved performance from
carbon dioxide sales, and incremental contributions from our August 31, 2004
acquisition of the Kinder Morgan Wink Pipeline, a 450-mile crude oil pipeline
system originating in the Permian Basin of West Texas and providing throughput
to a crude oil refinery located in El Paso, Texas.
Our CO2 segment's oil and natural gas producing activities, which include
its natural gas processing activities, reported increases of $20.6 million (38%)
and $84.5 million (57%), respectively, in earnings before depreciation,
depletion and amortization for the three and nine months ended September 30,
2005, when compared to the same periods a year ago. For both periods, the growth
in earnings from our oil and natural gas related activities was attributable to
increased crude oil and natural gas processing plant liquids production and
higher period-to-period average sale prices. We also realized, in the third
quarter of 2005, our first full quarter of benefits from the completion of a
power plant we constructed at the SACROC oil field unit, located in Scurry
County, Texas. Construction began in mid-2004, and the project was completed at
a cost of approximately $76 million. The power plant is being operated by KMI
and will provide the majority of SACROC's future electricity needs.
Combined daily oil production from the two largest oil field units in which
we hold ownership interests increased 15% and 23%, respectively, in the third
quarter and first nine months of 2005, as compared to the same prior-year
periods. The two oil field interests include our approximate 97% working
interest in the SACROC unit and our approximate 50% working interest in the
Yates oil field unit, located south of Midland, Texas. Similarly, natural gas
plant liquids product sales volumes increased 22% and 30%, respectively, in the
third quarter and first nine months of 2005, when compared with the same periods
of 2004. The year-over-year increases in plant product sales volumes were
primarily due to the capital expenditures we have made since the end of the
third quarter of 2004, and reflect the overall continuing strong demand for
domestic energy commodities. For the first nine months of 2005, capital
expenditures for our CO2 business segment totaled $219.5 million.
We also benefited from increases of 4% and 9%, respectively, in our realized
weighted average price of oil per barrel in the third quarter and first nine
months of 2005, versus the same time periods in 2004. Crude oil prices have
followed an upward trend since the end of the third quarter of 2004. Because we
are exposed to market risks related to the price volatility of crude oil,
natural gas liquids and carbon dioxide (to the extent contracts are tied to
crude oil prices), we mitigate our commodity price risk through a long-term
hedging strategy that is intended to generate more stable realized prices. For
more information on our hedging activities, see Note 10 to our consolidated
financial statements, included elsewhere in this report.
Our CO2 segment's carbon dioxide sales and transportation activities
reported increases of $13.2 million (41%) and $33.2 million (36%), respectively,
in earnings before depreciation, depletion and amortization for the three and
nine months ended September 30, 2005, when compared to the same periods a year
ago. The increases were driven by higher revenues from carbon dioxide sales,
incremental earnings from our Kinder Morgan Wink Pipeline, and increases of 3%
and 2%, respectively, in carbon dioxide transportation volumes for the three and
nine month periods of 2005 versus 2004.
64
The year-over-year increases in revenues from sales of carbon dioxide were
due to both higher volumes and higher average prices. The increases in sales
volumes were driven by increased demand for carbon dioxide in the Permian Basin.
We do not recognize profits on carbon dioxide sales to ourselves. The operations
of the acquired Kinder Morgan Wink Pipeline accounted for incremental earnings
before depreciation, depletion and amortization of $4.0 million, revenues of
$4.9 million and operating expenses of $0.9 million, respectively, in the third
quarter of 2005, and incremental earnings before depreciation, depletion and
amortization of $13.7 million, revenues of $17.1 million and operating expenses
of $3.4 million, respectively, in the first nine months of 2005, when compared
to the same time periods of 2004.
Revenues earned by our CO2 segment during the third quarter and first nine
months of 2005 increased $41.3 million (34%) and $150.4 million (45%),
respectively, over comparable periods in the prior year. Both increases were
mainly due to higher crude oil, plant product and carbon dioxide sales revenues,
and higher crude oil transportation revenues, all described above.
The segment's combined operating expenses increased $5.2 million (12%) in
the third quarter of 2005 and $28.8 million (23%) in the first nine months of
2005, versus the same periods of 2004. The increases were primarily the result
of higher property and production taxes, due to the period-to-period increases
in oil production volumes and to an increase in capitalized assets since the end
of the third quarter of 2004. Other factors contributing to the increases in
segment operating expenses included higher fuel and power costs, due to
increased carbon dioxide compression and equipment utilization, and higher
operating and maintenance expenses, due to additional labor and field expenses
related to higher production volumes.
Earnings from equity investments, representing the equity earnings from our
50% ownership interest in the Cortez Pipeline Company, decreased $2.2 million
(28%) in the third quarter of 2005 and $3.6 million (14%) in the first nine
months of 2005, versus the same periods of 2004. The decreases were due to lower
overall net income earned by Cortez, as a result of lower carbon dioxide
transportation revenues due to lower average tariff rates.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased $4.2 million (14%) and
$25.2 million (29%), respectively, in the third quarter and first nine months of
2005, when compared to the same periods last year. The increases were due to
higher depreciable costs, related to incremental capital spending since
September 2004, and higher depletion charges, related to higher period-to-period
crude oil production.
Terminals
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2005 2004 2005 2004
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues................................................... $ 177,484 $ 133,461 $ 515,115 $ 389,682
Operating expenses(a)...................................... (94,318) (63,943) (271,470) (188,336)
Earnings from equity investments........................... 18 (4) 51 3
Other, net-income (expense)................................ 886 (61) (293) (306)
Income taxes............................................... (2,372) (2,285) (9,874) (5,003)
------------ ------------ ------------ ------------
Earnings before depreciation, depletion and amortization
Expense and amortization of excess cost of equity 81,698 67,168 233,529 196,040
investments................................................
Depreciation, depletion and amortization expense........... (15,644) (10,607) (41,972) (31,330)
Amortization of excess cost of equity investments.......... - - - -
----------- ----------- ----------- -----------
Segment earnings......................................... $ 66,054 $ 56,561 $ 191,557 $ 164,710
=========== =========== ============ ============
Bulk transload tonnage (MMtons)(b)......................... 20.5 21.8 63.3 61.6
=========== =========== =========== ===========
Liquids leaseable capacity (MMBbl)......................... 40.3 36.5 40.3 36.5
=========== =========== =========== ===========
Liquids utilization %...................................... 96.5% 95.8% 96.5% 95.8%
=========== =========== =========== ===========
- ----------
(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.
65
Our Terminals segment, which includes the operations of our dry-bulk
material terminals and our petroleum and petrochemical-related liquids terminal
facilities, reported earnings before depreciation, depletion and amortization of
$81.7 million on revenues of $177.5 million in the third quarter of 2005. This
compares to earnings before depreciation, depletion and amortization of $67.2
million on revenues of $133.5 million in the third quarter last year. For the
first nine months of 2005, our Terminals segment reported earnings before
depreciation, depletion and amortization of $233.5 million on revenues of $515.1
million, while in the same period of 2004, the segment reported earnings before
depreciation, depletion and amortization of $196.0 million on revenues of $389.7
million.
Since the end of the third quarter of 2004, we have invested approximately
$273.7 million in cash and $49.6 million in common units to acquire assets and
business operations included as part of our Terminals segment.
Our terminal acquisitions since the end of the third quarter of 2004
primarily included the following:
- the river terminals and rail transloading facilities operated by Kinder
Morgan River Terminals LLC and its consolidated subsidiaries, acquired
effective October 6, 2004;
- our Kinder Morgan Fairless Hills terminal located along the Delaware
River in Bucks County, Pennsylvania, acquired effective December 1, 2004;
- our Texas Petcoke terminals, located in and around the Ports of Houston
and Beaumont, Texas, acquired effective April 29, 2005;
- three terminals acquired separately in July 2005: the Kinder Morgan
Staten Island terminal, a dry-bulk terminal located in Hawesville,
Kentucky and a liquids/dry-bulk facility located in Blytheville,
Arkansas;
- 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;
- our Kinder Morgan Blackhawk terminal located in Black Hawk County, Iowa,
acquired in August 2005; and
- a terminal-related repair shop located in Jefferson County, Texas,
acquired in September 2005.
Terminal operations acquired since the end of the third quarter of 2004
accounted for incremental amounts of earnings before depreciation, depletion and
amortization of $15.7 million, revenues of $37.9 million and operating expenses
of $21.4 million, respectively, in the third quarter of 2005, and incremental
amounts of earnings before depreciation, depletion and amortization of $33.1
million, revenues of $88.6 million and operating expenses of $52.1 million,
respectively, in the first nine months of 2005, when compared to the same
periods a year ago. For all other terminal operations (those owned during both
nine month periods), earnings before depreciation, depletion and amortization
decreased $1.2 million (2%) in the third quarter of 2005 versus the third
quarter of 2004, and increased $4.4 million (2%) in the first nine months of
2005 versus the first nine months of 2004.
The 2005 decrease in third quarter earnings before depreciation, depletion
and amortization from terminals owned during both years was primarily due to the
effects of two Gulf Coast hurricanes in the third quarter of 2005, as described
above in our discussion under "--Third Quarter 2005 Hurricanes." Specifically,
our International Marine Terminals facility, a Louisiana partnership owned 66
2/3% by us, suffered property damage and a general loss of business due to the
effects of Hurricane Katrina. Earnings before depreciation, depletion and
amortization from our IMT facility decreased $4.1 million, revenues decreased
$3.1 million and operating expenses increased $0.9 million in the third quarter
of 2005 versus the third quarter of 2004. IMT is a multi-purpose bulk commodity
transfer terminal facility located in Port Sulphur, Louisiana. It utilizes both
land and a dock facility to generate revenues from annual throughput contracts
under which the partnership agrees to transfer certain minimum quantities of
bulk commodities. For the comparative nine months, IMT's earnings before
depreciation, depletion and amortization decreased $5.6 million, revenues
decreased $2.5 million and operating expenses increased $3.1 million. The
year-over-year decrease in earnings reflects the impact of Hurricane Katrina in
the third quarter of
66
2005, as well as higher labor, equipment rental and fuel expenses in the first
half of 2005 versus the first half of 2004.
In addition, due to the impact of the two third quarter hurricanes and their
effect on Gulf Coast crude oil refineries, most of the terminal operations in
our Texas Petcoke region temporarily ceased operations, our two large Gulf Coast
liquids terminal facilities located on the Houston Ship Channel in Pasadena and
Galena Park, Texas, were out of service for four days, and four separate
facilities in Louisiana and Mississippi were shutdown for various lengths of
time due to property damage from the storms. In total, our Terminals segment
recognized $2.6 million in expense in the third quarter of 2005 to meet its
insurance deductible for Hurricane Katrina and another $0.8 million to repair
damaged facilities following Hurricane Rita. For the comparative quarterly
period, total bulk tonnage volume was down 6% in the third quarter of 2005 when
compared to the third quarter of 2004, primarily due to the hurricanes.
Despite the temporary shutdowns, earnings before depreciation, depletion and
amortization from our two large Gulf Coast liquids terminal facilities increased
$4.3 million (27%) and $9.2 million (20%), respectively, in the third quarter
and first nine months of 2005, when compared to the same periods last year. The
two terminals serve as a distribution hub for Houston's crude oil refineries,
and the period-to-period increases in the terminals' earnings before
depreciation, depletion and amortization expenses were primarily driven by
higher revenues at our Pasadena terminal, due to higher sales of petroleum
transmix, new customer agreements and certain contract price escalations.
Despite a decrease in total liquids transfer volumes in the third quarter of
2005, due in large part to the short-term shutdowns related to Hurricane Rita,
for the two terminals combined, total throughput volumes increased 2% in the
first nine months of 2005 versus the same year-earlier period.
For our entire liquids terminals combined, total throughput volumes
increased 1% in both the third quarter and first nine months of 2005, versus the
same periods in 2004. The increases were due to higher distillate, vegetable
oil, and oil field liquids volumes. Through a combination of business
acquisitions and internal capital spending, we have increased our liquids
leaseable capacity by 3.8 million barrels (10%) since the end of the third
quarter of 2004, while at the same time, increasing our liquids utilization rate
(the ratio of our actual output to our estimated potential output) by 1%.
Other contributions to the growth in earnings before depreciation, depletion
and amortization for the comparative three and nine month periods from terminals
owned during both years include increases of $1.6 million (37%) and $1.2 million
(8%), respectively, from our Southeast region, and increases of $0.7 million
(6%) and $2.7 million (8%), respectively, from our Midwest region. For our
Southeast region, the increases were largely due to improved performance at our
terminal operations located in and around the Tampa, Florida area. These
operations include the import and export business of our Kinder Morgan Tampaplex
terminal, the commodity transfer operations of our Port Sutton terminal, and the
terminal stevedoring services we perform along Tampa Bay. For our Midwest
terminal region, the increases included higher earnings from our Dakota bulk
terminal, located along the Mississippi River near St. Paul, Minnesota, and from
our Milwaukee, Wisconsin bulk commodity terminal. The period-to-period increases
in earnings from Dakota were primarily due to higher revenues generated by a
cement unloading and storage facility, which was designed and built by our River
Consulting engineering operations and which began operations in late 2004. The
increases from our Milwaukee bulk terminal were mainly due to an increase in
coal handling revenues related to higher coal truckage within the State of
Wisconsin.
Segment revenues for all terminals owned during both nine month periods
increased $6.1 million (5%) and $36.8 million (9%), respectively, in the third
quarter and first nine months of 2005, when compared to the same prior-year
periods. The quarter-to-quarter increase was primarily due to a $5.1 million
(23%) increase in revenues from our Pasadena and Galena Park Gulf Coast liquids
terminals, as described above. The year-over-year increase of $36.8 million was
mainly due to the following:
- an $11.6 million (18%) increase from our Pasadena and Galena Park Gulf
Coast facilities, due primarily to higher petroleum transmix sales and
additional customer contracts;
- an $8.5 million (13%) increase from our Midwest region, due primarily
to higher cement handling revenues at our Dakota terminal, increased
tonnage at our Milwaukee terminal, and higher oil sales at our
Dravosburg, Pennsylvania terminal;
67
- an $8.5 million (20%) increase from our Mid-Atlantic region, due
primarily to higher coal volumes and higher dockage revenues at our
Shipyard River terminal, located in Charleston, South Carolina, and to
higher synfuel, cement handling and dockage revenues at our Pier IX
bulk terminal, located in Newport News, Virginia; and
- a $3.5 million (10%) increase from our Southeast region, due primarily
to increased tonnage, storage and stevedoring services performed at
terminal sites located in Tampa Bay and Port Sutton, Florida.
Operating expenses for all terminals owned during both nine month periods
increased $9.0 million (14%) and $31.0 million (16%), respectively, in the third
quarter and first nine months of 2005, when compared to the same periods a year
earlier. The overall quarter-to-quarter increase in segment operating expenses
includes increases of $3.3 million (30%) from our Midwest terminals, $1.6
million (11%) from our Lower Mississippi River (Louisiana) terminals, and $0.8
million (14%) from our Gulf Coast terminals. For the comparative nine month
periods, the overall increase in operating expenses includes increases of $9.3
million (50%) from our Mid-Atlantic terminals, $6.6 million (20%) from our
Midwest terminals, and $5.1 million (12%) from our Louisiana terminals.
The increases in expenses for the terminals included in our Louisiana region
were largely due to additional insurance and property damage expenses related to
the two Gulf Coast hurricanes in the third quarter of 2005. The increases in
operating expenses from our Midwest terminals included higher expenses at our
Milwaukee terminal, due to increased wharfage, trucking and maintenance expenses
associated with the increase in coal volumes; higher expenses at our Dakota
terminal, due to repairs and higher labor expenses associated with the higher
cement volumes; and higher cost of sales expense at our Dravosburg terminal, due
to oil purchasing costs and inventory maintenance. The increases at our Gulf
Coast terminals were mainly due to higher period-to-period labor expenses, dock
expenses and dredging work. The Mid-Atlantic increases were largely due to
higher operating, maintenance and labor expenses at our Shipyard River and Pier
IX terminals, due to higher bulk tonnage volumes, and to higher labor and
equipment maintenance expenses at our Chesapeake Bay, Maryland bulk terminal,
due to higher movements of petroleum coke.
The segment's other income items increased $0.9 million in the third quarter
of 2005 versus the third quarter of 2004, but were flat across both nine month
periods. The increase in the comparative quarterly period was due to a gain on
sale of terminal property located at our liquids terminal facility in Argo,
Illinois.
The segment's income tax expenses were essentially flat across both third
quarter periods, but increased $4.9 million (97%) in the first nine months of
2005, compared to the first nine months of 2004. The increase was mainly due to
an incremental $3.5 million of income tax expense related to the taxable income
of Kinder Morgan River Terminals LLC and its consolidated subsidiaries, which we
acquired effective October 6, 2004. The remaining $1.4 million increase was
attributable to higher taxable income from Kinder Morgan Bulk Terminals, Inc.
and its consolidated subsidiaries.
Compared to the same periods in 2004, non-cash depreciation, depletion and
amortization charges increased $5.0 million (47%) in the third quarter of 2005
and $10.6 million (34%) in the first nine months of 2005. In addition to
increases associated with normal capital spending, the overall increases reflect
higher depreciation charges due to the terminal acquisitions we have made since
the third quarter of 2004. Collectively, the terminal assets that we have
acquired since the end of the third quarter of 2004 accounted for incremental
depreciation expenses of $4.4 million and $8.8 million in the three and nine
month periods ended September 30, 2005, respectively.
68
Other
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
2005 2004 2005 2004
---- ---- ---- ----
(In thousands-income/(expense))
General and administrative expenses........................ $ (47,073) $ (37,816) $ (171,058) $ (125,527)
Unallocable interest, net.................................. (69,688) (47,295) (196,362) (141,108)
Minority interest.......................................... (1,806) (2,789) (6,648) (7,332)
Loss from early extinguishment of debt..................... - - - (1,424)
----------- ----------- ----------- ------------
Interest and corporate administrative expenses........... $ (118,567) $ (87,900) $ (374,068) $ (275,391)
============= ============ ============ ============
Items not attributable to any segment include general and administrative
expenses, unallocable interest income, interest expense and minority interest.
We also included the $1.4 million loss from our early extinguishment of debt in
May 2004 as an item not attributable to any business segment. The loss
represented the excess of the price we paid to repurchase and retire the
principal amount of $84.3 million of tax-exempt industrial revenue bonds over
the bonds' carrying value and unamortized debt issuance costs. Pursuant to
certain provisions that gave us the right to call and retire the bonds prior to
maturity, we took advantage of the opportunity to refinance at lower rates, and
we included the $1.4 million loss under the caption "Other, net" in our
accompanying consolidated statements of income.
Our general and administrative expenses, which include such items as
salaries and employee-related expenses, payroll taxes, legal fees, unallocated
litigation and environmental accruals, insurance, and office supplies and
rentals, increased $9.3 million (24%) and $45.5 million (36%), respectively, in
the third quarter and first nine months of 2005 compared to the same periods in
2004. The increase in the third quarter of 2005 versus the third quarter of 2004
was primarily due to higher period-to-period employee costs, associated with
acquisitions; higher expenses incurred from KMI's operation and maintenance of
our natural gas pipeline assets, associated with higher actual costs in 2005
versus lower negotiated settlement costs in 2004; and higher legal, corporate
secretary and other shared services.
For the comparative nine month periods, higher general and administrative
expenses in 2005 versus 2004 were largely due to incremental litigation and
environmental settlement expenses of $33.4 million. The additional charges
recognized in 2005 consisted of a $25 million expense for a settlement reached
in the first quarter between us and a shipper on our Kinder Morgan Tejas natural
gas pipeline system, and a cumulative $8.4 million expense related to
settlements of environmental matters at certain of our operating sites located
in the State of California. The remaining increase in year-over-year general and
administrative expenses reflects the same items discussed above for the
comparative third quarter periods. For more information on our litigation
matters, see Note 3 to our consolidated financial statements, included elsewhere
in this report.
Unallocable interest expense, net of interest income, increased $22.4
million (47%) and $55.3 million (39%), respectively, in the third quarter and
first nine months of 2005, compared to the same year-earlier periods. The
increases were due to both higher average debt levels and higher effective
interest rates. The period-to-period increases in average borrowings were
largely due to a net increase of $800 million in principal amount of long-term
senior notes since September 30, 2004. We closed public offerings of $500
million in principal amount of senior notes in both November 2004 and March
2005, and we retired a principal amount of $200 million in March 2005. We issued
our senior notes pursuant to our available shelf registration statements,
principally to refinance commercial paper borrowings used for both internal
capital spending and acquisition expenditures made since the end of the third
quarter of 2004.
The period-to-period increases in our average borrowing rates reflect a
general rise in interest rates since the end of the third quarter of 2004. The
weighted average interest rate on all of our borrowings increased 10% in both
the third quarter and first nine months of 2005 compared to the same periods
last year. 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.
69
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, decreased $1.0 million (35%) and $0.7 million (9%), respectively, in the
third quarter and first nine months of 2005, compared to the same periods a year
ago. The decreases were primarily due to lower third quarter income allocated to
the 33 1/3% minority interest in the IMT Partnership in 2005, due to business
interruption caused by Hurricane Katrina.
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. The following
table illustrates the sources of our invested capital (dollars in thousands). In
addition to our results of operations, these balances are affected by our
financing activities as discussed below:
September 30, December 31,
------------ ------------
2005 2004
------------ ------------
Long-term debt, excluding market value of interest rate swaps.. $5,187,273 $4,722,410
Minority interest.............................................. 40,597 45,646
Partners' capital, excluding accumulated other comprehensive 4,691,963 4,353,863
------------ ------------
loss...........................................................
Total capitalization......................................... 9,919,833 9,121,919
Short-term debt, less cash and cash equivalents................ - -
------------ ------------
Total invested capital....................................... $ 9,919,833 $ 9,121,919
============ ============
Capitalization:
Long-term debt, excluding market value of interest rate swaps 52.3% 51.8%
Minority interest............................................ 0.4% 0.5%
Partners' capital, excluding accumulated other comprehensive 47.3% 47.7%
------------ ------------
loss...........................................................
100.0% 100.0%
============ ============
Invested Capital:
Total debt, less cash and cash equivalents and excluding
market value of interest rate swaps..................... 52.3% 51.8%
Partners' capital and minority interest, excluding accumulated
other comprehensive loss ............................... 47.7% 48.2%
------------ ------------
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 facility, issuing short-term commercial paper, long-term notes or
additional common units or issuing additional i-units to KMR.
In general, we expect to fund:
- cash distributions and sustaining capital expenditures with existing
cash and cash flows from operating activities;
- expansion capital expenditures and working capital deficits with
retained cash (resulting from including i-units in the determination of
cash distributions per unit but paying quarterly distributions on
i-units in additional i-units rather than cash), additional borrowings,
the issuance of additional common units or the issuance of additional
i-units to KMR;
- interest payments with cash flows from operating activities; and
- debt principal payments with additional borrowings, as such debt
principal payments become due, or by the issuance of additional common
units or the issuance of additional i-units to KMR.
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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.
Short-term Liquidity
Our principal sources of short-term liquidity are our $1.6 billion
revolving bank credit facility, our $1.6 billion short-term commercial paper
program (which is supported by our revolving bank credit facility, with the
amount available for borrowing under our credit facility being reduced by our
outstanding commercial paper borrowings) and cash provided by operations. In
August 2005, we replaced our previous five-year credit facility with a five-year
senior unsecured revolving credit facility that has a borrowing capacity of $1.6
billion, and we increased our commercial paper program by $350 million to
provide for the issuance of up to $1.6 billion.
Our current five-year credit facility is due August 18, 2010, and can be
used for general corporate purposes and as a backup for our commercial paper
program. There were no borrowings under our credit facility as of September 30,
2005. After inclusion of our outstanding commercial paper borrowings and letters
of credit, the remaining available borrowing capacity under our credit facility
was $394.2 million as of September 30, 2005.
On August 1, 2005, KMI announced that it had entered into a definitive
agreement to acquire all of the outstanding shares of Terasen Inc., a provider
of energy and utility services based in Vancouver, British Columbia, Canada, for
an aggregate consideration of approximately US$5.6 billion, consisting of cash,
stock of KMI and the assumption of debt. For more information on this
transaction, see Note 1 to our consolidated financial statements, included
elsewhere in this report. On August 2, 2005, following KMI's announcement of the
proposed acquisition, Standard & Poor's Rating Services placed our debt credit
ratings, as well as KMI's ratings, on CreditWatch with negative implications. As
of October 26, 2005, there was no change in our S&P credit rating.
In addition, some of our customers are experiencing, or may experience in
the future, severe financial problems that have had a significant impact on
their creditworthiness. We are working to implement, to the extent allowable
under applicable contracts, tariffs and regulations, prepayments and other
security requirements, such as letters of credit, to enhance our credit position
relating to amounts owed from these customers. We cannot provide assurance that
one or more of our financially distressed customers will not default on their
obligations to us or that such a default or defaults will not have a material
adverse effect on our business, financial position, future results of operations
or future cash flows.
Operating Activities
Net cash provided by operating activities was $901.6 million for the nine
months ended September 30, 2005, versus $837.9 million in the comparable period
of 2004. The period-to-period increase of $63.7 million (8%) in cash flow from
operations consisted of:
- a $140.6 million increase in cash from overall higher partnership income,
net of non-cash items including depreciation charges and undistributed
earnings from equity investments;
- a $2.1 million increase related to higher distributions received from
equity investments;
- a $53.0 million decrease in cash inflows relative to net changes in
working capital items; and
- a $26.0 million decrease in cash inflows relative to net changes in
non-current assets and liabilities.
The higher partnership income reflects the increase in cash earnings across
all four of our reportable business segments in the first nine months of 2005,
as discussed above in "-Results of Operations." The increase in cash inflows
from our equity investees was primarily due to higher distributions received
from Plantation Pipe Line and Red Cedar in the first nine months of 2005,
reflecting higher year-over-year earnings for both investees. The overall
71
increase in distributions was partially offset by lower distributions from
Cortez Pipeline, due to lower overall partnership net income in 2005 versus
2004.
The decrease in operating cash flows from working capital items was mainly
due to net changes in accounts payables and receivables; in 2005, timing
differences resulted in higher receivables, which more than offset an increase
in payables relative to the first nine months of 2004. The decrease in cash
inflows relative to net changes in non-current assets and liabilities related
to, among other things, higher payments made in the first nine months of 2005 to
reduce long-term liabilities and reserves for items such as: natural gas
imbalances, reserves for natural gas and natural gas liquids storage, and
pipeline rate case liabilities.
Investing Activities
Net cash used in investing activities was $905.6 million for the nine month
period ended September 30, 2005, compared to $713.2 million in the comparable
2004 period. The $192.4 million (27%) increase in cash used in investing
activities was primarily attributable to:
- a $147.2 million increase due to higher expenditures made for strategic
business acquisitions;
- a $32 million increase in capital expenditures; and
- a $20.4 million increase related to additional investments in
underground natural gas storage volumes.
For the nine months ended September 30, 2005, our acquisition outlays
totaled $289.7 million, including cash outflows of $188.6 million for the
acquisition of bulk terminal assets from Trans-Global Solutions, Inc., $50.9
million for our North Dayton, Texas natural gas storage facility, and $23.9
million for our acquisition of the Kinder Morgan Staten Island terminal. For the
nine months ended September 30, 2004, our acquisition outlays totaled $142.5
million, including cash outflows of $90.8 million for the acquisition of Kinder
Morgan Wink Pipeline, L.P., formerly Kaston Pipeline Company, L.P., and $48.1
million for the acquisition of seven refined petroleum products terminals from
Exxon Mobil Corporation.
Including expansion and maintenance projects, our capital expenditures were
$597.2 million in the first nine months of 2005, compared to $565.2 million in
the same prior-year period. We continue to expand and grow our existing asset
infrastructure and have current projects in place that will further increase
production and throughput across our business portfolio.
Our sustaining capital expenditures were $95.8 million for the first nine
months of 2005 compared to $82.9 million for the first nine months of 2004. As
of September 30, 2005, our forecasted expenditures for the remaining three
months of 2005 for sustaining capital expenditures were approximately $48.3
million, based on our 2005 sustaining capital expenditure forecast. This amount
has been committed primarily for the purchase of plant and equipment. Sustaining
capital expenditures are defined as capital expenditures which do not increase
the capacity of an asset. All of our capital expenditures, with the exception of
sustaining capital expenditures, are discretionary.
In the third and fourth quarters of 2005, we made the following
announcements related to our investing activities:
- On August 4, 2005, we announced plans for a second expansion to our
Pacific operations' East Line Pipeline. In addition to our approximate
$210 million East Line expansion initially proposed in October 2002, this
second expansion consists of replacing approximately 140 miles of 12-inch
diameter pipe between El Paso, Texas and Tucson, Arizona with 16-inch
diameter pipe. The project also includes the construction of two
additional pump stations on the East Line. The project is expected to
cost approximately $130 million. We began the permitting process for this
project in September 2005, we expect construction to begin in January
2007, and we expect to complete the expansion project in the summer of
2007;
- On August 15, 2005, we announced plans to expand our Texas intrastate
natural gas pipeline system into the Permian Basin by converting an
approximate 254-mile segment of a previously acquired 24-inch diameter
Texas crude oil pipeline from carrying crude oil to natural gas. The
project was completed at a cost of approximately $46 million and service
was commenced in early October 2005. The expansion accesses a
72
number of natural gas processing plants in West Texas and provides
transportation service from McCamey, Texas to just west of Austin, Texas.
The expansion complements our 2004 conversion of a 135-mile segment of the
same pipeline between Katy and Austin, Texas, that began natural gas
service in July 2004. Approximately 95% of the 150 million cubic feet per
day of new natural gas capacity being created by this conversion project is
already supported by customer contracts and the project is being phased in
through the first quarter of 2006;
- On August 17, 2005, we announced that we had entered into a Memorandum of
Understanding with Sempra Pipelines & Storage, a unit of Sempra Energy, to
pursue development of a proposed new natural gas pipeline that would link
producing areas in the Rocky Mountain region to the upper Midwest and
Eastern United States. The proposed 1,500-mile, 42-inch diameter Rockies
Express Pipeline would have a capacity of up to two billion cubic feet per
day of natural gas and would cost an estimated $3 billion to complete. The
pipeline will originate at the Cheyenne Market Hub in northeastern Colorado
and extend to eastern Ohio with an ultimate route to be selected based on
shipper interest. Under the memorandum of understanding with Sempra, we
will share responsibility for development activities with Sempra, but
initially, we would own 66 2/3% of the equity in the proposed pipeline and
Sempra would own the remaining 33 1/3% interest. Pending customer
commitments and regulatory approval, the proposed pipeline is projected to
be staged into service beginning in late 2007, and the eastern portion of
the project, providing direct access to markets in the Northeast United
States, is anticipated to be in service in late 2008 or early 2009.
- On September 22, 2005, we announced the start of a binding open season for
our proposed Kinder Morgan Louisiana Pipeline. The pipeline would provide
take-away natural gas capacity from the Cheniere Sabine Pass liquefied
natural gas (LNG) plant now under construction in Cameron Parish,
Louisiana. We plan to invest approximately $490 million to build this new
interstate natural gas pipeline that will originate at the Sabine Pass LNG
terminal and extend into Evangeline Parish, Louisiana. The Kinder Morgan
Louisiana Pipeline will consist of two segments: (i) a 137-mile large
diameter pipeline with firm capacity of about 2.1 million dekatherms per
day of natural gas that will connect to various interstate and intrastate
pipelines within Louisiana, and (ii) a 1-mile pipeline with firm capacity
of about 1.3 million dekatherms per day that will connect to KMI's Natural
Gas Pipeline Company of America's natural gas pipeline. Prior to the open
season, we had already obtained prearranged conditional agreements from
multiple shippers for the combined 3.4 million dekatherms per day of
initial project capacity. Pending various shipper and regulatory approvals,
the pipeline could be in service as early as the first quarter of 2009; and
- On October 5, 2005, and on October 18, 2005, we and Sempra announced that
we had entered into separate memoranda of understandings with the Wyoming
Natural Gas Pipeline Authority and with subsidiaries of EnCana Corporation,
respectively, with regard to our proposed development of the Rockies
Express Pipeline, announced on August 17, 2005 (discussed above). The WNGPA
is an instrumentality of the State of Wyoming that was formed by the state
legislature in order to facilitate production and transportation of Wyoming
natural gas. Pursuant to the memorandum of understanding with the WNGPA,
the WNGPA will contract for up to 200 million cubic feet per day of firm
capacity natural gas on the proposed pipeline, explore the use of its $1
billion in bonding authority to provide debt financing for the project, and
provide support for the extension of the project to the Opal Hub in
southwestern Wyoming. Pursuant to the memorandum of understanding with
EnCana, EnCana Gas Marketing has agreed to negotiate with the project for
firm transportation capacity during an upcoming open season. Combined with
previous agreements with the WNGPA and a Sempra affiliate, we now have
conditional commitments that account for approximately 50% of the
pipeline's two billion cubic feet per day capacity. Also, under the terms
of the EnCana memorandum of understanding and subject to final
negotiations, it is contemplated that EnCana will sell its Entrega Gas
Pipeline to the Rockies Express project. EnCana recently began constructing
the Entrega Pipeline, a 330-mile, 36 to 42-inch diameter interstate natural
gas pipeline that will link growing Rocky Mountain gas production areas to
the Cheyenne Hub. Under a previous agreement, we had contracted with EnCana
to operate the Entrega system, and we will now also market the available
capacity on the system.
Financing Activities
Net cash provided by financing activities amounted to $4.2 million for the
nine months ended September 30, 2005. For the same nine months of 2004, we used
$141.6 million in financing activities. The $145.8 million overall
73
increase in cash inflows provided by financing activities was primarily due to:
- a $218 million increase from overall debt financing activities;
- a $32.4 million increase from overall equity issuances; and
- a $115.1 million decrease from higher partnership distributions.
Our changes in cash from debt financing activities include both issuances
and payments of debt, and debt issuance costs. The period-to-period increase in
cash inflows from our overall debt financing activities was primarily due to the
following:
- a $498.7 million increase from the issuance of senior notes. On March 15,
2005, we closed a public offering of $500 million in principal amount of
5.80% senior notes due March 15, 2035. We used the proceeds from this
issuance to reduce the borrowings under our commercial paper program;
- a $97.2 million increase from our July 2004 loan to Plantation Pipe Line
Company, which corresponded to our 51.17% ownership interest, to allow
Plantation to pay all of its outstanding credit facility and commercial
paper borrowings. In exchange, we received a seven year note receivable
bearing interest at the rate of 4.72% per annum;
- an $84.3 million increase from the May 2004 redemption and retirement of
the principal amount of four series of tax-exempt bonds related to
certain liquids terminal facilities. Pursuant to certain provisions that
gave us the right to call and retire the bonds prior to maturity, we took
advantage of the opportunity to refinance at lower rates;
- a $200 million decrease from the retirement of senior notes. On March 15,
2005, we paid a maturing amount of $200 million in principal amount of
8.0% senior notes due on that date; and
- a $264.8 million decrease due to lower net commercial paper borrowings in
the first nine months of 2005 versus the first nine months of 2004.
The $32.4 million increase in cash inflows from partnership equity issuances
was primarily related to the incremental cash we received for our third quarter
2005 issuance of common units compared to our first quarter 2004 issuances of
common and i-units. In the third quarter of 2005, we issued, in a public
offering, 5,750,000 of our common units at a price of $51.25 per unit. After
commissions and underwriting expenses, we received net proceeds of $283.6
million for the issuance of these units. Similarly, in a February 2004 public
offering, we issued an additional 5,300,000 of our common units at a price of
$46.80 per unit, less commissions and underwriting expenses, and in March 2004,
we issued an additional 360,664 of our i-units to KMR at a price of $41.59 per
share, less closing fees and commissions. After all fees, we received net
proceeds of $252.7 million for the issuance of these common and i-units. We used
the proceeds from each of these three issuances to reduce the borrowings under
our commercial paper program.
Distributions to all partners, consisting of our common and Class B
unitholders, our general partner and minority interests, totaled $696.5 million
in the first nine months of 2005 compared to $581.4 million in the same
year-earlier period. The increase in distributions was due to an increase in the
per unit cash distributions paid, an increase in the number of units outstanding
and an increase in our general partner incentive distributions. 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
74
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.
Available cash is initially distributed 98% to our limited partners and 2%
to our general partner. These distribution percentages are modified to provide
for incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
- first, 98% to the owners of all classes of units pro rata and 2% to our
general partner until the owners of all classes of units have received a
total of $0.15125 per unit in cash or equivalent i-units for such
quarter;
- second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the owners
of all classes of units have received a total of $0.17875 per unit in
cash or equivalent i-units for such quarter;
- third, 75% of any available cash then remaining to the owners of all
classes of units pro rata and 25% to our general partner until the owners
of all classes of units have received a total of $0.23375 per unit in
cash or equivalent i-units for such quarter; and
- fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units in
cash and to owners of i-units in the equivalent number of i-units, and
50% to our general partner.
Incentive distributions are generally defined as all cash distributions paid
to our general partner that are in excess of 2% of the aggregate value of cash
and i-units being distributed. Our general partner's incentive distribution for
the distribution that we declared for the third quarter of 2005 was $121.5
million. Our general partner's incentive distribution for the distribution that
we declared for the third quarter of 2004 was $99.1 million. Our general
partner's incentive distribution that we paid during the third quarter of 2005
to our general partner (for the second quarter of 2005) was $115.7 million. Our
general partner's incentive distribution that we paid during the third quarter
of 2004 to our general partner (for the second quarter of 2004) was $94.9
million.
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.
Litigation and Environmental
As of September 30, 2005, we have recorded a total reserve for
environmental claims, without discounting and without regard to anticipated
insurance recoveries, in the amount of $26.7 million. 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. Please refer to Note
3 to our consolidated financial statements included elsewhere in this report for
additional information on our pending environmental and litigation matters. 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
75
circumstances could cause these matters to have a material adverse impact.
Pursuant to our continuing commitment to operational excellence and our
focus on safe, reliable operations, we have implemented, and intend to implement
in the future, enhancements to certain of our operational practices in order to
strengthen our environmental and asset integrity performance. The repairs
resulting from these enhancements have resulted and we expect that they will
result in higher capital and/or operating costs and expenses; however, we
believe these enhancements and repairs will provide us the greater long term
benefits of improved environmental and asset integrity performance.
Certain Contractual Obligations
There have been no material changes in either certain contractual
obligations or our obligations with respect to other entities which are not
consolidated in our financial statements that would affect the disclosures
presented as of December 31, 2004 in our 2004 Form 10-K report.
Information Regarding Forward-Looking Statements
This filing includes forward-looking statements. These forward-looking
statements are identified as any statement that does not relate strictly to
historical or current facts. They use words such as "anticipate," "believe,"
"intend," "plan," "projection," "forecast," "strategy," "position," "continue,"
"estimate," "expect," "may," or the negative of those terms or other variations
of them or comparable terminology. In particular, statements, express or
implied, concerning future actions, conditions or events, future operating
results or the ability to generate sales, income or cash flow or to make
distributions are forward-looking statements. Forward-looking statements are not
guarantees of performance. They involve risks, uncertainties and assumptions.
Future actions, conditions or events and future results of operations may differ
materially from those expressed in these forward-looking statements. Many of the
factors that will determine these results are beyond our ability to control or
predict. Specific factors which could cause actual results to differ from those
in the forward-looking statements include:
- price trends and overall demand for natural gas liquids, refined
petroleum products, oil, carbon dioxide, natural gas, coal and other bulk
materials and chemicals in the United States;
- economic activity, weather, alternative energy sources, conservation and
technological advances that may affect price trends and demand;
- changes in our tariff rates implemented by the Federal Energy Regulatory
Commission or the California Public Utilities Commission;
- our ability to acquire new businesses and assets and integrate those
operations into our existing operations, as well as our ability to make
expansions to our facilities;
- difficulties or delays experienced by railroads, barges, trucks, ships or
pipelines in delivering products to or from our terminals or pipelines;
- our ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
- shut-downs or cutbacks at major refineries, petrochemical or chemical
plants, ports, utilities, military bases or other businesses that use our
services or provide services or products to us;
- 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;
- 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;
- 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;
76
- our indebtedness could make us vulnerable to general adverse economic and
industry conditions, limit our ability to borrow additional funds and/or
place us at competitive disadvantages compared to our competitors that
have less debt or have other adverse consequences;
- interruptions of electric power supply to our facilities due to natural
disasters, power shortages, strikes, riots, terrorism, war or other
causes;
- our ability to obtain insurance coverage without significant levels of
self-retention of risk;
- acts of nature, sabotage, terrorism or other similar acts causing damage
greater than our insurance coverage limits;
- capital markets conditions;
- the political and economic stability of the oil producing nations of the
world;
- national, international, regional and local economic, competitive and
regulatory conditions and developments;
- the ability to achieve cost savings and revenue growth;
- inflation;
- interest rates;
- the pace of deregulation of retail natural gas and electricity;
- foreign exchange fluctuations;
- the timing and extent of changes in commodity prices for oil, natural
gas, electricity and certain agricultural products;
- 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;
- engineering and mechanical or technological difficulties with operational
equipment, in well completions and workovers, and in drilling new wells;
- the uncertainty inherent in estimating future oil and natural gas
production or reserves;
- the timing and success of business development efforts; and
- unfavorable results of litigation and the fruition of contingencies
referred to in Note 16 to our consolidated financial statements included
elsewhere in this report.
You should not put undue reliance on any forward-looking statements.
See Items 1 and 2 "Business and Properties--Risk Factors" of our Annual
Report on Form 10-K for the year ended December 31, 2004, 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 2004 Form 10-K report. The risk factors could
cause our actual results to differ materially from those contained in any
forward-looking statement. We disclaim any obligation to update the above list
or to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments.
77
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,
2004, in Item 7A of our 2004 Form 10-K report. For more information on our risk
management activities, see Note 10 to our consolidated financial statements
included elsewhere in this report.
Item 4. Controls and Procedures.
As of September 30, 2005, our management, including our Chief Executive
Officer and Chief Financial Officer, has evaluated the effectiveness of the
design and operation of our disclosure controls and procedures pursuant to Rule
13a-15(b) under the Securities Exchange Act of 1934. There are inherent
limitations to the effectiveness of any system of disclosure controls and
procedures, including the possibility of human error and the circumvention or
overriding of the controls and procedures. Accordingly, even effective
disclosure controls and procedures can only provide reasonable assurance of
achieving their control objectives. Based upon and as of the date of the
evaluation, our Chief Executive Officer and our Chief Financial Officer
concluded that the design and operation of our disclosure controls and
procedures were effective in all material respects to provide reasonable
assurance that information required to be disclosed in the reports we file and
submit under the Exchange Act is recorded, processed, summarized and reported as
and when required, and is accumulated and communicated to our management,
including our Chief Executive Officer and our Chief Financial Officer, to allow
timely decisions regarding required disclosure. There has been no change in our
internal control over financial reporting during the quarter ended September 30,
2005 that has materially affected, or is reasonably likely to materially affect,
our internal control over financial reporting.
78
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 herein by reference.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Effective August 1, 2005, we issued 64,412 common units as part of the
purchase price for all of the partnership interests in General Stevedores, L.P.
The total purchase price for the acquired partnership interests was
approximately $8.9 million, consisting of $2.1 million in cash, $3.4 million in
common units, and $3.4 million in assumed liabilities, including debt of $3.0
million. The issuance of the units was exempt from registration under Section
4(2) of the Securities Act of 1933 because we issued the units to the two owners
of General Stevedores, L.P. in a transaction not involving a public offering.
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 the
Partnership and its consolidated subsidiaries which relate to debt that
does not exceed 10% of the total assets of the Partnership and its
consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii)
(A) of Regulation S-K, 17 C.F.R. ss.229.601.
10.1 -- Credit Agreement, dated as of August 5, 2005, by and among Kinder
Morgan Energy Partners, L.P.; Kinder Morgan Operating L.P. "B"; the
lenders party thereto; Wachovia Bank, National Association, as
Administrative Agent; Citibank, N.A. and JPMorgan Chase Bank, N.A., as
Co-Syndication Agents; The Royal Bank of Scotland plc and Barclays Bank
PLC, as Co-Documentation Agents (filed as Exhibit 10.1 to Kinder Morgan
Energy Patners, L.P.'s Current Report on Form 8-K, filed on August 11,
2005, and incorporated herein by reference).
11 -- Statement re: computation of per share earnings.
31.1 -- Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the
Securities Exchange Act of 1934, as adopted pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
31.2 -- Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the
Securities Exchange Act of 1934, as adopted pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
79
32.1 -- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 -- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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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 J. Allen
------------------------------
Kimberly J. Allen
Vice President and Chief Financial Officer
(principal financial officer and principal
accounting officer)
Date: November 1, 2005
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