F O R M 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 by Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X]
No [ ]
The Registrant had 148,583,914 common units outstanding as of July 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 Six Months
Ended June 30, 2005 and 2004.................................. 3
Consolidated Balance Sheets - June 30, 2005 and December
31, 2004...................................................... 4
Consolidated Statements of Cash Flows - Six Months Ended
June 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............................. 53
Critical Accounting Policies and Estimates.................... 53
Results of Operations......................................... 53
Financial Condition........................................... 66
Information Regarding Forward-Looking Statements.............. 70
Item 3: Quantitative and Qualitative Disclosures About Market Risk....... 72
Item 4: Controls and Procedures.......................................... 72
` PART II. OTHER INFORMATION
Item 1: Legal Proceedings............................................... 73
Item 2: Unregistered Sales of Equity Securities and Use of Proceeds..... 73
Item 3: Defaults Upon Senior Securities................................. 73
Item 4: Submission of Matters to a Vote of Security Holders............. 73
Item 5: Other Information............................................... 73
Item 6: Exhibits........................................................ 74
Signature....................................................... 75
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Unit Amounts)
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
------------------------------- -------------------------------
2005 2004 2005 2004
------------- ------------- ------------- -------------
Revenues
Natural gas sales....................................... $ 1,492,534 $ 1,449,493 $ 2,845,149 $ 2,775,787
Services................................................ 455,602 380,301 899,027 752,421
Product sales and other................................. 178,219 127,388 354,111 251,230
----------- ----------- ---------- ----------
2,126,355 1,957,182 4,098,287 3,779,438
----------- ----------- ---------- ----------
Costs and Expenses
Gas purchases and other costs of sales................... 1,487,574 1,439,326 2,825,344 2,756,635
Operations and maintenance............................... 153,595 119,397 292,135 230,589
Fuel and power........................................... 45,438 38,004 87,378 71,512
Depreciation, depletion and amortization................. 88,261 69,878 173,288 137,409
General and administrative............................... 50,133 39,457 123,985 87,711
Taxes, other than income taxes........................... 26,225 19,756 52,051 39,076
----------- ----------- ---------- ----------
1,851,226 1,725,818 3,554,181 3,322,932
----------- ----------- ---------- ----------
Operating Income........................................... 275,129 231,364 544,106 456,506
Other Income (Expense)
Earnings from equity investments......................... 22,838 20,609 48,910 41,078
Amortization of excess cost of equity investments........ (1,409) (1,394) (2,826) (2,788)
Interest, net............................................ (65,312) (46,592) (124,039) (93,813)
Other, net............................................... 649 (489) (672) 254
Minority Interest.......................................... (2,454) (2,462) (4,842) (4,543)
----------- ----------- ---------- ----------
Income Before Income Taxes................................. 229,441 201,036 460,637 396,694
Income Taxes............................................... (7,615) (5,818) (15,190) (9,722)
----------- ------------ ---------- -----------
Net Income................................................. $ 221,826 $ 195,218 $ 445,447 $ 386,972
=========== =========== ========== ==========
General Partner's interest in Net Income................... $ 117,253 $ 95,867 $ 228,980 $ 187,531
Limited Partners' interest in Net Income................... 104,573 99,351 216,467 199,441
----------- ----------- ---------- ----------
Net Income................................................. $ 221,826 $ 195,218 $ 445,447 $ 386,972
=========== =========== ========== ==========
Basic and Diluted Limited Partners' Net Income per Unit ... $ 0.50 $ 0.51 $ 1.04 $ 1.03
=========== ========== ========== ==========
Weighted average number of units used in computation
of Limited Partners'NetIncome per unit:
Basic...................................................... 209,220 195,949 208,379 194,231
=========== =========== ========== ==========
Diluted.................................................... 209,465 196,030 208,529 194,316
=========== =========== ========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
3
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
June 30, December 31,
ASSETS 2005 2004
---- ----
Current Assets
Cash and cash equivalents.................................... $ 37,556 $ -
Restricted deposits.......................................... 32,420 -
Accounts, notes and interest receivable, net
Trade..................................................... 737,332 739,798
Related parties........................................... 4,341 12,482
Inventories
Products.................................................. 20,443 17,868
Materials and supplies.................................... 11,627 11,345
Gas imbalances
Trade..................................................... 20,300 24,653
Related parties........................................... 2,021 980
Gas in underground storage................................... 4,331 -
Other current assets......................................... 92,543 46,045
------------- -------------
962,914 853,171
------------- -------------
Property, Plant and Equipment, net............................. 8,399,686 8,168,680
Investments.................................................... 427,195 413,255
Notes receivable
Trade........................................................ 1,944 1,944
Related parties.............................................. 110,126 111,225
Goodwill....................................................... 755,637 732,838
Other intangibles, net......................................... 200,487 15,284
Deferred charges and other assets.............................. 413,016 256,545
------------- -------------
Total Assets................................................... $11,271,005 $10,552,942
============= =============
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts...................................... $ 1,241 $ 29,866
Trade..................................................... 661,221 685,034
Related parties........................................... 1,554 16,650
Current portion of long-term debt............................ - -
Accrued interest............................................. 67,693 56,930
Accrued taxes................................................ 48,776 26,435
Deferred revenues............................................ 13,483 7,825
Gas imbalances............................................... 29,303 32,452
Accrued other current liabilities............................ 550,363 325,663
------------- -------------
1,373,634 1,180,855
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding............................................... 5,247,403 4,722,410
Market value of interest rate swaps....................... 214,079 130,153
------------- --------------
5,461,482 4,852,563
Deferred revenues............................................ 10,719 14,680
Deferred income taxes........................................ 57,782 56,487
Asset retirement obligations................................. 37,228 37,464
Other long-term liabilities and deferred credits............. 962,607 468,727
------------- -------------
6,529,818 5,429,921
Commitments and Contingencies (Note 3)
Minority Interest.............................................. 39,970 45,646
------------- -------------
Partners' Capital
Common Units................................................. 2,417,390 2,438,011
Class B Units................................................ 114,965 117,414
i-Units...................................................... 1,752,212 1,694,971
General Partner.............................................. 112,161 103,467
Accumulated other comprehensive loss......................... (1,069,145) (457,343)
-------------- --------------
3,327,583 3,896,520
Total Liabilities and Partners' Capital........................ $11,271,005 $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)
Six Months Ended June 30,
2005 2004
--------------- ------------
Cash Flows From Operating Activities
Net income........................................................................... $ 445,447 $ 386,972
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization........................................... 173,288 137,409
Amortization of excess cost of equity investments.................................. 2,826 2,788
Earnings from equity investments................................................... (48,910) (41,078)
Distributions from equity investments................................................ 30,089 35,005
Changes in components of working capital, net of effects of acquisitions:
Accounts receivable................................................................ 11,455 (139,540)
Other current assets............................................................... (3,528) 23,614
Inventories........................................................................ (2,180) (3,978)
Accounts payable................................................................... (38,721) 160,917
Accrued liabilities................................................................ 14,233 (20,597)
Accrued taxes...................................................................... 22,356 17,534
Other, net........................................................................... (18,115) (3,240)
------------- -------------
Net Cash Provided by Operating Activities.............................................. 588,240 555,806
------------ ------------
Cash Flows From Investing Activities
Acquisitions of assets............................................................... (193,330) (51,679)
Additions to property, plant and equip. for expansion and maintenance projects....... (341,609) (339,525)
Sale of investments, property, plant and equipment, net of removal costs............. 2,474 1,452
Investments in margin deposits....................................................... (32,420) --
Contributions to equity investments.................................................. (1,070) (3,875)
Natural gas stored underground and natural gas liquids line-fill..................... (20,574) (564)
Other................................................................................ (295) (897)
------------- -------------
Net Cash Used in Investing Activities.................................................. (586,824) (395,088)
------------ ------------
Cash Flows From Financing Activities
Issuance of debt..................................................................... 2,599,233 2,744,061
Payment of debt...................................................................... (2,074,849) (2,767,262)
Debt issue costs..................................................................... (4,994) (317)
Repayments on loans to related parties............................................... 1,048 --
Decrease in cash book overdrafts..................................................... (28,625) --
Proceeds from issuance of common units............................................... 1,532 238,051
Proceeds from issuance of i-units.................................................... - 14,925
Contributions from minority interest................................................. 1,510 3,272
Distributions to partners:
Common units....................................................................... (222,099) (188,248)
Class B units...................................................................... (7,970) (7,279)
General Partner.................................................................... (220,286) (179,140)
Minority interest.................................................................. (5,785) (4,716)
Other, net........................................................................... (2,370) (3,667)
------------- -------------
Net Cash Provided by (Used in) Financing Activities.................................... 36,345 (150,320)
------------- -------------
Effect of exchange rate changes on cash and cash equivalents........................... (205) --
------------- -------------
Increase in Cash and Cash Equivalents.................................................. 37,556 10,398
Cash and Cash Equivalents, beginning of period......................................... - 23,329
------------- -------------
Cash and Cash Equivalents, end of period............................................... $ 37,556 $ 33,727
============= =============
Noncash Investing and Financing Activities:
Assets acquired by the issuance of units............................................. 46,250 --
Assets acquired by the assumption of liabilities..................................... 15,387 3,724
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. and Kinder Morgan Management, LLC
Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of
Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware
corporation, is the sole stockholder of our general partner, Kinder Morgan
G.P., Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report.
Kinder Morgan Management, LLC, a Delaware limited liability company, was
formed on February 14, 2001. Our general partner owns all of Kinder Morgan
Management, LLC's voting securities and, pursuant to a delegation of control
agreement, our general partner delegated to Kinder Morgan Management, LLC, to
the fullest extent permitted under Delaware law and our partnership agreement,
all of its power and authority to manage and control our business and affairs,
except that Kinder Morgan Management, LLC cannot take certain specified actions
without the approval of our general partner. Under the delegation of control
agreement, Kinder Morgan Management, LLC manages and controls our business and
affairs and the business and affairs of our operating limited partnerships and
their subsidiaries. Furthermore, in accordance with its limited liability
company agreement, Kinder Morgan Management, LLC's activities are limited to
being a limited partner in, and managing and controlling the business and
affairs of us, our operating limited partnerships and their subsidiaries. Kinder
Morgan Management, LLC is referred to as "KMR" in this report.
Basis of Presentation
Our consolidated financial statements include our accounts and those of our
majority-owned and controlled subsidiaries and our operating partnerships. All
significant intercompany items have been eliminated in consolidation. Certain
amounts from prior periods have been reclassified to conform to the current
presentation.
Net Income Per Unit
We compute Basic Limited Partners' Net Income per Unit by dividing our limited
partners' interest in net income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the potential dilution, by application of the treasury stock method,
that could occur if options to issue units were exercised, which would result in
the issuance of additional units that would then share in our net income.
6
2. Acquisitions and Joint Ventures
During the first six 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 Purchase Current Property Deferred Goodwill Minority
Plant & Charges
Price Assets Equipment & Other 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 10.2 70.2 3.1 6.2 -
(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 ........ $ 245.0 $ - $72.4 $ 162.7 $9.9 $ -
(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.
(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
7
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. Our allocation of the purchase price
to assets acquired and liabilities assumed is preliminary, pending final
purchase price adjustments that may be necessary following an independent
appraisal of fair market values. We expect the appraisal to be completed in the
third quarter of 2005. In the second quarter of 2005, we made purchase price
adjustments that increased receivables $0.3 million, decreased goodwill $0.2
million, and increased current liabilities $0.1 million. The changes related to
adjustments in receivables due from certain outstanding life insurance policies,
and to adjustments in assumed liabilities at acquisition. The $6.2 million of
goodwill was assigned to our Terminals business segment, and the entire amount
is expected to be deductible for tax purposes.
(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 an independent
appraisal of fair market values, which is expected to be completed in the third
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.
(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 to as high as 4,000 barrels of oil per day. The acquired
operations are included as part of our CO2 business segment.
8
(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
$245 million, consisting of $183.7 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 an independent appraisal of
fair market values, which is expected to be completed in the third quarter of
2005. The $9.9 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.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement
information for the six months ended June 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
Six Months Ended June 30,
------------------------------------
2005 2004
--------------- ----------------
(Unaudited)
Revenues................................. $ 4,117,541 $ 3,884,840
Operating Income......................... 551,604 493,434
Net Income............................... $ 451,215 $ 419,790
Basic and Diluted Limited Partners'
Net Income per unit................... $ 1.06 $ 1.17
Acquisitions subsequent to June 30, 2005
Natural Gas Storage Facility
On June 28, 2005, we announced that we had agreed to acquire a natural gas
storage facility in Liberty County, Texas, from Texas Genco LLC for an aggregate
consideration of approximately $100 million, consisting of $51 million in cash
and $49 million in assumed debt. The facility, referred to as our 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
gas. The acquisition complements our existing Texas intrastate natural gas
pipeline group assets and positions 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 have 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 transaction is expected to
close in the third quarter of 2005, and we will include the Dayton storage
facility's operations in our Natural Gas Pipelines business segment.
9
Terminal Assets
In July 2005, we announced three separate terminal acquisitions totaling $50
million, including capital to enhance operational efficiency. The largest of the
transactions is the purchase of a refined petroleum products terminal in New
York Harbor from ExxonMobil Oil Corporation. The second acquisition involves a
dry-bulk river terminal located in the State of Kentucky, and the third involves
a liquids/dry-bulk facility located in Blytheville, Arkansas.
The New York terminal, located on Staten Island, currently has 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 acquisition complements our
existing Northeast liquid terminal facilities located in Carteret and Perth
Amboy, New Jersey. The transaction was closed in July 2005, and we will include
the terminal's operations in our Terminals business segment.
The dry-bulk terminal, located along the Ohio River in Hawsville, Kentucky,
primarily handles wood chips and finished paper products. 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 acquisition complements our existing terminal assets located in
the Ohio River Valley and further expands our wood-chip handling businesses. The
transaction was closed in July 2005, and we will include the terminal's
operations in our Terminals business segment.
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 facility puts us into
position to take advantage of the increase in fertilizer imports that has
resulted from the shut down of domestic production. The terminal is one of only
two facilities in the United States that can handle imported fertilizer and
provide shipment west on railcars. The transaction was closed in July 2005, and
we will include the terminal's operations in our Terminals business segment.
3. Litigation and Other Contingencies
SFPP, L.P.
Federal Energy Regulatory Commission Proceedings
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 involving shippers' complaints
regarding the interstate rates, as well as practices and the jurisdictional
nature of certain facilities and services, on our Pacific operations' pipeline
systems.
OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a
consolidated proceeding that began in September 1992 and includes a number of
shipper complaints against certain rates and practices on SFPP's East Line (from
El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California
to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson
Station in Carson, California. The complainants in the case are El Paso
Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company,
Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products
Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing
Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.),
Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco
Corporation (now part of ConocoPhillips Company). The FERC has ruled that the
complainants have the burden of proof in 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
10
1992 and therefore deemed to be just and reasonable; it further held that
complainants had failed to prove "substantially changed circumstances" with
respect to those rates and that the rates therefore could not be challenged in
the Docket No. OR92-8 et al. proceedings, either for the past or prospectively.
However, the initial decision also made rulings generally adverse to SFPP on
certain cost of service issues relating to the evaluation of East Line rates,
which are not "grandfathered" under the Energy Policy Act. Those issues included
the capital structure to be used in computing SFPP's "starting rate base," the
level of income tax allowance SFPP may include in rates and the recovery of
civil and regulatory litigation expenses and certain pipeline reconditioning
costs incurred by SFPP. The initial decision also held SFPP's Watson Station
gathering enhancement service was subject to FERC jurisdiction and ordered SFPP
to file a tariff for that service.
The FERC subsequently reviewed the initial decision, and issued a series of
orders in which it adopted certain rulings made by the administrative law judge,
changed others and modified a number of its own rulings on rehearing. Those
orders began in January 1999, with FERC Opinion No. 435, and continued through
June 2003.
The FERC affirmed that all but one of SFPP's West Line rates are
"grandfathered" and that complainants had failed to satisfy the threshold burden
of demonstrating "substantially changed circumstances" necessary to challenge
those rates. The FERC further held that the one West Line rate that was not
grandfathered did not need to be reduced. The FERC consequently dismissed all
complaints against the West Line rates in Docket Nos. OR92-8 et al. without any
requirement that SFPP reduce, or pay any reparations for, any West Line rate.
The FERC initially modified the initial decision's ruling regarding the
capital structure to be used in computing SFPP's "starting rate base" to be more
favorable to SFPP, but later reversed that ruling. The FERC also made certain
modifications to the calculation of the income tax allowance and other cost of
service components, generally to SFPP's disadvantage.
On multiple occasions, the FERC required SFPP to file revised East Line rates
based on rulings made in the FERC's various orders. SFPP was also directed to
submit compliance filings showing the calculation of the revised rates, the
potential reparations for each complainant and in some cases potential refunds
to shippers. SFPP filed such revised East Line rates and compliance filings in
March 1999, July 2000, November 2001 (revised December 2001), October 2002 and
February 2003 (revised March 2003). Most of those filings were protested by
particular SFPP shippers. The FERC has held that certain of the rates SFPP filed
at the FERC's directive should be reduced retroactively and/or be subject to
refund; SFPP has challenged the FERC's authority to impose such requirements in
this context.
While the FERC initially permitted SFPP to recover certain of its litigation,
pipeline reconditioning and environmental costs, either through a surcharge on
prospective rates or as an offset to potential reparations, it ultimately
limited recovery in such a way that SFPP was not able to make any such surcharge
or take any such offset. Similarly, the FERC initially ruled that SFPP would not
owe reparations to any complainant for any period prior to the date on which
that party's complaint was filed, but ultimately held that each complainant
could recover reparations for a period extending two years prior to the filing
of its complaint (except for Navajo, which was limited to one month of
pre-complaint reparations under a settlement agreement with SFPP's predecessor).
The FERC also ultimately held that SFPP was not required to pay reparations or
refunds for Watson Station gathering enhancement fees charged prior to filing a
FERC tariff for that service.
In April 2003, SFPP paid complainants and other shippers reparations and/or
refunds as required by FERC's orders. In August 2003, SFPP paid shippers an
additional refund as required by FERC's most recent order in the Docket No.
OR92-8 et al. proceedings. We made aggregate payments of $44.9 million in 2003
for reparations and refunds pursuant to a FERC order.
Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond
Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for
review of FERC's Docket OR92-8 et al. orders in the United States Court of
Appeals for the District of Columbia Circuit. Certain of those petitions were
dismissed by the Court of Appeals as premature, and the remaining petitions were
held in abeyance pending completion of agency action. However, in December 2002,
the Court of Appeals returned to its active docket all petitions to review the
FERC's orders in the case through November 2001 and severed petitions regarding
later FERC orders. The severed orders were held in abeyance for later
consideration.
11
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 Circuit Court 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 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.
12
The Court of Appeals accepted the FERC's treatment of regulatory litigation
costs, including the limitation of recoverable costs and their offset against
"unclaimed reparations" - that is, reparations that could have been awarded to
parties that did not seek them. The court also accepted the FERC's denial of any
recovery for the costs of civil litigation by East Line shippers against SFPP
based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix.
However, the court did not find adequate support for the FERC's decision to
allocate the limited litigation costs that SFPP was allowed to recover in its
rates equally between the East Line and the West Line, and ordered the FERC to
explain that decision further on remand.
The Court of Appeals held the FERC had failed to justify its decision to deny
SFPP any recovery of funds spent to recondition pipe on the East Line, for which
SFPP had spent nearly $6 million between 1995 and 1998. It concluded that the
Commission's reasoning was inconsistent and incomplete, and remanded for further
explanation, noting that "SFPP's shippers are presently enjoying the benefits of
what appears to be an expensive pipeline reconditioning program without sharing
in any of its costs."
The Court of Appeals affirmed the FERC's rulings on reparations in all
respects. It held the Arizona Grocery doctrine did not apply to orders requiring
SFPP to file "interim" rates, and that "FERC only established a final rate at
the completion of the OR92-8 proceedings." It held that the Energy Policy Act
did not limit complainants' ability to seek reparations for up to two years
prior to the filing of complaints against rates that are not grandfathered. It
rejected SFPP's arguments that the FERC should not have used a "test period" to
compute reparations that it should have offset years in which there were
underrecoveries against those in which there were overrecoveries, and that it
should have exercised its discretion against awarding any reparations in this
case.
The Court of Appeals also rejected:
o Navajo's argument that its prior settlement with SFPP's predecessor
did not limit its right to seek reparations;
o Valero's argument that it should have been permitted to recover
reparations in the Docket No. OR92-8 et al. proceedings rather
than waiting to seek them, as appropriate, in the Docket No.
OR96-2 et al. proceedings;
o arguments that the former ARCO and Texaco had challenged East
Line rates when they filed a complaint in January 1994 and should
therefore be entitled to recover East Line reparations; and
o Chevron's argument that its reparations period should begin two
years before its September 1992 protest regarding the six-inch
line reversal rather than its August 1993 complaint against East
Line rates.
On September 2, 2004, BP West Coast Products, ChevronTexaco, ConocoPhillips
and ExxonMobil filed a petition for rehearing and rehearing en banc asking the
Court of Appeals to reconsider its ruling that West Line rates were not subject
to investigation at the time the Energy Policy Act was enacted. On September 3,
2004, SFPP filed a petition for rehearing asking the court to confirm that the
FERC has the same discretion to address on remand the income tax allowance issue
that administrative agencies normally have when their decisions are set aside by
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
13
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. The rulings
regarding the OR96-2 proceedings (discussed following).
With respect to the OR92-8 proceedings, the June 1, 2005 order ruled on
several issues that had been remanded by the Court of Appeals in BP West Coast
Products 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
December 2005. 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 pipelines (Line
Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject
to FERC's jurisdiction under the Interstate Commerce Act, and claimed that the
rate for that service was unlawful. Several other West Line shippers filed
similar complaints and/or motions to intervene.
Following a hearing in March 1997, a FERC administrative law judge issued an
initial decision holding that the movements on the Sepulveda pipelines were not
subject to FERC jurisdiction. On August 5, 1997, the FERC reversed that
decision. On October 6, 1997, SFPP filed a tariff establishing the initial
interstate rate for movements on the Sepulveda pipelines at the pre-existing
rate of five cents per barrel. Several shippers protested that rate. In December
1997, SFPP filed an application for authority to charge a market-based rate for
the Sepulveda service, which application was protested by several parties. On
September 30, 1998, the FERC issued an order finding that SFPP lacks market
power in the Watson Station destination market and set a hearing to determine
whether SFPP
14
possessed market power in the origin market.
Following a hearing, on December 21, 2000, an administrative law judge found
that SFPP possessed market power over the Sepulveda origin market. On February
28, 2003, the FERC issued an order upholding that decision. SFPP filed a request
for rehearing of that order on March 31, 2003. The FERC denied SFPP's request
for rehearing on July 9, 2003.
As part of its February 28, 2003 order denying SFPP's application for
market-based ratemaking authority, the FERC remanded to the ongoing litigation
in Docket No. OR96-2, et al. the question of whether SFPP's current rate for
service on the Sepulveda line is just and reasonable. A hearing in this
proceeding was held in February and March 2005. The matter has now been briefed
to the administrative law judge in this proceeding and his initial decision is
pending.
OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar Diamond
Shamrock Corporation filed a complaint at FERC (Docket No. OR97-2) challenging
SFPP's West Line rates, claiming they were unjust and unreasonable and no longer
subject to grandfathering. In October 1997, ARCO, Mobil and Texaco filed a
complaint at the FERC (Docket No. OR98-1) challenging the justness and
reasonableness of all of SFPP's interstate rates, raising claims against SFPP's
East and West Line rates similar to those that have been at issue in Docket Nos.
OR92-8, et al. discussed above, but expanding them to include challenges to
SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno,
Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line. In
November 1997, Ultramar filed a similar, expanded complaint (Docket No. OR98-2).
Tosco Corporation filed a similar complaint in April 1998. The shippers seek
both reparations and prospective rate reductions for movements on all of SFPP's
lines. The FERC accepted the complaints and consolidated them into one
proceeding (Docket No. OR96-2, et al.), but held them in abeyance pending a FERC
decision on review of the initial decision in Docket Nos. OR92-8, et al.
In a companion order to Opinion No. 435, the FERC gave the complainants an
opportunity to amend their complaints in light of Opinion No. 435, which the
complainants did in January 2000. In August 2000, Navajo and Western filed
complaints against SFPP's East Line rates and Ultramar filed an additional
complaint updating its pre-existing challenges to SFPP's interstate pipeline
rates. These complaints were consolidated with the ongoing proceeding in Docket
No. OR96-2, et al.
A hearing in this consolidated proceeding was held from October 2001 to March
2002. A FERC administrative law judge issued his initial decision on June 24,
2003. The initial decision found that, for the years at issue, the complainants
had shown substantially changed circumstances for rates on SFPP's West, North
and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson
Station and thus found that those rates should not be "grandfathered" under the
Energy Policy Act of 1992. The initial decision also found that most of SFPP's
rates at issue were unjust and unreasonable.
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
15
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
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. SFPP
demonstrated that, based on the tax-paying characteristics of the types of
entities that, during the years at issue in the two cases, owned limited
partnership interests in us, the master limited partnership that indirectly owns
nearly all of SFPP, the income generated by SFPP was subject to actual or
potential tax liability, thereby justifying the FERC in granting SFPP a full
income tax allowance. 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 third 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 of delay in the implementation
of rate reductions sought, we estimate that reparations and accrued interest
accumulates by approximately $9 million. We now assume that any potential rate
reductions will be implemented no earlier than the third quarter of 2005 and
that reparations and accrued interest thereon will be paid no earlier than the
third 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.
16
Chevron complaint OR02-4 proceedings. On February 11, 2002, Chevron, an
intervenor in the Docket No. OR96-2, et al. proceeding, filed a complaint
against SFPP in Docket No. OR02-4 along with a motion to consolidate the
complaint with the Docket No. OR96-2, et al. proceeding. On May 21, 2002, the
FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed a
request for rehearing, which the FERC dismissed on September 25, 2002. In
October 2002, Chevron filed a request for rehearing of the FERC's September 25,
2002 Order, which the FERC denied on May 23, 2003. On July 1, 2003, Chevron
filed a petition for review of this denial at the U.S. Court of Appeals for the
District of Columbia Circuit. On August 18, 2003, SFPP filed a motion to dismiss
Chevron's petition on the basis that Chevron lacks standing to bring its appeal
and that the case is not ripe for review. Chevron answered on September 10,
2003. SFPP's motion was pending, when the Court of Appeals, on December 8, 2003,
granted Chevron's motion to hold the case in abeyance pending the outcome of the
appeal of the Docket No. OR92-8, et al. proceeding. On January 8, 2004, the
Court of Appeals granted Chevron's motion to have its appeal of the FERC's
decision in Docket No. OR03-5 (see below) consolidated with Chevron's appeal of
the FERC's decision in the Docket No. OR02-4 proceeding. 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. FERC action on those motions and the complaint is pending.
OR05-4 proceeding. 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,
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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.
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 third or 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
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 third or 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
18
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.
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. A trial date has tentatively been set for
January 2006, but SFPP expects that the trial date will be postponed and that
the trial will occur in late 2006.
ARB, Inc. Dispute
ARB, Inc, a general contractor engaged by SFPP, L.P. to build a 20-inch
70-mile pipeline from Concord to Sacramento, California is seeking additional
payments based on alleged scope changes and delays on the project. After
deducting for payments made by SFPP to date, ARB asserts that it is owed between
$13.1 million and $16.8 million on the project. ARB has indicated that its
calculation of outstanding amounts may be increased in the future pending
further analysis. SFPP has engaged construction claims specialists and auditors
to review the project records and determine what additional payments, if any,
should be made to ARB. Numerous third party subcontractors have filed liens
against ARB and SFPP. SFPP has requested that ARB honor its contractual
obligation to avoid and discharge any liens arising on the project.
Standards of Conduct Rulemaking
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.
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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.
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
20
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
- 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.
21
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:
o prepare a plan to implement the program;
o identify high consequence areas;
o develop and maintain a record keeping system; and
o inspect affected pipeline segments.
The costs of modifying the pipeline to permit in-line inspections, such as
installing pig launchers and receivers, are to be capitalized, as are certain
costs associated with developing or enhancing computer software or to add or
replace other items of plant. We are currently reviewing the effects of this
order on our financial statements.
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.
On February 20, 2004, the D.C. Circuit Court of Appeals for the District of
Columbia remanded back to the FERC a Williston Basin Interstate Pipeline
proceeding in which the court ruled that the FERC did not explain how the
selective discounting policy adopted by the FERC in the Colorado Interstate Gas
Co. and Granite State Gas Transmission cases would not compromise the pipelines'
ability to target discounts at particular receipt/delivery points, subsystems or
other defined geographic areas. On June 1, 2004, the FERC issued a Notice of
Request for Comments in the Williston Basin Interstate Pipeline proceeding, on
issues pertaining to the discounting policy adopted in the Colorado Interstate
Gas Co. and Granite State Gas Transmission cases. Comments were due on August 9,
2004. Numerous parties filed comments, including our three interstate natural
gas pipelines: Kinder Morgan Interstate Gas Transmission LLC, Trailblazer
Pipeline Company and TransColorado Gas Transmission Company. On March 3, 2005,
the FERC issued an Order on Remand in the Williston Basin Interstate Pipeline,
Co. proceeding (RP00-463). The FERC has concluded that it cannot, at the present
time, satisfy its burden under Section 5 of the Natural Gas Act to require
Williston or other pipelines to modify their tariffs to incorporate the
CIG/Granite State policy. The FERC will return to its pre-existing policy of
permitting pipelines to limit the selective discounts they offer shippers to
particular points. Pipelines who implemented the CIG/Granite State policy
pursuant to orders that are now final may file pursuant to Section 4 of the
Natural Gas Act to remove their tariff provisions implementing that policy. Our
interstate natural gas pipelines have filed to remove these tariff provisions,
and on May 20, 2005, the FERC approved these filings.
Index of Customer Audit
On July 14, 2005, the FERC commenced an audit of our 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 filings and postings
of the Index of Customers.
22
Other Regulatory
Marathon Oil Company Complaint
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.
Other
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. Counsel for some of the individual plaintiffs in these
cases previously indicated that those plaintiffs may refile their claims.
New lawsuits have been filed (discussed below).
On May 13, 2004, William Armor, one of the former plaintiffs in the Shores
matter whose claims were dismissed for improper venue by the Court of Appeals,
filed a new case alleging the same claims 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, Dallas County Court 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.
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, Dallas County Court 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. By agreement of the parties, the defendants' answer or other response
to the petition in Reddy is due on or before August 10, 2005.
23
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. 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. 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, Wichita County
Court filed March 1, 2004). The defendants in this action include Kinder Morgan
CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., various Shell entities,
ExxonMobil entities, and Cortez Pipeline Company. On June 25, 2004, defendants
filed answers, special exceptions, pleas in abatement, and motions to transfer
venue back to the Harris County District Court. On January 31, 2005, the Wichita
County judge abated the case pending resolution of the Bailey State Court
Action. The case remains abated.
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
24
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).
This case involves a purported class action against Kinder Morgan CO2 Company,
L.P. alleging that defendant 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 defendant's method of paying royalty interests is contrary to the
settlement of the Feerer Class Action. Defendant 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.
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
25
to intervene in support of the action. The complaint is part of a larger series
of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines
(approximately 330 other defendants). Certain entities we acquired in the Kinder
Morgan Tejas acquisition are also defendants in this matter. An earlier single
action making substantially similar allegations against the pipeline industry
was dismissed by Judge Hogan of the U.S. District Court for the District of
Columbia on grounds of improper joinder and lack of jurisdiction. As a result,
Mr. Grynberg filed individual complaints in various courts throughout the
country. In 1999, these cases were consolidated by the Judicial Panel for
Multidistrict Litigation, and transferred to the District of Wyoming. The
multidistrict litigation matter is called In Re Natural Gas Royalties Qui Tam
Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument
on the motion to dismiss occurred on March 17, 2000. On July 20, 2000, the
United States of America filed a motion to dismiss those claims by Grynberg that
deal with the manner in which defendants valued gas produced from federal
leases, referred to as valuation claims. Judge Downes denied the defendant's
motion to dismiss on May 18, 2001. The United States' motion to dismiss most of
plaintiff's valuation claims has been granted by the court. Grynberg has
appealed that dismissal to the 10th Circuit, which has requested briefing
regarding its jurisdiction over that appeal. Subsequently, Grynberg's appeal was
dismissed for lack of appellate jurisdiction. Discovery to determine issues
related to the Court's subject matter jurisdiction arising out of the False
Claims Act is complete. Briefing has been completed and oral arguments on
jurisdiction were held before the Special Master on March 17 and 18, 2005. On
May 7, 2003, Grynberg sought leave to file a Third Amended Complaint, which adds
allegations of undermeasurement related to carbon dioxide production. Defendants
have filed briefs opposing leave to amend. Neither the Court nor the Special
Master has ruled on Grynberg's Motion to Amend.
On May 13, 2005, the Special Master issued his Report and Recommendations to
Judge Downes in the In Re Natural Gas Royalties Qui Tam Litigation, Docket No.
1293. The Special Master found that there was a prior public disclosure of the
mismeasurement fraud Grynberg alleged, and that Grynberg was not an original
source of the allegations. As a result, the Special Master recommended dismissal
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 third or fourth quarter of this year. It is likely that Grynberg
will appeal any dismissal to the 10th Circuit Court of Appeals.
Mel R. Sweatman and Paz Gas Corporation v. Gulf Energy Marketing, LLC, et
al.
On July 25, 2002, we were served with this suit for breach of contract,
tortious interference with existing contractual relationships, conspiracy to
commit tortious interference and interference with prospective business
relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection
with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to be
shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder Morgan
Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this action
eliminated profit on Kinder Morgan Tejas, a portion of which Mr. Sweatman and
Paz Gas Corporation claim they are entitled to receive under an agreement with a
subsidiary of ours acquired in the Tejas Gas acquisition. We filed a motion to
remove the case from venue in Dewitt County, Texas to Harris County, Texas, and
our motion was denied in a venue hearing in November 2002.
In a Second Amended Original Petition, Sweatman and Paz assert new and
distinct allegations against us, principally that we were a party to an alleged
commercial bribery committed by us, Gulf Energy Marketing, and Intergen inasmuch
as we, in our role as acquirer of Kinder Morgan Tejas, allegedly paid Intergen
to not renew the underlying Entex contracts belonging to the Tejas/Paz joint
venture. Moreover, new and distinct allegations of breach of fiduciary and
bribery of a fiduciary are also raised in this amended petition for the first
time.
The parties have engaged in some discovery and depositions. At this stage of
discovery, we believe that our actions were justified and defensible under
applicable Texas law and that the decision not to renew the underlying gas sales
agreements was made unilaterally by persons acting on behalf of Entex. The
plaintiffs have moved for summary judgment asking the court to declare that a
fiduciary relationship existed for purposes of Sweatman's claims. We have moved
for summary judgment on the grounds that:
26
o there is no cause-in-fact of the gas sales nonrenewals
attributable to us; and
o the defense of legal justification applies to the claims for
tortuous interference.
In September 2003 and then again in November 2003, Sweatman and Paz filed
their third and fourth amended petitions, respectively, asserting all of the
claims for relief described above. In addition, the plaintiffs asked that the
court impose a constructive trust on (i) the proceeds of the sale of Tejas and
(ii) any monies received by any Kinder Morgan entity for sales of gas to any
Entex/Reliant entity following June 30, 2002 that replaced volumes of gas
previously sold under contracts to which Sweatman and Paz had a participating
interest pursuant to the joint venture agreement between Tejas, Sweatman and
Paz. In October 2003, the court granted, and then rescinded its order after a
motion to reconsider heard on February 13, 2004, a motion for partial summary
judgment on the issue of the existence of a fiduciary duty.
On October 27, 2004, the court granted a motion for partial summary judgment
in the defendants' favor, finding that, as a matter of law, Sweatman's interests
in four of the five gas sales contracts at issue terminated in 1992 after those
contracts were amended in their material terms, and thus falling outside the
joint venture itself. In various forms, the plaintiffs have amended their
petition to allege various oral and implied joint venture agreements as well as
an oral partnership agreement. The claimants are asking for the imposition of a
constructive trust on the proceeds of gas sales contracts with Entex and its
affiliates that were entered into after the gas sales at issue were unilaterally
terminated by Entex on March 28, 2002, for which Sweatman blames us and our
agents and representatives.
We moved for partial summary judgment on all of Sweatman's claims, asserting
that even in the light most favorable to Sweatman's assertions, there is no
issue of material fact on whether Sweatman even owned an interest in the
underlying gas sales agreements in dispute. That motion was heard on August 13,
2004, and was granted on October 26, 2004 as to four of the five gas sales
contracts at issue, leaving for further determination at a later time any
remaining claims based upon other theories of recovery not dependent upon the
four gas sales agreements being joint venture property. We also filed a
no-evidence motion for summary judgment on the plaintiffs' defamation claims.
On March 24, 2005, we announced a settlement of this case. Under the terms of
the settlement, we agreed to pay $25 million to the defendants in full
settlement of any possible claims related to this case. We included this amount
as general and administrative expense in March 2005, and we made payment in
April 2005.
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. The Court has scheduled a Case Scheduling
27
and Trial Management Conference for August 24, 2005, and has deferred
consideration of the pending motions until after such conference. Based on the
information available to date and our preliminary investigation, the Kinder
Morgan Defendants believe that the claims against them are without merit and
intend to defend against them vigorously.
Marie Snyder, et al v. City of Fallon, United States Department of the Navy,
Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas
Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District
Court, District of Nevada)("Snyder"); Frankie Sue Galaz, et al v. United States
of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy
Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No.
cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)("Galaz
I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial District Court,
State of Nevada, County of Washoe) ("Galaz II); Frankie Sue Galaz, et al v. The
United States of America, the City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC (United States District
Court, District of Nevada)("Galaz III)
On July 9, 2002, we were served with a purported Complaint for Class Action in
the Snyder case, in which the plaintiffs, on behalf of themselves and others
similarly situated, assert that a leukemia cluster has developed in the City of
Fallon, Nevada. The Complaint alleges that the plaintiffs have been exposed to
unspecified "environmental carcinogens" at unspecified times in an unspecified
manner and are therefore "suffering a significantly increased fear of serious
disease." The plaintiffs seek a certification of a class of all persons in
Nevada who have lived for at least three months of their first ten years of life
in the City of Fallon between the years 1992 and the present who have not been
diagnosed with leukemia.
The Complaint purports to assert causes of action for nuisance and "knowing
concealment, suppression, or omission of material facts" against all defendants,
and seeks relief in the form of "a court-supervised trust fund, paid for by
defendants, jointly and severally, to finance a medical monitoring program to
deliver services to members of the purported class that include, but are not
limited to, testing, preventative screening and surveillance for conditions
resulting from, or which can potentially result from exposure to environmental
carcinogens," incidental damages, and attorneys' fees and costs.
The defendants responded to the Complaint by filing Motions to Dismiss on the
grounds that it fails to state a claim upon which relief can be granted. On
November 7, 2002, the United States District Court granted the Motion to Dismiss
filed by the United States, and further dismissed all claims against the
remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs
filed a Motion for Reconsideration and Leave to Amend, which was denied by the
Court on December 30, 2002. Plaintiffs filed a Notice of Appeal to the United
States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit
affirmed the dismissal of this case.
On December 3, 2002, plaintiffs filed an additional Complaint for Class Action
in the Galaz I matter asserting the same claims in the same court on behalf of
the same purported class against virtually the same defendants, including us. On
February 10, 2003, the defendants filed Motions to Dismiss the Galaz I Complaint
on the grounds that it also fails to state a claim upon which relief can be
granted. This motion to dismiss was granted as to all defendants on April 3,
2003. Plaintiffs have filed a Notice of Appeal to the United States Court of
Appeals for the 9th Circuit. On November 17, 2003, the 9th Circuit dismissed the
appeal, upholding the District Court's dismissal of 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.
28
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 and
several Kinder Morgan related entities and individuals and additional unrelated
defendants ("Jernee"). Plaintiffs in the Jernee matter claim that defendants
negligently and intentionally failed to inspect, repair and replace unidentified
segments of their pipeline and facilities, allowing "harmful substances and
emissions and gases" to damage "the environment and health of human beings."
Plaintiffs claim that "Adam Jernee's death was caused by leukemia that, in turn,
is believed to be due to exposure to industrial chemicals and toxins."
Plaintiffs purport to assert claims for wrongful death, premises liability,
negligence, negligence per se, intentional infliction of emotional distress,
negligent infliction of emotional distress, assault and battery, nuisance,
fraud, strict liability, and aiding and abetting, and seek unspecified special,
general and punitive damages. The Kinder Morgan defendants filed Motions to
Dismiss the complaint on November 20, 2003, which Motions are currently pending.
Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326
(Second Judicial District Court, State of Nevada, County of Washoe) ("Sands").
On August 28, 2003, a separate group of plaintiffs, represented by the counsel
for the plaintiffs in the Jernee matter, individually and on behalf of Stephanie
Suzanne Sands, filed a civil action in the Nevada State trial court against us
and several Kinder Morgan related entities and individuals and additional
unrelated defendants ("Sands"). Plaintiffs in the Sands matter claim that
defendants negligently and intentionally failed to inspect, repair and replace
unidentified segments of their pipeline and facilities, allowing "harmful
substances and emissions and gases" to damage "the environment and health of
human beings." Plaintiffs claim that Stephanie Suzanne Sands' death was caused
by leukemia that, in turn, is believed to be due to exposure to industrial
chemicals and toxins. Plaintiffs purport to assert claims for wrongful death,
premises liability, negligence, negligence per se, intentional infliction of
emotional distress, negligent infliction of emotional distress, assault and
battery, nuisance, fraud, strict liability, and aiding and abetting, and seek
unspecified special, general and punitive damages. The Kinder Morgan defendants
were served with the Complaint on January 10, 2004. On February 26, 2004, the
Kinder Morgan defendants filed a Motion to Dismiss and a Motion to Strike, which
motions are currently pending.
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.
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
29
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
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.
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).
The above-referenced 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).
The above-referenced 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.
30
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).
The above-referenced 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.
The above-referenced 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.
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.
Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids
Terminals, Inc. and ST Services, Inc.
On April 23, 2003, Exxon Mobil Corporation filed the Complaint in the Superior
Court of New Jersey, Gloucester County. We filed our answer to the Complaint on
June 27, 2003, in which we denied ExxonMobil's claims and allegations as well as
included counterclaims against ExxonMobil. The lawsuit relates to environmental
remediation obligations at a Paulsboro, New Jersey liquids terminal owned by
ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp.
from 1989 through September 2000, and owned currently by ST Services, Inc. Prior
to selling the terminal to GATX Terminals, ExxonMobil performed an environmental
site assessment of the terminal required prior to sale pursuant to state law.
During the site assessment, ExxonMobil discovered items that required
remediation and the New Jersey Department of Environmental Protection issued an
order that required ExxonMobil to perform various remediation activities to
remove hydrocarbon contamination at the terminal. ExxonMobil, we understand, is
still remediating the site and has not been removed as a responsible party from
the state's cleanup order; however, ExxonMobil claims that the remediation
continues because of GATX Terminals' storage of a fuel additive, MTBE, at the
terminal during GATX Terminals' ownership of the terminal. When GATX Terminals
sold the terminal to ST Services, the parties indemnified one another for
certain environmental matters. When GATX Terminals was sold to us, GATX
Terminals' indemnification obligations, if any, to ST Services may have passed
to us. Consequently, at issue is any indemnification obligations we may owe to
ST Services in respect to environmental remediation of MTBE at the terminal. The
Complaint seeks any and all damages related to remediating MTBE at the terminal,
and, according to the New Jersey Spill Compensation and Control Act, treble
damages may be available for actual dollars incorrectly spent by the successful
party in the lawsuit for remediating MTBE at the terminal. The parties have
recently completed discovery. 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 September 2005.
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
31
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.
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 is
scheduled to be completed in September 2005.
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.
Proposed Office of Pipeline Safety Civil Penalty and Compliance Order
On July 15, 2004, the U.S. Department of Transportation's Office of Pipeline
Safety ("OPS") issued a Proposed Civil Penalty and Proposed Compliance Order
(the "Proposed Order") concerning alleged violations of certain federal
regulations concerning our pipeline Integrity Management Program. The violations
alleged in the Proposed Order are based upon the results of inspections of our
Integrity Management Program at our products pipelines facilities in Orange,
California and Doraville, Georgia conducted in April and June of 2003,
respectively. As a result of the alleged violations, the OPS seeks to have us
implement a number of changes to our Integrity Management Program and also seeks
to impose a proposed civil penalty of 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 is anticipated that the decision in this matter and
potential administrative order will be issued in the third or fourth quarter of
2005.
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
32
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 and 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.
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:
o 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.;
o groundwater and soil remediation efforts under administrative orders issued
by various regulatory agencies on those assets purchased from GATX
Corporation, comprising Kinder Morgan Liquids Terminals LLC, KM Liquids
Terminals L.P., CALNEV Pipe Line LLC and Central Florida Pipeline LLC;
o 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
o 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.
Tucson, Arizona
On July 30, 2003, SFPP, L.P. suffered a sudden and accidental rupture of one
of its liquid products pipelines in the vicinity of Tucson, Arizona. The rupture
resulted in the release of petroleum product into the soil and groundwater in
the immediate vicinity of the rupture.
33
On September 11, 2003, the Arizona Department of Environmental Quality
("ADEQ") issued a Notice of Violation indicating that ADEQ "has reason to
believe" that SFPP violated certain Arizona statutes and rules due to the
discharge of petroleum product to the environment as a result of the pipeline
rupture. ADEQ asserted that such alleged violations could result in the
imposition of civil penalties against SFPP. SFPP timely responded to the Notice
of Violation, disputed its validity, and provided the information requested in
the Notice of Violation. According to ADEQ written policy, a Notice of Violation
is not an enforcement action, and is instead "an enforcement compliance
assurance tool used by ADEQ." ADEQ's policy also states that although ADEQ has
the "authority to issue appealable administrative orders compelling compliance,
a Notice of Violation has no such force or effect."
On November 13, 2003, ADEQ sent a second Notice of Violation with respect to
the pipeline rupture and release, stating that ADEQ had reason to believe that a
violation of additional Arizona regulations had resulted from the discharge of
petroleum, because the petroleum had reached groundwater. ADEQ asserted that
such alleged violations could result in the imposition of civil penalties
against SFPP. SFPP timely responded to this second Notice of Violation, disputed
its validity, and provided the information requested in the second Notice of
Violation.
On January 19, 2005, SFPP, L.P. and ADEQ announced a settlement with the terms
of the settlement set forth in a consent judgment filed with the Maricopa County
Superior Court. Under the terms of the settlement, we paid $500,000 to the State
of Arizona in full settlement of any possible claims by the state arising out of
the release. The settlement expressly provides that we do not admit any
wrongdoing or violation of environmental law. On April 12, 2005, the ADEQ filed
a Satisfaction of Judgment with the Maricopa County Superior Court acknowledging
full satisfaction of the Consent Judgment and terminating the Consent Judgment.
We are currently evaluating the long term costs of the cleanup. A substantial
portion of those costs are recoverable through insurance.
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
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.
34
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. We included the combined $5.4 million as general
and administrative expense in March 2005, and we made payments in the amount of
$0.3 million as of June 30, 2005.
We expect to pay the remaining $5.1 million in the third quarter of 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 June 30, 2005, the remediation
was substantially complete.
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.
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.
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
35
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.
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. We
are currently in final settlement discussions with TCEQ regarding this issue and
do not expect the cost of any settlement to be material. 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.
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.
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.
Although no assurance can be given, we believe that the ultimate resolution of
the environmental matters set forth in this note will not have a material
adverse effect on our business, financial position, results of operations or
cash flows. However, we are not able to reasonably estimate when the eventual
settlements of these claims will occur. Many factors may change in the future
affecting our reserve estimates, such as regulatory changes, groundwater and
land use near our sites, and changes in cleanup technology. As of June 30, 2005,
we have accrued an environmental reserve of $33.2 million.
Other
We are a defendant in various lawsuits arising from the day-to-day operations
of our businesses. Although no assurance can be given, we believe, based on our
experiences to date, that the ultimate resolution of such items will not have a
material adverse impact on our business, financial position, results of
operations or cash flows.
4. Asset Retirement Obligations
We account for our legal obligations associated with the retirement of
long-lived assets pursuant to Statement of Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides
accounting and reporting guidance for legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction
or normal operation of a long-lived asset.
SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. Under SFAS No. 143,
the fair value of asset retirement obligations are recorded as liabilities on a
discounted basis when they are incurred, which is typically at the time the
assets are installed or acquired. Amounts recorded for the related assets are
increased by the amount of these obligations. Over time, the liabilities will be
accreted for the change in their present value and the initial capitalized costs
will be depreciated over the useful lives
36
of the related assets. The liabilities are eventually extinguished when the
asset is taken out of service.
In our CO2 business segment, we are required to plug and abandon oil and gas
wells that have been removed from service and to remove our surface wellhead
equipment and compressors. As of June 30, 2005, we have recognized asset
retirement obligations in the aggregate amounts of $35.6 million relating to
these requirements at existing sites within our CO2 business segment.
In our Natural Gas Pipelines business segment, if we were to cease providing
utility services, we would be required to remove surface facilities from land
belonging to our customers and others. Our Texas intrastate natural gas pipeline
group has various condensate drip tanks and separators located throughout its
natural gas pipeline systems, as well as inactive gas processing plants,
laterals and gathering systems which are no longer integral to the overall
mainline transmission systems, and asbestos-coated underground pipe which is
being abandoned and retired. Our Kinder Morgan Interstate Gas Transmission
system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of June 30, 2005, we have recognized asset
retirement obligations in the aggregate amounts of $2.4 million relating to the
businesses within our Natural Gas Pipelines business segment.
We have included $0.8 million of our total asset retirement obligations as of
June 30, 2005 with "Accrued other current liabilities" in our accompanying
consolidated balance sheet. The remaining $37.2 million obligation is reported
separately as a non-current liability. No assets are legally restricted for
purposes of settling our asset retirement obligations. A reconciliation of the
beginning and ending aggregate carrying amount of our asset retirement
obligations for each of the six months ended June 30, 2005 and 2004 is as
follows (in thousands):
Six Months Ended June 30,
--------------------------------
2005 2004
----------- ------------
Balance at beginning of period........... $ 38,274 $ 35,708
Liabilities incurred................... 521 130
Liabilities settled.................... (1,197) (307)
Accretion expense...................... 962 1,038
Revisions in estimated cash flows...... (522) -
----------- -------------
Balance at end of period................. $ 38,038 $ 36,569
=========== =============
5. Distributions
On May 13, 2005, we paid a cash distribution of $0.76 per unit to our common
unitholders and our Class B unitholders for the quarterly period ended March 31,
2005. KMR, our sole i-unitholder, received 963,495 additional i-units based on
the $0.76 cash distribution per common unit. The distributions were declared on
April 20, 2005, payable to unitholders of record as of April 29, 2005.
On July 20, 2005, we declared a cash distribution of $0.78 per unit for the
quarterly period ended June 30, 2005. The distribution will be paid on August
12, 2005, to unitholders of record as of July 29, 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 $0.78 distribution per common unit.
The number of i-units distributed will be 909,009. For each outstanding i-unit
that KMR holds, a fraction of an i-unit (0.016210) will be issued. The fraction
was determined by dividing:
o $0.78, the cash amount distributed per common unit
by
o $48.117, the average of KMR's limited liability shares' closing market
prices from July 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.
37
6. Intangibles
Our intangible assets include goodwill, lease value, contracts and agreements.
All of our intangible assets having definite lives are being amortized on a
straight-line basis over their estimated useful lives. Following is information
related to our intangible assets still subject to amortization and our goodwill
(in thousands):
June 30, December 31,
2005 2004
------------- -------------
Goodwill
Gross carrying amount......... $ 769,779 $ 746,980
Accumulated amortization...... (14,142) (14,142)
------------- -------------
Net carrying amount........... 755,637 732,838
------------- -------------
Lease value
Gross carrying amount......... 6,592 6,592
Accumulated amortization...... (1,099) (1,028)
------------- -------------
Net carrying amount........... 5,493 5,564
------------- -------------
Contracts and other
Gross carrying amount......... 196,880 10,775
Accumulated amortization...... (1,886) (1,055)
------------- -------------
Net carrying amount........... 194,994 9,720
------------- -------------
Total intangibles, net.......... $ 956,124 $ 748,122
============= =============
Changes in the carrying amount of goodwill for the six months ended June 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 adjs... 13,088 - - 9,711 22,799
Disposals.............................. - - - - -
Impairments............................ - - - - -
------------- ------------- ------------- ------------- -------------
Balance as of June 30, 2005.............. $ 276,270 $ 250,318 $ 46,101 $ 182,948 $ 755,637
============= ============= ============= ============= =============
Amortization expense on our intangibles consisted of the following (in
thousands):
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2005 2004 2005 2004
---- ---- ---- ----
Lease value................ $ 35 $ 34 $ 71 $ 70
Contracts and other........ 501 205 831 330
-------------- -------------- -------------- --------------
Total amortization......... $ 536 $ 239 $ 902 $ 400
============== ============== ============== ==============
As of June 30, 2005, our weighted average amortization period for our
intangible assets was approximately 24.6 years. Our estimated amortization
expense for these assets for each of the next five fiscal years is approximately
$9.2 million, $9.0 million, $9.0 million, $8.8 million and $8.7 million,
respectively.
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 of businesses we acquired, 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. As of both June 30, 2005
and December 31, 2004, we have reported $150.3 million in equity method goodwill
within the caption "Investments" in our accompanying consolidated balance
sheets.
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7. Debt
Our outstanding short-term debt as of June 30, 2005 was $646.8 million. The
balance consisted of:
- $643 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); 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 June 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 5.135% during the second quarter of 2005 and 4.742% during the
second quarter of 2004.
Credit Facility
As of June 30, 2005, we had a $1.25 billion five-year, unsecured revolving
credit facility due August 18, 2009. Similar to our previous credit facilities,
our current credit facility is with a syndicate of financial institutions and
Wachovia Bank, National Association is the administrative agent. There were no
borrowings under our five-year credit facility as of June 30, 2005 or as of
December 31, 2004.
The amount available for borrowing under our credit facility as of June 30,
2005 was reduced by:
- our outstanding commercial paper borrowings ($643 million as of June 30,
2005);
- a combined $448 million in three letters of credit that support our
hedging of commodity price risks involved from 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
- $1.5 million of other letters of credit supporting other obligations of
us and our subsidiaries.
Interest Rate Swaps
Information on our interest rate swaps is contained in Note 10.
Commercial Paper Program
As of both June 30, 2005 and December 31, 2004, our commercial paper
program provided for the issuance of up to $1.25 billion of commercial paper. As
of June 30, 2005, we had $643 million of commercial paper outstanding with an
average interest rate of 3.1491%. Borrowings under our commercial paper program
reduce the borrowings allowed under our credit facility.
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.
39
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.
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 June 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
40
- a $125 million five-year committed revolving credit facility due
December 22, 2009 (to support the above-mentioned $125 million
commercial paper program).
As of June 30, 2005, Cortez Capital Corporation had $108.9 million of
commercial paper outstanding with an average interest rate of 3.1379%, the
average interest rate on the Series D notes was 7.14%, and there were no
borrowings under the credit facility.
Red Cedar Gas Gathering Company Debt
In October 1998, Red Cedar Gas Gathering Company sold $55 million in
aggregate principal amount of Senior Notes due October 31, 2010. The $55 million
was sold in 10 different notes in varying amounts with identical terms.
The Senior Notes are collateralized by a first priority lien on the
ownership interests, including our 49% ownership interest, in Red Cedar Gas
Gathering Company. The Senior Notes are also guaranteed by us and the other
owner of Red Cedar Gas Gathering Company jointly and severally. The principal is
to be repaid in seven equal installments beginning on October 31, 2004 and
ending on October 31, 2010. As of June 30, 2005, $47.1 million in principal
amount of notes were outstanding.
Nassau County, Florida Ocean Highway and Port Authority Debt
Nassau County, Florida Ocean Highway and Port Authority is a political
subdivision of the State of Florida. During 1990, Ocean Highway and Port
Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal
amount of $38.5 million for the purpose of constructing certain port
improvements located in Fernandino Beach, Nassau County, Florida. 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 June 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 June 30, 2005 and December 31, 2004, our partners' capital consisted
of the following limited partner units:
June 30, December 31,
2005 2004
------------ --------------
Common units....................... 148,575,314 147,537,908
Class B units...................... 5,313,400 5,313,400
i-units............................ 56,077,072 54,157,641
---------- ----------
Total limited partner units...... 209,965,786 207,008,949
=========== ===========
41
The total limited partner units represent our limited partners' interest
and an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights.
As of June 30, 2005, our common unit totals consisted of 134,219,579 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 both June 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.
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.
Furthermore, under the terms of our partnership agreement, we agreed that
we will not, except in liquidation, make a distribution on an i-unit other than
in additional i-units or a security that has in all material respects the same
rights and privileges as our i-units. The number of i-units we distribute to KMR
is based upon the amount of cash we distribute to the owners of our common
units. When cash is paid to the holders of our common units, we will issue
additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by
KMR will have 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 963,495 i-units from us on May 13,
2005. These additional i-units distributed were based on the $0.76 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 $0.76 per unit paid on May 13, 2005 for the
first quarter of 2005 required an incentive distribution to our general partner
of $111.1 million. Our distribution of $0.69 per unit paid on May 14, 2004 for
the first quarter of 2004 required an incentive distribution to our general
partner of $90.7 million. The increased incentive distribution to our general
partner paid for the first quarter of 2005 over the distribution paid for the
first 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 second quarter of 2005 of $0.78 per unit
will result in an incentive distribution to our general partner of approximately
$115.7 million. This compares to our distribution of $0.71 per unit and
incentive distribution to our general partner of approximately $94.9 million for
the second quarter of 2004.
42
9. Comprehensive Income
SFAS No. 130, "Accounting for Comprehensive Income," requires that
enterprises report a total for comprehensive income. For the three and six
months ended June 30, 2005, the difference between our net income and our
comprehensive income resulted from unrealized gains or losses on derivatives
utilized for hedging purposes and from foreign currency translation adjustments.
For the three and six months ended June 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):
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------- ----------------------
2005 2004 2005 2004
-------------- ------------ ----------- ---------
Net income............................................................... $ 221,826 $ 195,218 $ 445,447 $ 386,972
Foreign currency translation adjustments ................................ (377) - (604) -
Change in fair value of derivatives used for hedging purposes............ (200,034) (136,012) (756,869) (236,022)
Reclassification of change in fair value of derivatives to net income.... 84,751 47,096 145,671 73,212
---------- ---------- ------- ---------
Comprehensive income................................................... $ 106,166 $ 106,302 $ (166,355) $ 224,162
========== ========== =========== =========
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 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.
43
Specifically, our risk management committee is a separately designated
standing committee comprised of 15executive-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
- 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.
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 $340.8 million of the
Accumulated other comprehensive loss balance of $1,069.1 million as of June 30,
2005 is expected to be reclassified into earnings during the next twelve months.
During the six months ended June 30, 2005 and 2004, we reclassified $145.7
million and $73.2 million, respectively, of Accumulated other comprehensive loss
into earnings. The reclassification of Accumulated other comprehensive loss into
earnings during the six months ended June 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 six 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). In
conjunction with these activities, we are required to place funds in margin
accounts (included with "Restricted deposits" in the accompanying interim
consolidated balance sheet) when the market value of these derivatives with
specific counterparties exceeds established limits, or in conjunction with the
purchase of exchange-traded derivatives.
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 $0.2 million during the second quarter of
2005 and a loss of $0.4 million during the first six months of 2005 as a result
of ineffective hedges, and we recognized no gain or loss during the second
quarter or the first six 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
six months ended June 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
44
associated with our commodity market risk management activities and included on
our accompanying consolidated balance sheets as of June 30, 2005 and December
31, 2004 (in thousands):
June 30, December 31,
2005 2004
------------ ---------------
Derivatives-net asset/(liability)
Other current assets............................. $ 84,542 $ 41,010
Deferred charges and other assets................ 70,351 17,408
Accrued other current liabilities................ (432,597) (218,967)
Other long-term liabilities and deferred credits. $ (807,497) $ (309,035)
As of June 30, 2005, we had three outstanding letters of credit totaling
$448 million in support of our hedging of commodity price risks involved from
the sale of natural gas, natural gas liquids, crude oil and carbon dioxide
Our over-the-counter swaps and options are with a number of parties, who
principally have investment grade credit ratings. We both owe money and are owed
money under these financial instruments; however, as of both June 30, 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
June 30, 2005 and December 31, 2004, we were a party to interest rate swap
agreements with notional principal amounts of $2.2 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 June 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
45
- $100 million principal amount of our 5.80% senior notes due March 15,
2035.
These swap agreements have termination dates that correspond to the
maturity dates of the related series of senior notes, therefore, as of June 30,
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 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 both June 30, 2005 and December 31, 2004, we also had swap agreements
that effectively convert the interest expense associated with $100 million of
our variable rate debt to fixed rate debt. Half of these agreements, converting
$50 million of our variable rate debt to fixed rate debt, mature on August 1,
2005, and the remaining half mature on September 1, 2005. These swaps are
designated as a cash flow hedge of the risk associated with changes in the
designated benchmark interest rate (in this case, one-month LIBOR) related to
forecasted payments associated with interest on an aggregate of $100 million of
our portfolio of commercial paper.
Our interest rate swaps meet the conditions required to assume no
ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed for fair value hedges by SFAS No. 133.
Accordingly, we adjust the carrying value of each swap to its fair value each
quarter, with an offsetting entry to adjust the carrying value of the debt
securities whose fair value is being hedged. We record interest expense equal to
the variable rate payments or fixed rate payments under the swaps. Interest
expense is accrued monthly and paid semi-annually.
The differences between fair value and the original carrying value
associated with our interest rate swap agreements are included within "Deferred
charges and other assets" and "Other long-term liabilities and deferred credits"
in our accompanying consolidated balance sheets. The offsetting entry to adjust
the carrying value of the debt securities whose fair value was being hedged is
recognized as "Market value of interest rate swaps" on our accompanying
consolidated balance sheets.
The following table summarizes the net fair value of our interest rate swap
agreements associated with our interest rate risk management activities and
included on our accompanying consolidated balance sheets as of June 30, 2005 and
December 31, 2004 (in thousands):
June 30, December 31,
2005 2004
------------ ---------------
Derivatives-net asset/(liability)
Deferred charges and other assets................ $ 214,604 $ 132,210
Other long-term liabilities and deferred credits. (525) (2,057)
------------ -----------
Market value of interest rate swaps............ $ 214,079 $ 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.
46
11. Reportable Segments
We divide our operations into four reportable business segments:
- Products Pipelines;
- Natural Gas Pipelines;
- 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 June 30, Six Months Ended June 30,
------------------------------ ---------------------------
2005 2004 2005 2004
-------------- -------------- ------------ -----------
Revenues
Products Pipelines.......................................... $ 174,632 $ 159,464 $ 345,915 $ 314,320
Natural Gas Pipelines....................................... 1,616,657 1,554,831 3,089,549 2,992,739
CO2......................................................... 162,029 110,572 325,192 216,158
Terminals................................................... 173,037 132,315 337,631 256,221
-------------- -------------- ----------- -----------
Total consolidated revenues................................. $ 2,126,355 $ 1,957,182 $ 4,098,287 $ 3,779,438
============== ============== =========== ===========
Operating expenses(a)
Products Pipelines.......................................... $ 57,070 $ 46,425 $ 109,126 $ 89,303
Natural Gas Pipelines....................................... 1,509,692 1,463,867 2,866,787 2,803,827
CO2......................................................... 54,334 41,904 103,843 80,289
Terminals................................................... 91,736 64,287 177,152 124,393
------------- -------------- ------------ -----------
Total consolidated operating expenses....................... $ 1,712,832 $ 1,616,483 $ 3,256,908 $ 3,097,812
============= ============== ============ ===========
Depreciation, depletion and amortization
Products Pipelines.......................................... $ 19,828 $ 17,384 $ 39,222 $ 34,800
Natural Gas Pipelines....................................... 15,816 12,926 30,574 25,768
CO2......................................................... 38,462 29,130 77,164 56,118
Terminals................................................... 14,155 10,438 26,328 20,723
------------- -------------- ------------ -----------
Total consol. depreciation, depletion and amortization...... $ 88,261 $ 69,878 $ 173,288 $ 137,409
============= ============== ============ ===========
Earnings from equity investments
Products Pipelines.......................................... $ 7,065 $ 8,933 $ 15,450 $ 13,952
Natural Gas Pipelines....................................... 8,598 4,311 17,028 9,278
CO2......................................................... 7,151 7,362 16,399 17,841
Terminals................................................... 24 3 33 7
------------- -------------- ------------ -----------
Total consolidated equity earnings.......................... $ 22,838 $ 20,609 48,910 41,078
============= ============== ============ ===========
Three Months Ended June 30, Six Months Ended June 30,
------------------------------ ---------------------------
2005 2004 2005 2004
-------------- -------------- ----------- -----------
Amortization of excess cost of equity investments
Products Pipelines.......................................... $ 836 $ 821 $ 1,680 $ 1,642
Natural Gas Pipelines....................................... 69 69 138 138
CO2......................................................... 504 504 1,008 1,008
Terminals................................................... - - - -
------------- -------------- ----------- -----------
Total consol. amortization of excess cost of investments.... $ 1,409 $ 1,394 $ 2,826 $ 2,788
============= ============== ============ ===========
Interest income
Products Pipelines.......................................... $ 1,149 $ - $ 2,298 $ -
Natural Gas Pipelines....................................... 166 - 337 -
CO2......................................................... - - - -
Terminals................................................... - - - -
------------- -------------- ------------ -----------
Total segment interest income............................... 1,315 - 2,635 -
Unallocated interest income................................. 93 201 265 477
------------- -------------- ------------ -----------
Total consolidated interest income.......................... $ 1,408 $ 201 $ 2,900 $ 477
============= ============== ============ ===========
Other, net - income (expense)
Products Pipelines.......................................... $ 223 $ 1,127 $ 365 $ 765
Natural Gas Pipelines....................................... 396 (4) 142 1,126
CO2......................................................... (1) 23 - 32
Terminals................................................... 31 (211) (1,179) (245)
------------- -------------- ------------ -----------
Total segment other, net - income (expense)................. 649 935 (672) 1,678
Loss from early extinguishment of debt...................... - (1,424) - (1,424)
------------- -------------- ------------ -----------
Total consolidated Other, net - income (expense)............ $ 649 $ (489) $ (672) $ 254
============= ============== ============ ============
Income tax benefit (expense)
Products Pipelines.......................................... $ (2,737) $ (3,803) $ (6,038) $ (6,184)
Natural Gas Pipelines....................................... (1,081) 167 (1,538) (773)
CO2......................................................... (67) (61) (112) (47)
Terminals................................................... (3,730) (2,121) (7,502) (2,718)
-------------- -------------- ------------ -----------
Total consolidated income tax benefit (expense)............. $ (7,615) $ (5,818) $ (15,190) $ (9,722)
============== ============== ============ ============
Segment earnings
Products Pipelines.......................................... $ 102,598 $ 101,091 $ 207,962 $ 197,108
Natural Gas Pipelines....................................... 99,159 82,443 208,019 172,637
CO2......................................................... 75,812 46,358 159,464 96,569
Terminals................................................... 63,471 55,261 125,503 108,149
------------- -------------- ------------ -----------
Total segment earnings(b)................................... 341,040 285,153 700,948 574,463
Interest and corporate administrative expenses(c)........... (119,214) (89,935) (255,501) (187,491)
------------- -------------- ------------ -----------
Total consolidated net income............................... $ 221,826 $ 195,218 $ 445,447 $ 386,972
============= ============== ============ ===========
Segment earnings before depreciation, depletion, amortization
And amortization
of excess cost of equity investments(d)
Products Pipelines.......................................... $ 123,262 $ 119,296 $ 248,864 $ 233,550
Natural Gas Pipelines....................................... 115,044 95,438 238,731 198,543
CO2......................................................... 114,778 75,992 237,636 153,695
Terminals................................................... 77,626 65,699 151,831 128,872
------------- ------------- ------------ -----------
Total segment earnings before DD&A.......................... 430,710 356,425 877,062 714,660
Total consol. depreciation, depletion and amortization...... (88,261) (69,878) (173,288) (137,409)
Total consol. amortization of excess cost of investments.... (1,409) (1,394) (2,826) (2,788)
Interest and corporate administrative expenses.............. (119,214) (89,935) (255,501) (187,491)
------------- ------------- ------------ -----------
Total consolidated net income .............................. $ 221,826 $ 195,218 $ 445,447 $ 386,972
============= ============= ============ ===========
Capital expenditures
Products Pipelines.......................................... $ 56,647 $ 35,951 $ 97,717 $ 66,962
Natural Gas Pipelines....................................... 23,488 36,251 33,147 54,073
CO2......................................................... 74,385 82,492 126,942 159,207
Terminals................................................... 43,281 35,113 83,803 59,283
------------- ------------- ------------- -----------
Total consolidated capital expenditures(e).................. $ 197,801 $ 189,807 $ 341,609 $ 339,525
============= ============= ============ ===========
48
June 30, December 31,
2005 2004
------------ -------------
Assets
Products Pipelines................................... $ 3,715,926 $ 3,651,657
Natural Gas Pipelines................................ 3,713,066 3,691,457
CO2.................................................. 1,686,519 1,527,810
Terminals............................................ 1,902,312 1,576,333
------------ -------------
Total segment assets................................. 11,017,823 10,447,257
Corporate assets(f).................................. 253,182 105,685
------------ -------------
Total consolidated assets............................ $ 11,271,005 $ 10,552,942
============ =============
(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 and minority interest expense.
(d) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses.
(e) Includes sustaining capital expenditures of $28,747 and $25,939 for the
three months ended June 30, 2005 and 2004 respectively, and includes
sustaining capital expenditures of $52,956 and $46,094 for the six months
ended June 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 June 30, 2005 and 2004, we
reported (in thousands) total consolidated interest expense of $66,720 and
$46,793, respectively. For the six months ended June 30, 2005 and 2004, we
reported (in thousands) total consolidated interest expense of $126,939 and
$94,290, 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 June 30, Six Months Ended June 30,
--------------------------- ---------------------------
2005 2004 2005 2004
----------- -------------- ------------ -------------
Net periodic benefit cost
Service cost............................ $ 2 $ 28 $ 4 $ 56
Interest cost........................... 77 97 154 194
Expected return on plan assets.......... -- -- -- --
Amortization of prior service cost...... (29) (31) (58) (62)
Actuarial gain.......................... (127) (244) (254) (488)
----- ------ ------ ------
Net periodic benefit cost............... $ (77) $(150) $(154) $(300)
====== ====== ====== ======
49
Our net periodic benefit cost for each of the first two 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.
As of June 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 June 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 June 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 June 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 Gas Gathering Company
We own a 49% equity interest in the Red Cedar Gas 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. However, as of April 1, 2005, through July 1, 2005, the maximum
outstanding principal amount will be 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
50
loaned Red Cedar approximately $2.0 million, which corresponds 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.
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 accrued for the cost of insurance which is
included in the related party accounts.
14. 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 immediate effect on our consolidated financial
statements.
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
51
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.
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.
52
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
considered 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 six months ended June 30, 2005.
Results of Operations
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2005 2004 2005 2004
---- ---- ---- ----
(In thousands)
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments
Products Pipelines.......................................... $ 123,262 $ 119,296 $ 248,864 $ 233,550
Natural Gas Pipelines....................................... 115,044 95,438 238,731 198,543
CO2......................................................... 114,778 75,992 237,636 153,695
Terminals................................................... 77,626 65,699 151,831 128,872
----------- ----------- ---------- ---------
Segment earnings before depreciation, depletion and
amortization expense and amortization of excess cost of
equity investments(a)....................................... 430,710 356,425 877,062 714,660
Depreciation, depletion and amortization expense.............. (88,261) (69,878) (173,288) (137,409)
Amortization of excess cost of equity investments............. (1,409) (1,394) (2,826) (2,788)
Interest and corporate administrative expenses(b)............. (119,214) (89,935) (255,501) (187,491)
----------- ----------- ----------- ----------
Net income.................................................... $ 221,826 $ 195,218 $ 445,447 $ 386,972
=========== =========== =========== ==========
_______
(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).
Consolidated net income in the second quarter of 2005 was $221.8 million
($0.50 per diluted unit), compared to $195.2 million ($0.51 per diluted unit) in
the second quarter of 2004. For the six months ended June 30, 2005, our
consolidated net income was $445.4 million ($1.04 per diluted unit), compared to
$387.0 million ($1.03 per diluted
53
unit) for the first six months of 2004. We earned total revenues of $2,126.4
million and $1,957.2 million, respectively, in the three month periods ended
June 30, 2005 and 2004, and revenues of $4,098.3 million and $3,779.4 million,
respectively, in the six month periods ended June 30, 2005 and 2004.
Throughout the first half of 2005, we have continued to follow our
strategies of providing fee-based transportation, storage and handling services
to growing energy markets, increasing crude oil production from our interests in
oil field reserves, and enlarging our business portfolio through both strategic
acquisitions and internal expansions. The period-to-period increases in our net
income and diluted earnings per unit for the first half of 2005 were primarily
due to:
- higher earnings from our oil and gas producing activities, resulting from
higher crude oil and gas plant liquids production volumes, and from
higher industry price levels for both crude oil and natural gas
processing plant liquid products;
- improved performance from the sales of natural gas, favorable cashouts of
natural gas pipeline imbalances, 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 second 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
segments, and in both the second quarter and first six 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.
We declared a cash distribution of $0.78 per unit for the second quarter of
2005 (an annualized rate of $3.12). This distribution is approximately 10%
higher than the $0.71 per unit distribution we made for the second 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.
Products Pipelines
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2005 2004 2005 2004
---- ---- ---- ----
(In thousands, except operating statistics)
Revenues............................................................. $ 174,632 $ 159,464 $ 345,915 $ 314,320
Operating expenses(a)................................................ (57,070) (46,425) (109,126) (89,303)
Earnings from equity investments..................................... 7,065 8,933 15,450 13,952
Interest income and Other, net-income (expense)...................... 1,372 1,127 2,663 765
Income taxes......................................................... (2,737) (3,803) (6,038) (6,184)
--------- ---------- --------- ---------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments.... 123,262 119,296 248,864 233,550
Depreciation, depletion and amortization expense..................... (19,828) (17,384) (39,222) (34,800)
Amortization of excess cost of equity investments.................... (836) (821) (1,680) (1,642)
--------- ----------- --------- ---------
Segment earnings................................................... $ 102,598 $ 101,091 $ 207,962 $ 197,108
========= =========== ========= =========
Gasoline (MMBbl)..................................................... 118.0 117.1 226.9 226.6
Diesel fuel (MMBbl).................................................. 40.8 40.9 81.0 79.2
Jet fuel (MMBbl)..................................................... 29.4 29.2 58.8 58.0
--------- ---------- --------- ---------
Total refined product volumes (MMBbl).............................. 188.2 187.2 366.7 363.8
Natural gas liquids (MMBbl).......................................... 8.0 9.4 17.6 20.9
--------- ---------- --------- ---------
Total delivery volumes (MMBbl)(b).................................. 196.2 196.6 384.3 384.7
========= ========== ========= =========
54
__________
(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 $123.3 million on revenues of $174.6 million in
the second quarter of 2005. This compares to earnings before depreciation,
depletion and amortization of $119.3 million on revenues of $159.5 million in
the second quarter of 2004. For the comparable six month periods, the segment
reported earnings before depreciation, depletion and amortization of $248.9
million on revenues of $345.9 million in 2005, and earnings before depreciation,
depletion and amortization of $233.6 million on revenues of $314.3 million in
2004.
The segment's overall $4.0 million (3%) increase in earnings before
depreciation, depletion and amortization in the second quarter of 2005 versus
the second quarter of 2004 included a $4.9 million increase in earnings before
depreciation, depletion and amortization from our Southeast product terminal
operations, including incremental earnings of $3.3 million from the refined
product terminal operations we acquired in November 2004 from Charter Terminal
Company and Charter-Triad Terminals, LLC. We also reported a quarter-to-quarter
increase of $2.0 million (3%) from the combined operations of our Pacific and
CALNEV Pipeline operations, a $0.6 million (23%) increase from our North System
natural gas liquids pipeline, and a $0.4 million (5%) increase from our Central
Florida Pipeline operations. The $1.6 million (46%) quarter-to-quarter increase
in earnings before depreciation, depletion and amortization from the Southeast
terminals owned during both quarters was largely due to higher product storage
revenues. The increase from our Pacific and CALNEV operations, which together
consist of seven pipeline segments that serve six western states with
approximately 3,100 miles of refined petroleum products pipelines and related
terminal facilities, was mainly due to higher product delivery revenues and
higher product terminal revenues. The quarter-to-quarter increase from our North
System was due to higher throughput delivery revenues, driven primarily by a
greater average tariff resulting from a higher ratio of long haul shipments to
shorter haul shipments and, to a lesser extent, higher published tariff rates
that were approved by the Federal Energy Regulatory Commission and became
effective April 1, 2005. The increase in earnings from our Central Florida
Pipeline was mainly due to higher product delivery revenues resulting from an
overall 9% increase in throughput delivery volumes.
The segment's overall $15.3 million (7%) increase in earnings before
depreciation, depletion and amortization in the first six months of 2005 versus
the first six months of 2004 included a $10.4 million increase from our
Southeast product terminal operations, including incremental earnings of $9.8
million from the combined terminal operations we acquired from Charter in
November 2004 and from Exxon Mobil Corporation in March 2004. We also reported
a $5.7 million (5%) increase from our Pacific operations and a $3.2 million
(19%) increase attributable to our 51% ownership interest in Plantation Pipe
Line Company.
The increase in earnings before depreciation, depletion and amortization
expenses for the comparative six month periods from our Pacific operations was
largely related to an $11.2 million (7%) increase in operating revenues, driven
by both higher mainline delivery revenues and higher product terminal revenues.
The period-to-period increase from Plantation was due to the recognition, in
2005, of incremental interest income on our long-term note receivable from
Plantation, and an increase in equity earnings due to higher income earned by
Plantation as a result of both higher pipeline delivery revenues in the first
half of 2005 and higher litigation settlement expenses incurred in the first
half of 2004.
The overall increase in segment earnings before depreciation, depletion and
amortization in both the comparable three and six month periods were partly
offset by year-over-year decreases from our petroleum pipeline transmix
processing operations and West Coast product terminals. For the comparable
second quarter periods, we reported a $2.4 million (32%) decrease in earnings
before depreciation, depletion and amortization from our transmix processing
operations and a $1.0 million (10%) decrease from our West Coast terminals. For
the comparable six month periods, our transmix and West Coast terminal
operations reported decreases of $2.4 million (18%) and $1.2 million (6%),
respectively, in 2005 versus 2004. The quarterly and year-to-date decreases from
our transmix operations were due to both lower revenues, resulting from an
almost 11% decrease in processing volumes, and lower other income, due to a $0.9
million benefit taken from the write-off of certain short-term liabilities in
the second quarter of 2004. The quarterly and year-to-date decreases from our
West Coast product terminal operations were due to both higher property tax
expenses in 2005, due to expense reversals taken in the second quarter of 2004
55
pursuant to favorable property reassessments, and to lower product revenues
resulting from the fourth quarter 2004 closure of our Gaffey Street product
terminal located in San Pedro, California.
Revenues for the segment increased $15.1 million (9%) in the second quarter
of 2005 compared to the second quarter of 2004. For the comparable six month
periods, revenues increased $31.6 million (10%) in 2005 versus 2004. The
quarter-to-quarter increase in segment revenues included incremental revenues of
$7.5 million from our Southeast terminals, including $6.1 million attributable
to the Charter terminals we acquired since the end of the second quarter of
2004. The remaining $1.4 million increase was largely attributable to higher
product storage revenues at the terminals we acquired in March 2004 from
ExxonMobil, with the strongest growth coming from our Newington, Virginia and
Collins, Mississippi terminals. The increase in segment revenues between the
comparable six month periods included a $19.6 million increase from our
Southeast terminals, including $19.1 million of incremental revenues from the
terminals acquired since March 2004.
The overall increases in revenues for the three and six month periods ended
June 30, 2005, compared to the prior year, also included increases of $6.4
million (8%) and $11.2 million (7%), respectively, from our Pacific operations,
and increases of $1.4 million (11%) and $1.6 million (6%), respectively, from
our CALNEV Pipeline. Pacific's period-to-period increases in revenues were
driven by increases of $4.7 million (8%) and $8.6 million (7%), respectively, in
mainline delivery revenues, due to both higher delivery volumes and higher
average tariff rates, and by higher product terminal revenues. The
period-to-period increases in CALNEV's revenues were due to higher terminal
revenues and to higher product delivery revenues resulting from increases of 4%
and 2%, respectively, in product delivery volumes in the second quarter and
first six months of 2005, when compared to the same periods of 2004. Combined,
our Pacific and CALNEV businesses operate 15 truck-loading terminals that
provide services to customers such as product storage and truck-loading, vapor
handling, and injection and blending services.
We also benefited from a quarter-to-quarter revenue increase of $1.2
million (18%) from our North System, due primarily to a greater average tariff
resulting from a higher ratio of long haul shipments to shorter haul shipments
and, to a lesser degree, higher published tariff rates that became effective on
April 1, 2005. The new rates were associated with a cost of service filing that
was approved by the FERC. Revenues from our Central Florida Pipeline increased
$1.5 million (8%) in the first half of 2005 compared to the first half of 2004.
The increase was due to a 10% increase in delivery volumes. For the second
quarter of 2005, total delivery volumes of refined products were up 0.5%
compared to the second quarter of 2004 with increases on Pacific, Central
Florida and CALNEV largely offset by a decrease on Plantation. Although jet and
diesel fuel delivery volumes were essentially unchanged quarter-over-quarter,
overall segment gasoline volumes were up almost 0.8% in 2005 versus 2004,
largely due to Central Florida. Deliveries of natural gas liquids were down
about 15% due to low demand for propane on the North System, and Cypress
Pipeline, but revenues were up over 4% due to higher tariffs.
The segment's operating expenses increased $10.6 million (23%) in the
second quarter of 2005, compared to the second quarter of 2004, and increased
$19.8 million (22%) in the first six months of 2005, compared to the first six
months of 2004. The quarter-to-quarter increase in operating expenses included
increases of $2.7 million from the Southeast terminal operations we acquired in
November 2004, $5.2 million (27%) from our Pacific operations, largely due to
higher overall repair, maintenance and labor expenses associated with line
wash-outs, repairs and environmental issues, and $1.0 million (26%) from our
West Coast terminals, largely due to higher property tax expenses in 2005
relative to 2004, as discussed above. The overall increase in segment operating
expenses from the comparative six month periods included incremental expenses of
$9.2 million from the Southeast terminal operations we acquired since March
2004, $6.8 million (16%) from our combined Pacific and CALNEV Pipeline
operations, $1.3 million (20%) from our 49.8% proportionate interest in the
Cochin Pipeline, and $1.0 million (11%) from our North System. The increase from
our Pacific and CALNEV operations were mainly due to additional maintenance and
clean-up work resulting from adverse weather in the State of California in the
first quarter of 2005. The increase from the Cochin Pipeline was primarily due
to higher labor and outside services associated with additional health, safety
and security work, and the increase in operating expenses from our North System
was mainly due to higher storage expenses related to a new contract agreement
entered into in April 2004.
In the second quarter of 2005, the segment's earnings from equity
investments decreased $1.9 million (21%) from the equity earnings reported in
the second quarter of 2004. The decrease was primarily due to a $1.8 million
(20%) decrease in equity earnings from our 51% ownership interest in Plantation
Pipe Line Company. The decrease was due to lower quarterly net income earned by
Plantation, primarily due to write-offs taken in the second quarter
56
of 2005, associated with projects and developmental work, and to higher interest
expense associated with Plantation's long-term note payable to us (as discussed
below). However, when taking into account the incremental interest income that
we earned from the related-party note, and the favorable changes in our periodic
income tax expense related to Plantation's lower net income, quarter-to-quarter
earnings before depreciation, depletion and amortization from our investment in
Plantation increased $0.2 million (2%) in 2005 versus 2004. For the comparative
six month periods, equity earnings increased $1.5 million (11%) in 2005 versus
2004, reflecting a $1.2 million (9%) increase related to our investment in
Plantation and a $0.3 million (67%) increase related to our 50% ownership
interest in the Heartland Pipeline Company. Both increases were due to higher
year-to-date income in 2005; for Plantation, the increase was due to higher
litigation settlement expenses incurred in the first quarter of 2004, related to
the resolution of a past environmental issue, and for Heartland, the increase
was primarily due to higher pipeline delivery volumes in 2005.
The segment's income from allocable interest income and other income and
expense items was essentially flat across both second quarter periods. For the
comparative six month periods, income from interest and other items increased
$1.9 million in 2005 versus 2004. The increase included incremental interest
earnings of $2.3 million from our long-term note receivable from Plantation Pipe
Line Company. 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 overall increase in income from
interest and other items in the first half of 2005 versus the first half of 2004
was partly offset by a $0.8 million period-to-period decrease in other income
from our transmix operations, due to the write-off of a $0.9 million account
payable in April 2004.
The segment's income tax expenses decreased $1.1 million (28%) in the
second quarter of 2005 compared to the second quarter of 2004, but were
essentially unchanged over the first six month period of each year. The decrease
in income taxes in the comparable three month periods was due to lower pre-tax
earnings realized by Plantation and the Cochin pipeline systems in the second
quarter of 2005.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of equity investments, increased $2.5 million (14%)
in the second quarter of 2005, and $4.5 million (12%) in the first six 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,
related to higher depreciable costs as a result of the capital spending we have
made since the end of the second quarter of 2004, and to the inclusion of
additional depreciation charges on the Southeast terminal assets that we
acquired in November 2004.
Natural Gas Pipelines
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- ------------------
2005 2004 2005 2004
---- ----- ---- ----
(In thousands, except operating statistics)
Revenues............................................................. $ 1,616,657 $ 1,554,831 $ 3,089,549 $ 2,992,739
Operating expenses(a)................................................ (1,509,692) (1,463,867) (2,866,787) (2,803,827)
Earnings from equity investments..................................... 8,598 4,311 17,028 9,278
Interest income and Other, net-income (expense)...................... 562 (4) 479 1,126
Income taxes......................................................... (1,081) 167 (1,538) (773)
------------ ------------- ------------ ------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments....... 115,044 95,438 238,731 198,543
Depreciation, depletion and amortization expense..................... (15,816) (12,926) (30,574) (25,768)
Amortization of excess cost of equity investments.................... (69) (69) (138) (138)
------------ ------------- ------------ ------------
Segment earnings................................................... $ 99,159 $ 82,443 $ 208,019 $ 172,637
============ ============ ============ ============
Natural gas transport volumes (Trillion Btus)(b)..................... 307.1 316.5 645.1 645.7
============ ============ ============ ============
Natural gas sales volumes (Trillion Btus)(c)......................... 222.7 242.8 449.3 487.9
============ ============ ============ ============
__________
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
(b) Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate
natural gas pipeline group, Trailblazer and
57
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 $115.0 million on revenues of
$1,616.7 million in the second quarter of 2005. This compares to earnings before
depreciation, depletion and amortization of $95.4 million on revenues of
$1,554.8 million in the second quarter of 2004. For the six month periods ended
June 30, 2005 and 2004, the segment reported earnings before depreciation,
depletion and amortization of $238.7 million and $198.5 million, respectively,
and revenues of $3,089.5 million and $2,992.7 million, respectively.
The segment's $19.6 million (21%) increase in earnings before depreciation,
depletion and amortization expenses in the second quarter of 2005 compared to
the second quarter of 2004 included incremental earnings before depreciation,
depletion and amortization expenses of $9.4 million from our TransColorado
Pipeline, a 300-mile interstate natural gas pipeline system that extends from
the Western Slope of Colorado to the Blanco natural gas hub in northwestern New
Mexico. We acquired the TransColorado Pipeline from KMI effective November 1,
2004.
Our Kinder Morgan Interstate Gas Transmission system, which along with our
Trailblazer Pipeline and our TransColorado Pipeline comprise our Rocky Mountain
natural gas pipeline group, reported an $8.8 million (42%) increase in earnings
before depreciation, depletion and amortization expenses in the second quarter
of 2005 compared to the second quarter of 2004. The increase in earnings before
depreciation, depletion and amortization expenses from KMIGT was mainly due to
higher operational sales of natural gas and to imbalance valuation adjustments.
KMIGT's operational gas sales are primarily made possible by its collection of
fuel in-kind pursuant to its transportation tariffs. In addition, we reported
higher equity earnings from our 49% ownership interest in the Red Cedar Gas
Gathering Company. The increase in equity earnings from Red Cedar accounted for
$4.4 million of the quarter-to-quarter increase in segment earnings before
depreciation, depletion and amortization expenses. The increase in earnings
before depreciation, depletion and amortization from Red Cedar was due to higher
quarterly income, primarily resulting from additional 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 segment's overall increase in earnings before depreciation, depletion
and amortization in the second quarter of 2005 compared to the second quarter of
2004 was partially offset by a combined $2.7 million (5%) decrease in earnings
before depreciation, depletion and amortization expenses from our Texas
intrastate natural gas pipeline group, which consists of our Kinder Morgan
Tejas, Kinder Morgan Texas Pipeline, Mier-Monterrey Mexico Pipeline and Kinder
Morgan North Texas Pipeline systems. The decrease in earnings before
depreciation, depletion and amortization from our intrastate group was primarily
due to an 8% decrease in natural gas sales volumes partially offset by higher
margins (defined as the difference between the prices at which we buy gas in our
supply areas and the prices at which we sell gas in our market areas, less the
cost of fuel to transport) in our recurring business.
For the comparable six month periods, the $40.2 million (20%) overall
increase in segment earnings before depreciation, depletion and amortization
expenses in 2005 over 2004 included an increase of $18.0 million from the
inclusion of TransColorado, increases of $8.7 million (20%) and $8.0 million
(125%), respectively, from KMIGT and Red Cedar, due to the same reasons
described above, and an increase of $7.6 million (38%) from our Trailblazer
natural gas pipeline system, mainly due to timing differences on the favorable
settlements of natural gas pipeline imbalances in the first quarter of 2005.
These pipeline imbalances were caused by differences between the volumes
nominated and volumes delivered at an inter-connecting point by the pipeline.
Earnings before depreciation, depletion and amortization from our Texas
intrastate natural gas pipeline group increased $0.3 million in the first half
of 2005, when compared to the first half of last year. The increase was
primarily due to lower operating expenses, reflecting favorable adjustments in
operating lease and pipeline maintenance expenses in 2005 versus 2004.
The segment's overall increase in earnings before depreciation, depletion
and amortization in the first six months of 2005 compared to the first six
months of 2004 was partially offset by a $2.6 million (33%) decrease in earnings
before depreciation, depletion and amortization expenses from our Casper Douglas
natural gas gathering system, primarily due to lower natural gas sale volumes,
caused by higher fuel reimbursement charges that reduced volumes available for
sale.
58
Revenues earned by our Natural Gas Pipelines segment during the second
quarter and first six months of 2005 increased $61.9 million (4%) and $96.8
million (3%), respectively, over comparable periods in the prior year. Our Texas
intrastate natural gas pipeline group accounted for $42.1 million and $72.9
million of the respective periodic increases in segment revenues. The group's
higher revenues were driven by higher natural gas sales revenues earned by our
Kinder Morgan Tejas, Kinder Morgan Texas Pipeline, and Kinder Morgan North Texas
Pipeline systems. The Texas intrastate natural gas pipeline group purchases,
sells, stores and transports for others, significant volumes of natural gas on
Kinder Morgan Tejas and Kinder Morgan Texas Pipeline and combined, the two
systems reported increases in natural gas sales revenues in the second quarter
and first six months of 2005 of $32.1 million (2%) and $66.5 million (2%),
respectively, when compared to the same prior year periods. The increases were
driven by higher average natural gas sales prices during 2005; for the three
month period, average natural gas sales prices increased 12% (from $5.92 per
dekatherm in 2004 to $6.62 per dekatherm in 2005); for the six month period,
average natural gas sales prices increased 11% (from $5.63 per dekatherm in 2004
to $6.27 per dekatherm in 2005). The higher sale prices more than offset the
period-to-period decreases in natural gas sales volumes. The decreases in
natural gas sales volumes were largely due to lower electric generation demand
and to reduced sales to lower margin customers.
The inclusion of the TransColorado Pipeline in our 2005 results accounted
for total revenue increases of $10.7 million and $20.5 million, respectively, in
the second quarter and first six months of 2005. KMIGT, which owns approximately
4,500 miles of natural gas transmission lines and primarily provides gas
transportation and storage services to customers, reported increases in revenues
of $9.4 million (27%) and $5.1 million (7%) for the second quarter and first six
months of 2005, respectively. The increases were driven by higher sales of
natural gas in the second quarter of 2005. Pursuant to its effective interstate
natural gas transportation tariff, KMIGT has authority to make gas purchases and
sales as needed for system operations.
The segment's combined operating expenses increased $45.8 million (3%) in
the second quarter of 2005 compared to the second quarter of 2004. For the
comparable six month periods, operating expenses increased $63.0 million (2%) in
2005 versus 2004. The increases were mainly related to higher natural gas
purchase costs from our Texas intrastate natural gas pipeline group. For the
total group, costs of sales increased $46.1 million (3%) in the second quarter
of 2005 and $73.1 million (3%) in the first half of 2005, when compared to the
same periods of 2004. The increases in natural gas purchase costs, which
represent the expenses incurred under gas purchase contracts used to maintain
pipeline natural gas supply, were caused by higher average commodity prices
during 2005 as a result of continuing strong demand for natural gas across the
State of Texas. However, higher natural gas purchase costs can occur from period
to period without significantly impacting our margins due to the fact that we
sell natural gas in the same price environment in which it is purchased, thereby
offsetting the increases in our gas purchase costs by corresponding increases in
our sales revenues.
The inclusion of the TransColorado Pipeline in our 2005 results accounted
for operating expenses of $1.3 million and $2.6 million, respectively, in the
second quarter and first six months of 2005, and operating expenses from our
Trailblazer pipeline system remained flat quarter-over-quarter, but decreased
$7.9 million in the first six months of 2005 versus the same prior-year period
due mainly to favorable gas imbalance settlements, referred to above, and lower
gas reimbursement expenses.
Earnings from equity investments increased $4.3 million (99%) and $7.8
million (84%), respectively, in the second quarter and first half 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, driven by higher operational gas
sales as a result of lower gas lost.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased $2.9 million (22%) and
$4.8 million (19%), respectively, in the second quarter and first six 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 second quarter of 2004.
59
CO2
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- ------------------
2005 2004 2005 2004
---- ----- ---- ----
(In thousands, except operating statistics)
Revenues............................................................. $ 162,029 $ 110,572 $ 325,192 $ 216,158
Operating expenses(a)................................................ (54,334) (41,904) (103,843) (80,289)
Earnings from equity investments..................................... 7,151 7,362 16,399 17,841
Other, net-income (expense).......................................... (1) 23 - 32
Income taxes......................................................... (67) (61) (112) (47)
----------- ----------- ---------- ------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments.... 114,778 75,992 237,636 153,695
Depreciation, depletion and amortization expense(b).................. (38,462) (29,130) (77,164) (56,118)
Amortization of excess cost of equity investments.................... (504) (504) (1,008) (1,008)
----------- ----------- ---------- ------------
Segment earnings................................................... $ 75,812 $ 46,358 $ 159,464 $ 96,569
=========== =========== ========== ============
Carbon dioxide volumes transported (Bcf)(c).......................... 155.5 138.6 325.4 321.1
=========== =========== ========== ============
SACROC oil production (MBbl/d)(d).................................... 32.5 27.4 33.1 26.7
=========== =========== ========== ============
Yates oil production (MBbl/d)(d)..................................... 24.0 18.6 24.0 18.2
=========== =========== ========== ============
Natural gas liquids sales volumes (MBbl/d)(e)........................ 9.3 7.5 9.5 7.1
=========== =========== ========== ============
Realized weighted average oil price per Bbl(f)(g).................... $ 27.39 $ 25.26 $ 28.10 $ 25.31
=========== =========== ========== ============
Realized weighted average natural gas liquids price per Bbl(g)(h).... $ 35.40 $ 27.60 $ 34.67 $ 27.17
=========== =========== ========== ============
__________
(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 $33,828 for the second quarter of 2005, $25,484 for the second
quarter of 2004, $68,025 for the first six months of 2005 and $48,600 for
the first six months of 2004. Includes depreciation, depletion and
amortization expense associated with sales and transportation services
activities in the amount of $4,634 for the second quarter of 2005, $3,646
for the second quarter of 2004, $9,139 for the first six months of 2005 and
$7,518 for the first six 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.
(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
$114.8 million on revenues of $162.0 million in the second quarter of 2005.
These amounts compare to earnings before depreciation, depletion and
amortization of $76.0 million on revenues of $110.6 million in the same quarter
last year. For the six month periods ended June 30, 2005 and 2004, the segment
reported earnings before depreciation, depletion and amortization of $237.6
million and $153.7 million, respectively, and revenues of $325.2 million and
$216.2 million, respectively.
The year-over-year growth in earnings before depreciation, depletion and
amortization was primarily due to higher earnings from the segment's oil and gas
producing activities, which include the operations associated with its ownership
interests in oil-producing fields and natural gas processing plants. Earnings
before depreciation, depletion and amortization from combined oil and gas
producing activities totaled $72.5 million and $157.6 million, respectively, in
the three and six month periods ended June 30, 2005. These amounts compare to
earnings before depreciation, depletion and amortization of $48.5 million and
$93.6 million, respectively, in the three and six month periods ended June 30,
2004. The period-to-period increases were mainly due to higher revenues from the
sale of crude oil, produced from our interests in seven oil field units located
in the Permian Basin area of West Texas, and
60
the sale of gas plant liquid products, produced from our interests in three
gasoline and gas processing plants also located in the Permian Basin. The
increase in revenues was due to both higher sales prices and higher production
volumes. While sales prices were generally higher for all products, revenues
from crude oil sales increased significantly compared to the 2004 periods
largely due to a rise in production volumes as a result of the infrastructure
expansions and improvements we have made since the second quarter of 2004.
Our CO2 segment's carbon dioxide sales and transportation activities
reported earnings before depreciation, depletion and amortization in the amount
of $42.3 million and $80.0 million, respectively, in the three and six month
periods ended June 30, 2005. These same activities reported earnings before
depreciation, depletion and amortization of $27.5 million and $60.1 million,
respectively, for the three and six month periods ended June 30, 2004. The
period-to-period increases were driven by higher revenues from carbon dioxide
sales, mainly due to higher sales volumes, and by incremental crude oil
transportation revenues, due to the inclusion of our Kinder Morgan Wink
Pipeline, a 450-mile crude oil pipeline system located in West Texas and
acquired effective August 31, 2004. For the second quarter of 2005, the Wink
Pipeline reported earnings before depreciation, depletion and amortization of
$5.1 million on revenues of $6.4 million; for the first six months of 2005, it
reported earnings before depreciation, depletion and amortization of $9.7
million on revenues of $12.2 million.
Revenues earned by our CO2 segment during the second quarter and first six
months of 2005 increased $51.4 million (46%) and $109.0 million (50%),
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 increases
were due to higher average prices, higher production and sales volumes, and the
inclusion of the Wink Pipeline.
Combined daily oil production from the two largest oil field units in which
we hold ownership interests, consisting of our approximate 97% working interest
in the SACROC oil field unit and our approximate 50% working interest in the
Yates oil field unit, increased 23% and 27%, respectively, in the second quarter
and first six months of 2005, as compared to the same periods last year.
Similarly, sales volumes of natural gas liquids increased 24% and 34%,
respectively, in the second quarter and first six months of 2005, when compared
with the same periods of 2004. The volume increases were due to higher product
demand and to the internal capital spending and acquisition expenditures we have
made since the end of the second quarter of 2004.
For the first six months of 2005, capital expenditures for our CO2 business
segment totaled $126.9 million, the highest for all four of our reportable
business segments. The expenditures largely represented incremental spending for
new well and injection compression facilities at the SACROC oil field unit in
order to enhance oil recovery from carbon dioxide injection. Additionally, in
the first quarter of 2005, we spent $6.2 million in cash and assumed $0.3
million in liabilities to acquire an approximate 64.5% gross working interest in
the Claytonville oil field unit, also located in the Permian Basin.
We also benefited from increases of 8% and 28%, respectively, in our
realized weighted average price of oil and natural gas liquids per barrel in the
second quarter of 2005, as compared to the second quarter of 2004. For the
comparable six month periods, our realized weighted average prices of oil and
natural gas liquids per barrel increased 11% and 28%, respectively. 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 this commodity price risk through a long-term
hedging strategy that is intended to generate more stable realized prices.
Our strategy involves the use of financial derivative commodity instruments
to manage this price risk on certain activities, including firm commitments and
anticipated transactions for the sale of crude oil, natural gas liquids and
carbon dioxide. Although the details of hedging can be somewhat complex, our
strategy, as it relates to our oil production business, primarily involves
entering into a forward sale or, in some cases, buying a put option in order to
establish a known price level. In this way, we attempt to protect ourselves
against the risk of an unfavorable price change in the interim. In essence, we
use derivatives to lock in an acceptable margin between our production costs and
our selling price. For more information on our hedging activities, see Note 10
to our consolidated financial statements, included elsewhere in this report.
The segment's combined operating expenses increased $12.4 million (30%) in
the second quarter of 2005 compared to the second quarter of 2004. For the
comparable six-month periods, operating expenses increased $23.6
61
million (29%) in 2005 versus 2004. The increases were mainly related to higher
fuel and power costs, due to increased carbon dioxide compression and equipment
utilization, higher property and production taxes, due to the period-to-period
increases in oil production volumes and the increase in capitalized assets since
the end of the second quarter of 2004, and higher operating and maintenance
expenses, due to additional labor and non-labor expenses related to higher
production volumes.
Earnings from the segment's equity investments represent the earnings from
our 50% investment in the Cortez Pipeline Company, a partnership that owns and
operates an approximate 500-mile common carrier carbon dioxide pipeline system
that extends from Southwest Colorado through New Mexico to certain oil producing
properties in West Texas. For the comparative quarterly periods, equity earnings
from Cortez were essentially flat; for the comparative six month periods, equity
earnings decreased $1.4 million (8%). The decrease reflects lower year-to-date
net income earned by Cortez, primarily due to lower average tariff rates that
more than offset a 7% increase in carbon dioxide transport volumes.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased $9.3 million (31%) and
$21.0 million (37%), respectively, in the second quarter and first six 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 June
2004, and higher unit-of-production depletion charges, related to higher
period-to-period crude oil production.
Terminals
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- ------------------
2005 2004 2005 2004
---- ----- ---- ----
(In thousands, except operating statistics)
Revenues............................................................. $ 173,037 $ 132,315 $ 337,631 $ 256,221
Operating expenses(a)................................................ (91,736) (64,287) (177,152) (124,393)
Earnings from equity investments..................................... 24 3 33 7
Other, net-income (expense).......................................... 31 (211) (1,179) (245)
Income taxes......................................................... (3,730) (2,121) (7,502) (2,718)
----------- ----------- ---------- ------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments.... 77,626 65,699 151,831 128,872
Depreciation, depletion and amortization expense..................... (14,155) (10,438) (26,328) (20,723)
Amortization of excess cost of equity investments.................... - - - -
----------- ------------- ---------- ------------
Segment earnings................................................... $ 63,471 $ 55,261 $ 125,503 $ 108,149
=========== ============= ========== ============
Bulk transload tonnage (MMtons)(b)................................... 21.7 17.1 42.0 34.4
============ ============ ========== ============
Liquids leaseable capacity (MMBbl)................................... 37.3 36.5 37.3 36.5
============ ============ ========== ============
Liquids utilization %................................................ 96.4% 96.0% 96.4% 96.0%
============ ============ ========== ============
__________
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs; excludes operatorship of LAXT bulk terminal. Volumes
for acquired terminals are included for all periods.
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
$77.6 million on revenues of $173.0 million in the second quarter of 2005. This
compares to earnings before depreciation, depletion and amortization of $65.7
million on revenues of $132.3 million in the second quarter last year. For the
comparable six-month periods, our Terminals segment reported earnings before
depreciation, depletion and amortization of $151.8 million on revenues of $337.6
million in 2005, and earnings before depreciation, depletion and amortization of
$128.9 million on revenues of $256.2 million in 2004.
Since the end of the second quarter of 2004, we have invested approximately
$230.6 million in cash and $46.3 million in common units to acquire assets and
business operations included as part of our Terminals segment (excluding
approximately $50 million in terminal acquisitions and improvements subsequent
to June 30, 2005). We consider external acquisitions an important part of our
overall business strategy, and we are increasing the number
62
of terminals in our portfolio in order to gain access to larger markets and to
benefit from the economies of scale resulting from increases in storage,
handling and throughput capacity.
Our terminal acquisitions since the end of the first quarter of 2004
through the second quarter of 2005 have included the following:
- our North Charleston, South Carolina bulk terminal, acquired effective
April 30, 2004;
- 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; and
- our Texas Petcoke terminals, located in and around the Ports of Houston
and Beaumont, Texas, acquired effective April 29, 2005.
The above acquisitions accounted for incremental amounts of earnings before
depreciation, depletion and amortization of $10.7 million, revenues of $29.3
million and operating expenses of $17.4 million, respectively, in the second
quarter of 2005, and incremental amounts of earnings before depreciation,
depletion and amortization of $17.5 million, revenues of $50.7 million and
operating expenses of $30.6 million, respectively, in the first six months of
2005, when compared to the same time periods of 2004.
For all other terminal operations (those owned during both six month
periods), earnings before depreciation, depletion and amortization increased
$1.2 million (2%) in the second quarter of 2005 versus the second quarter of
2004, and increased $5.4 million (4%) in the first half of 2005 versus the first
half of 2004. The increases in earnings before depreciation, depletion and
amortization in the second quarter and first six months of 2005 from terminals
owned during both periods included increases of $2.9 million (18%) and $4.9
million (16%), respectively, from our Gulf Coast terminals, which include our
two liquids terminal facilities located in Pasadena and Galena Park, Texas. The
two terminals serve as a distribution hub for Houston's crude oil refineries,
and the period-to-period increases in earnings before depreciation, depletion
and amortization expenses from these terminals were driven by higher volumes of
liquids throughput at the Houston Ship Channel in the first half of 2005,
largely the result of continued strength in distillate volumes. For the two
terminals combined, total throughput volumes increased 1% in the second quarter
of 2005 versus the second quarter of 2004, and increased 6% in the first six
months of 2005 versus the same year-earlier period.
For our entire liquids terminals combined, total throughput volumes
decreased almost 3% in the second quarter of 2005 versus the second quarter of
2004, due to higher petroleum volumes in the second quarter of 2004; however,
for the comparable six month periods, total liquids volumes increased 1% in 2005
versus 2004. The year-over-year increase was due to higher distillate volumes, a
2% increase in our leaseable capacity, and a slight increase in our capacity
utilization rate. Our liquids terminals utilization rate is the ratio of our
actual output to our estimated potential output. Potential output is generally
derived from measures of total capacity, taking into account periodic changes to
terminal facilities due to additions, disposals, obsolescence, or other factors.
Earnings before depreciation, depletion and amortization expenses from our
Midwest terminal operations increased $1.3 million (16%) and $2.0 million (14%),
respectively, in the second quarter and first half of 2005, when compared to the
same prior year periods. The increases were largely due to higher earnings from
our Dakota bulk terminal, located along the Mississippi River near St. Paul,
Minnesota, and our Pinney Dock bulk terminal, located along Lake Erie in
Ashtabula, Ohio. 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 earnings increases from
Pinney Dock were mainly due to incremental accruals for bad debt expenses taken
in the first quarter of 2004, and to higher prices received for the movement of
iron ore and steel products in 2005.
The overall increase in segment earnings before depreciation, depletion and
amortization expenses in the second quarter of 2005 versus the second quarter of
2004 was partially offset by decreases of $1.4 million (12%) from our
Mid-Atlantic terminals, $1.0 million (8%) from our Northeast terminals, and $0.9
million (35%) from our West
63
region terminals. The decrease in earnings before depreciation, depletion and
amortization from our Mid-Atlantic terminals were primarily due to lower
earnings at our Chesapeake Bay, Maryland bulk terminal, due to higher operating
expenses associated with higher petroleum coke movements, and to lower earnings
at our Grand Rivers, Kentucky coal terminal, due to a 13% decrease in coal
transport volumes. The quarter-to-quarter decrease in earnings before
depreciation, depletion and amortization expenses from our Northeast terminals
was largely due to lower earnings from our liquids terminal facility located in
Carteret, New Jersey, mainly due to lower petroleum volumes handled in the
second quarter of 2005 versus the second quarter of 2004. The decrease in
earnings from our West region terminals was largely due to lower soda ash
tonnage volumes at our bulk terminal facility located in Portland, Oregon.
For the comparable six month periods, the overall increase in segment
earnings before depreciation, depletion and amortization in 2005 versus 2004 was
partially offset by a decrease of $1.5 million (6%) from our Northeast
terminals, largely due to lower earnings at our Port Newark, New Jersey bulk
terminal and our Carteret facility. The decrease at Port Newark was mainly due
to higher operating expenses and the decrease at Carteret was mainly due to
higher utility and fuel expenses in 2005 versus 2004.
Segment revenues for all terminals owned during both six month periods
increased $11.4 million (9%) and $30.7 million (12%), respectively, in the
second quarter and first six months of 2005, when compared to the same
prior-year periods. The overall quarter-to-quarter increase in segment revenues
includes increases of $3.4 million (16%) from our two Gulf Coast terminals, $3.2
million (16%) from our Mid-Atlantic terminals, and $3.1 million (18%) from our
Midwest terminals. The Gulf Coast increase was driven by higher petroleum
transmix revenues at our Pasadena terminal. The Mid-Atlantic increase was
largely due to higher coal volumes at our Shipyard River terminal, located in
Charleston, South Carolina, and to higher cement volumes at our Pier IX bulk
terminal, located in Newport News, Virginia. The increase from our Midwest
terminals was primarily due to the higher cement handling revenues at our Dakota
bulk terminal, as described above.
For the comparable six month periods, the overall increase in segment
revenues in 2005 over 2004 includes increases of $9.5 million (26%) from our
Mid-Atlantic region, $6.6 million (15%) from our Gulf Coast terminals and $4.8
million (15%) from our Midwest terminals. The Mid-Atlantic increase was largely
due to higher coal volumes and higher dockage revenues at our Shipyard River
terminal and to higher synfuel and cement revenues at our Pier IX bulk terminal.
The Gulf Coast increase was due to higher year-to-date transmix revenues and
additional customer contracts at our Pasadena facility, and the Midwest increase
was primarily due to higher cement revenues at our Dakota terminal and higher
oil sales at our Dravosburg, Pennsylvania terminal. In 2005, our Dravosburg
terminal began selling oil for marine fueling.
Operating expenses for all terminals owned during both six month periods
increased $10.0 million (16%) and $22.2 million (18%), respectively, in the
second quarter and first six 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 $4.5 million (54%) from our Mid-Atlantic
terminals, $2.0 million (21%) from our Midwest terminals, and $1.8 million (12%)
from our Lower Mississippi River (Louisiana) terminals. For the comparative six
month periods, the overall increase in operating expenses includes increases of
$9.3 million (60%) from our Mid-Atlantic terminals, $3.5 million (12%) from our
Louisiana terminals, and $2.7 million (15%) from our Midwest terminals.
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. The Midwest increases were primarily due to
higher cost of sales expense at our Dravosburg terminal, due to oil purchasing
costs and inventory maintenance, and the increases for the terminals included in
our Louisiana region were largely due to higher stevedoring, labor, ship
conveyance and general operating expenses.
The segment's other income items were flat across both second quarter
periods, but decreased $0.9 million in the first half of 2005 versus the first
half of 2004. The decrease was primarily due to a disposal loss in the first
quarter of 2005 on warehouse property at our Elizabeth River bulk terminal,
located in Chesapeake, Virginia.
Income tax expenses for the second quarter and first six months of 2005
increased $1.6 million (76%) and $4.8 million (176%), respectively, over the
comparable periods last year. The quarter-to-quarter increase was largely due to
incremental tax expense related to the taxable income of Kinder Morgan River
Terminals LLC and its
64
consolidated subsidiaries, which we acquired effective October 6, 2004. The
increase between the comparable six month periods was approximately 60%
attributable to the incremental income of Kinder Morgan River Terminals LLC, and
approximately 40% attributable to higher taxable income from Kinder Morgan Bulk
Terminals, Inc., the tax-paying entity that owns many of our bulk terminal
businesses.
Compared to the same periods in 2004, non-cash depreciation, depletion and
amortization charges increased $3.7 million (36%) in the second quarter of 2005
and $5.6 million (27%) in the first six 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
second quarter of 2004.
Other
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- ------------------
2005 2004 2005 2004
---- ----- ---- ----
(In thousands-income/(expense))
General and administrative expenses.................................. $ (50,133) $ (39,457) $ (123,985) $ (87,711)
Unallocable interest, net............................................ (66,627) (46,592) (126,674) (93,813)
Minority interest.................................................... (2,454) (2,462) (4,842) (4,543)
Loss from early extinguishment of debt............................... - (1,424) - (1,424)
----------- ------------- ----------- -----------
Interest and corporate administrative expenses..................... $ (119,214) $ (89,935) $ (255,501) $ (187,491)
=========== ============= ============ ===========
Items not attributable to any segment include general and administrative
expenses, unallocable interest income, interest expense and minority interest.
In the second quarter of 2004, we also included the $1.4 million loss from our
early extinguishment of debt in May 2004 as an item not attributable to any
business segment. The loss represented the excess of the price we paid to
repurchase and retire the principal amount of $84.3 million of tax-exempt
industrial revenue bonds over the bonds' carrying value 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 $10.7 million (27%) and $36.3 million (41%), respectively, in
the second quarter and first six months of 2005 as compared to the same periods
in 2004. The increase in the second quarter of 2005 compared to the second
quarter of 2004 was primarily due to higher environmental accruals; higher
shared services expenses, largely related to expenses incurred from KMI's
operation and maintenance of our natural gas pipeline assets; higher corporate
service expenses, which include legal, corporate secretary, tax, information
technology and other shared services; and higher employee-related benefit
expenses.
For the comparative six month periods, the increase was largely due to
incremental expenses of $30.4 million in the first quarter of 2005 related to
unallocated litigation and environmental settlements, consisting of a $25
million expense for a settlement reached between us and a shipper on our Kinder
Morgan Tejas natural gas pipeline system, and a $5.4 million expense related to
settlements of environmental matters at certain of our operating sites located
in the State of California. The additional increase in year-over-year general
and administrative expenses was mainly due to higher shared services and
corporate service expenses. 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 $20.0
million (43%) and $32.9 million (35%), respectively, in the second quarter and
first six months of 2005, versus the same year-earlier periods. The increases
were due to higher average debt balances and higher effective interest rates in
the second quarter and first six months of 2005 compared with the same periods
of 2004.
The period-to-period increases in average borrowings reflect our issuance
of $1.0 billion in principal amount of long-term senior notes since June 30,
2004. The notes were issued under 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 second
quarter of 2004.
65
The period-to-period increase in our average borrowing rates reflects a
general rise in interest rates since the end of the second quarter of 2004; the
weighted average interest rate on all of our borrowings during the second
quarter and first six months of 2005 increased 8% and 10%, respectively, over
the comparable prior-year periods. Given the volatility of interest rates and
the capital markets in general, we use interest rate derivative instruments to
help manage our overall interest expense. Our use of such derivatives is limited
to simple, non-leveraged interest rate swap agreements placed with major
financial institutions whose creditworthiness is monitored. For more information
on our interest rate swaps, see Note 10 to our consolidated financial
statements, included elsewhere in this report.
Minority interest, representing the deduction in our consolidated net
income attributable to all outstanding ownership interests in our five operating
limited partnerships and their consolidated subsidiaries that are not held by
us, was essentially flat across both second quarter periods. Minority interest
increased $0.3 million (7%) in the first six months of 2005, when compared to
the first six months a year-ago. The increase was primarily due to higher
overall income earned by our five operating partnerships, resulting in higher
income allocable to Kinder Morgan G.P., Inc., our general partner and holder of
a 1.0101% general partner ownership interest in each of our five operating
partnerships.
Financial Condition
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:
June 30, December 31,
------------------ ------------------
2005 2004
------------------ ------------------
Long-term debt, excluding market value of interest rate swaps............ $5,247,403 $4,722,410
Minority interest........................................................ 39,970 45,646
Partners' capital, excluding accumulated other comprehensive loss........ 4,396,728 4,353,863
------------- ----------
Total capitalization................................................... 9,684,101 9,121,919
Short-term debt, less cash and cash equivalents.......................... (37,556) -
------------- ----------
Total invested capital................................................. $ 9,646,545 $9,121,919
============= ==========
Capitalization:
Long-term debt, excluding market value of interest rate swaps.......... 54.2% 51.8%
Minority interest...................................................... 0.4% 0.5%
Partners' capital, excluding accumulated other comprehensive loss...... 45.4% 47.7%
------------- ----------
100.0% 100.0%
============= ==========
Invested Capital:
Total debt, less cash and cash equivalents and excluding
market value of interest rate swaps............................... 54.0% 51.8%
Partners' capital and minority interest, excluding accumulated
other comprehensive loss ......................................... 46.0% 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. We are
currently in negotiations to increase the amount available for borrowing under
our credit facility to $1.6 billion.
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
66
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.
As a publicly traded limited partnership, our common units are attractive
primarily to individual investors, although such investors represent a small
segment of the total equity capital market. We believe that some institutional
investors prefer shares of KMR over our common units due to tax and other
regulatory considerations. We are able to access this segment of the capital
market through KMR's purchases of i-units issued by us with the proceeds from
the sale of KMR shares to institutional investors.
As of June 30, 2005, our forecasted expenditures for the remaining six
months of 2005 for sustaining capital expenditures were approximately $81
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 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.
Pursuant to our continuing commitment to operational excellence and our
focus on safe reliable operations, we have implemented, and intend to implement
in the future, enhancements to certain of our operational practices in order to
strengthen our environmental and asset integrity performance. These enhancements
have resulted and may result in higher operating costs; however, we believe
these enhancements will provide us the greater long term benefits of improved
environmental and asset integrity performance.
Operating Activities
Net cash provided by operating activities was $588.2 million for the six
months ended June 30, 2005, versus $555.8 million in the comparable period of
2004. The period-to-period increase of $32.4 million (6%) in cash flow from
operations consisted of:
- a $97.4 million increase in cash from overall higher partnership income,
net of non-cash items including depreciation charges and undistributed
earnings from equity investments;
- a $34.3 million decrease in cash inflows relative to net changes in
working capital items;
- a $25.8 million decrease in cash inflows relative to net changes in
non-current assets and liabilities; and
- a $4.9 million decrease related to lower distributions received from
equity investments.
The higher partnership income reflects the increase in cash earnings across
all four of our reportable business segments in the first half of 2005, as
discussed above in "Results of Operations." The decrease in cash from working
capital items in the first six months of 2005 compared to the first six months
of 2004 was mainly due to timing differences that resulted in higher payments in
2005 on trade accounts payables, lower net cash inflows from the settlements of
short-term natural gas pipeline imbalances, and higher payments made to increase
short-term natural gas storage volumes.
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 half of 2005 to reduce long-term liabilities and reserves for items such
as: natural gas imbalances, reserves for natural gas lost and used during
transmission, and pipeline rate case and other long-term claim liabilities. The
decrease in cash inflows from our equity investees was primarily due to lower
distributions received from Red Cedar in the first six months of 2005 compared
to the same period of 2004. The reduction in distributions from Red Cedar were
due to the following two factors. First, since the summer of 2004, Red Cedar has
increased its expansion capital spending and has funded a large portion of the
expenditures with
67
retained cash. Secondly, in October 2004, Red Cedar began paying principal
amounts due on long-term debt borrowings, thus reducing its cash available for
distribution to investors.
Investing Activities
Net cash used in investing activities was $586.8 million for the six month
period ended June 30, 2005, compared to $395.1 million in the comparable 2004
period. The $191.7 million (49%) increase in cash used in investing activities
was primarily attributable to an increase of $141.6 million due to higher
expenditures made in the first half of 2005 for strategic business acquisitions.
During the first six months of 2005, our acquisition outlays totaled $193.3
million, which primarily consisted of $183.7 million used to acquire bulk
terminal assets from Trans-Global Solutions, Inc., and $6.2 million used to
acquire a 64.5% gross working interest in the Claytonville oil field unit
located in West Texas. For the comparable six month period last year, our
acquisition outlays totaled $51.7 million, including $48.1 million for the
acquisition of seven refined petroleum products terminals in the southeastern
United States from Exxon Mobil Corporation.
The overall period-to-period increase in cash used in investing activities
also included an increase of $32.4 million related to higher 2005 margin
deposits associated with the energy derivative instruments we use to hedge our
energy commodity price risk, and an increase of $20.0 million that was primarily
related to additional investments in underground natural gas storage volumes.
For more information on our hedging activities, see Note 10 to our consolidated
financial statements included elsewhere in this report.
Including expansion and maintenance projects, our capital expenditures were
$341.6 million in the first six months of 2005, slightly up from the $339.5
million we spent in the same prior-year period. Our sustaining capital
expenditures were $53.0 million for the first six months of 2005 compared to
$46.1 million for the first six months of 2004.
We continue to expand and grow our business portfolio and have current
projects in place that will further increase production from our crude oil
reserve interests and will add storage and throughput capacity to our carbon
dioxide flooding, natural gas and refined product pipelines, and terminaling
operations. In July 2005, we announced a $48 million investment for two major
terminal expansion projects. The first entails the construction of 600,000
barrels of new storage capacity for gasoline and distillates at our Pasadena,
Texas liquids terminal. The expansion is being supported by long-term contracts.
The second project involves improvements at our Shipyard River bulk terminal
that are expected to increase throughput by more than 30 percent and enhance our
ability to handle the increasing supplies of imported coal used to meet the
growing demand for electricity in the Southeast. We have executed a long-term
contract with at third party to support the economics of the expansion.
Financing Activities
Net cash provided by financing activities amounted to $36.3 million for the
six months ended June 30, 2005. For the same six months of 2004, we used $150.3
million in financing activities. The $186.6 million overall increase in cash
provided by financing activities was due to a $544.0 million increase in cash
inflows from overall debt financing activities, which 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 $164.7 million increase due to higher net commercial paper borrowings
in the first half of 2005 versus the first half of 2004, primarily
related to acquisitions;
- a $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;
68
- 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 $4.7 million decrease due to higher debt issuance costs, largely
attributable to our March 2005 issuance of senior notes.
The overall increase in cash provided by financing activities was partially
offset by period-to-period decreases of $251.4 million due to lower cash
proceeds from partnership equity issuances, $76.8 million due to higher
partnership distributions, and $28.6 million due to reductions in temporary cash
book overdrafts, which represent checks issued but not yet endorsed.
The decrease in cash inflows from partnership equity issuances primarily
related to the cash received from our February 2004 issuance of common units and
our March 2004 issuance of i-units. On February 9, 2004, we issued, in a public
offering, an additional 5,300,000 of our common units at a price of $46.80 per
unit, less commissions and underwriting expenses. After these fees, we received
net proceeds of $237.8 million for the issuance of these common units. On March
25, 2004, we issued an additional 360,664 of our i-units to KMR at a price of
$41.59 per share, less closing fees and commissions. After fees, we received net
proceeds of $14.9 million for the issuance of these i-units. We used the
proceeds from each of these issuances to reduce the borrowings under our
commercial paper program.
Distributions to all partners, consisting of our common and Class B
unitholders, our general partner and minority interests, totaled $456.2 million
in the first six months of 2005 compared to $379.4 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 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;
69
- 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 second quarter of 2005 was $115.7
million. Our general partner's incentive distribution for the distribution that
we declared for the second quarter of 2004 was $94.9 million. Our general
partner's incentive distribution that we paid during the second quarter of 2005
to our general partner (for the first quarter of 2005) was $111.1 million. Our
general partner's incentive distribution that we paid during the second quarter
of 2004 to our general partner (for the first quarter of 2004) was $90.7
million.
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.
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;
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- 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;
- 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
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- 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.
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 June 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 June 30, 2005 that has materially affected,
or is reasonably likely to materially affect, our internal control over
financial reporting.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 3 to our consolidated financial statements
entitled "Litigation and Other Contingencies," which is incorporated herein by
reference.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Effective April 29, 2005, we issued 957,656 common units as part of the
purchase price for seven bulk terminal operations that we acquired from
Trans-Global Solutions, Inc. The total purchase price for the acquired
operations was approximately $245 million, consisting of $183.7 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. The units were issued to a
single accredited investor in a transaction not involving a public offering
under Section 4(2) of the Securities Act of 1933.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Item 5. Other Information.
At its July 20, 2005 meeting, the compensation committee of the KMI board
of directors approved a special contribution of an additional 1% of base pay
into the Kinder Morgan Savings Plan (a defined contribution 401(k) plan) for
each eligible employee. Each eligible employee will receive an additional 1%
company contribution based on eligible base pay to his or her Savings Plan
account each pay period beginning with the first pay period of August 2005 and
continuing through the last pay period of July 2006.
The 1% contribution will be in the form of KMI common stock (the same as
the current 4% contribution). The 1% contribution will be in addition to, and
does not change or otherwise impact, the 4% contribution that eligible employees
currently receive. It may be converted to any other Savings Plan investment fund
at any time and it will vest on the second anniversary of the employee's date of
hire. Since this additional 1% company contribution is discretionary,
compensation committee approval will be required annually for each special
contribution.
On May 4, 2005, we announced that C. Park Shaper, formerly Executive Vice
President and Chief Financial Officer of KMI, KMR and Kinder Morgan G.P., Inc.,
had been promoted and named President of KMI, KMR and Kinder Morgan G.P., Inc.,
remaining a member of the Office of the Chairman, and that Steve Kean, formerly
our President - Texas Intrastate Pipelines, had been promoted and named
Executive Vice President, Operations of KMI, KMR and Kinder Morgan G.P., Inc.,
becoming a member of the Office of the Chairman. In addition, we announced that
Kim Allen had been promoted and named Chief Financial Officer of KMI, KMR and
Kinder Morgan G.P., Inc., retaining her role in charge of investor relations,
and that David Kinder, Vice President, Corporate Development of KMI, KMR and
Kinder Morgan G.P., Inc., would also assume the role of Treasurer, formerly held
by Ms. Allen. We also announced that (i) Deb Macdonald, our President - Natural
Gas Pipelines, would resign from that position effective October 2005; (ii)
Scott Parker, President of KMI's Natural Gas Pipeline Company of America
("NGPL"), would be promoted effective October 2005 to our President - Natural
Gas Pipelines; (iii) David Devine would
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become President of NGPL effective October 2005; and (iv) Tom Martin had been
promoted to President - Texas Intrastate Pipelines. Until Ms. MacDonald's
resignation in October 2005, each of Ms. MacDonald and Mr. Parker are serving
as Co-Presidents - Natural Gas Pipelines.
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.
11 -- Statement re: computation of per share earnings.
31.1 -- Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the
Securities Exchange Act of 1934, as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
31.2 -- Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the
Securities Exchange Act of 1934, as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
32.1 -- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 -- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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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: August 1, 2005
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