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 March 31, 2006
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 1-11234
KINDER MORGAN ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0380342
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
500 Dallas Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-369-9000
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No
Indicate by check mark whether the registrant is a large accelerated filer,
an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of
the Securities Exchange Act of 1934). Large accelerated filer [X] Accelerated
filer [ ] Non-accelerated filer [ ]
Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X]
The Registrant had 157,019,676 common units outstanding as of April 28,
2006.
1
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
PART I. FINANCIAL INFORMATION
Item 1: Financial Statements (Unaudited).................................. 3
Consolidated Statements of Income-Three Months Ended
March 31, 2006 and 2005....................................... 3
Consolidated Balance Sheets - March 31, 2006 and
December 31, 2005............................................. 4
Consolidated Statements of Cash Flows - Three Months
Ended March 31, 2006 and 2005................................. 5
Notes to Consolidated Financial Statements...................... 6
Item 2: Management's Discussion and Analysis of Financial
Condition and Results of Operations............................. 52
Critical Accounting Policies and Estimates...................... 52
Results of Operations........................................... 52
Financial Condition............................................. 65
Information Regarding Forward-Looking Statements................ 72
Item 3: Quantitative and Qualitative Disclosures About Market Risk........ 74
Item 4: Controls and Procedures........................................... 74
PART II. OTHER INFORMATION
Item 1: Legal Proceedings................................................. 75
Item 1A: Risk Factors...................................................... 75
Item 2: Unregistered Sales of Equity Securities and Use of Proceeds....... 75
Item 3: Defaults Upon Senior Securities................................... 75
Item 4: Submission of Matters to a Vote of Security Holders............... 75
Item 5: Other Information................................................. 75
Item 6: Exhibits.......................................................... 75
Signature......................................................... 77
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 March 31,
------------ ---------------
2006 2005
---------- ---------------
Revenues
Natural gas sales................................... $1,691,392 $1,352,615
Services............................................ 509,502 443,425
Product sales and other............................. 190,707 175,892
---------- ----------
2,391,601 1,971,932
---------- ----------
Costs and Expenses
Gas purchases and other costs of sales.............. 1,677,231 1,337,770
Operations and maintenance.......................... 173,382 138,540
Fuel and power...................................... 50,923 41,940
Depreciation, depletion and amortization............ 92,721 85,027
General and administrative.......................... 60,883 73,852
Taxes, other than income taxes...................... 31,267 25,826
---------- ----------
2,086,407 1,702,955
---------- ----------
Operating Income...................................... 305,194 268,977
Other Income (Expense)
Earnings from equity investments.................... 24,721 26,072
Amortization of excess cost of equity investments... (1,414) (1,417)
Interest, net....................................... (75,706) (58,727)
Other, net.......................................... 1,775 (1,321)
Minority Interest..................................... (2,370) (2,388)
---------- ----------
Income Before Income Taxes............................ 252,200 231,196
Income Taxes.......................................... (5,491) (7,575)
---------- ----------
Net Income............................................ $ 246,709 $ 223,621
-========= ==========
General Partner's interest in Net Income.............. $ 129,528 $ 111,727
Limited Partners' interest in Net Income.............. 117,181 111,894
---------- ----------
Net Income............................................ $ 246,709 $ 223,621
========== ==========
Basic and Diluted Limited Partners' Net Income per $ 0.53 $ 0.54
========== ==========
Unit..................................................
Weighted average number of units used in computation
of Limited
Partners' Net Income per unit:
Basic................................................. 220,753 207,528
========== ==========
Diluted............................................... 221,080 207,584
========== ==========
Per unit cash distribution declared................... $ 0.81 $ 0.76
========== ==========
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)
March 31, December 31,
--------- ------------
2006 2005
---- ----
ASSETS
Current Assets
Cash and cash equivalents........................ $ 32,636 $ 12,108
Restricted deposits.............................. 33,100 -
Accounts, notes and interest receivable, net
Trade......................................... 784,806 1,011,716
Related parties............................... 3,659 2,543
Inventories
Products...................................... 15,367 18,820
Materials and supplies........................ 13,851 13,292
Gas imbalances
Trade......................................... 13,781 18,220
Related parties............................... 3,111 -
Gas in underground storage....................... 45,616 7,074
Other current assets............................. 93,177 131,451
----------- -----------
1,039,104 1,215,224
----------- -----------
Property, Plant and Equipment, net................. 9,210,903 8,864,584
Investments........................................ 434,684 419,313
Notes receivable
Trade............................................ 1,438 1,468
Related parties.................................. 92,003 109,006
Goodwill........................................... 798,959 798,959
Other intangibles, net............................. 216,588 217,020
Deferred charges and other assets.................. 227,572 297,888
----------- -----------
Total Assets....................................... $12,021,251 $11,923,462
=========== ===========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts....................... $ 42,198 $ 30,408
Trade...................................... 681,252 996,174
Related parties............................ 5,370 16,676
Current portion of long-term debt............. - -
Accrued interest.............................. 42,898 74,886
Accrued taxes................................. 40,862 23,536
Deferred revenues............................. 12,281 10,523
Gas imbalances
Trade...................................... 13,189 22,948
Related parties............................ - 1,646
Accrued other current liabilities............. 643,703 632,088
----------- -----------
1,481,753 1,808,885
----------- -----------
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding................................ 5,704,920 5,220,887
Market value of interest rate swaps........ 10,239 98,469
----------- -----------
5,715,159 5,319,356
Deferred revenues............................. 5,846 6,735
Deferred income taxes......................... 70,632 70,343
Asset retirement obligations.................. 42,721 42,417
Other long-term liabilities and deferred credits 1,086,598 1,019,655
----------- -----------
6,920,956 6,458,506
----------- -----------
Commitments and Contingencies (Note 3)
Minority Interest............................... 131,087 42,331
----------- -----------
Partners' Capital
Common Units.................................. 2,638,137 2,680,352
Class B Units................................. 108,165 109,594
i-Units....................................... 1,814,526 1,783,570
General Partner............................... 122,021 119,898
Accumulated other comprehensive loss.......... (1,195,394) (1,079,674)
----------- -----------
3,487,455 3,613,740
----------- -----------
Total Liabilities and Partners' Capital......... $12,021,251 $11,923,462
=========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
4
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Increase/(Decrease) in Cash and Cash Equivalents In Thousands)
(Unaudited)
Three Months Ended
March 31,
----------------------
2006 2005
---------- ----------
Cash Flows From Operating Activities
Net income............................................ $ 246,709 $ 223,621
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization............ 92,721 85,027
Amortization of excess cost of equity investments... 1,414 1,417
Earnings from equity investments.................... (24,721) (26,072)
Distributions from equity investments................. 22,378 13,386
Changes in components of working capital:
Accounts receivable................................. 236,029 49,284
Other current assets................................ (22,329) (10,239)
Inventories......................................... 2,898 (2,245)
Accounts payable.................................... (326,208) (95,343)
Accrued liabilities................................. (44,324) (12,429)
Accrued taxes....................................... 17,397 15,636
Other, net............................................ (25,950) 17,464
---------- ----------
Net Cash Provided by Operating Activities............... 176,014 259,507
---------- ----------
Cash Flows From Investing Activities
Acquisitions of assets................................ (240,000) (6,476)
Additions to property, plant and equip. for
expansion and maintenance projects.................... (193,663) (143,808)
Sale of investments, property, plant and equipment,
net of removal costs.................................. (272) 2,900
Investments in margin deposits........................ (33,100) (18,096)
Contributions to equity investments................... (2) (18)
Natural gas stored underground and natural gas
liquids line-fill..................................... (9,833) (1,905)
Other................................................. (2,988) (588)
---------- ----------
Net Cash Used in Investing Activities................... (479,858) (167,991)
---------- ----------
Cash Flows From Financing Activities
Issuance of debt...................................... 1,148,000 1,327,433
Payment of debt....................................... (664,267) (1,182,630)
Debt issue costs...................................... (450) (4,477)
Increase (Decrease) in cash book overdrafts........... 11,789 (8,560)
Proceeds from issuance of common units................ 83 1,167
Contributions from minority interest.................. 91,043 409
Distributions to partners:
Common units........................................ (125,873) (109,191)
Class B units....................................... (4,251) (3,932)
General Partner..................................... (127,405) (107,585)
Minority interest................................... (3,477) (2,761)
Other, net............................................ (838) (1,389)
---------- ----------
Net Cash Provided by (Used in) Financing Activities..... 324,354 (91,516)
---------- ----------
Effect of exchange rate changes on cash and cash
equivalents............................................. 18 --
---------- ----------
Increase (Decrease) in Cash and Cash Equivalents........ 20,528 --
Cash and Cash Equivalents, beginning of period.......... 12,108 --
---------- ----------
Cash and Cash Equivalents, end of period................ $ 32,636 $ --
========== ==========
Noncash Investing and Financing Activities:
Contribution of net assets to partnership
investments........................................... $ 17,003 $ --
Assets acquired by the assumption of liabilities...... $ -- $ 284
The accompanying notes are an integral part of these consolidated
financial statements.
5
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Organization
General
Unless the context requires otherwise, references to "we," "us," "our" or
the "Partnership" are intended to mean Kinder Morgan Energy Partners, L.P. and
its consolidated subsidiaries. We have prepared the accompanying unaudited
consolidated financial statements under the rules and regulations of the
Securities and Exchange Commission. Under such rules and regulations, we have
condensed or omitted certain information and notes normally included in
financial statements prepared in conformity with accounting principles generally
accepted in the United States of America. We believe, however, that our
disclosures are adequate to make the information presented not misleading. The
consolidated financial statements reflect all adjustments which are solely
normal and recurring adjustments that are, in the opinion of our management,
necessary for a fair presentation of our financial results for the interim
periods. You should read these consolidated financial statements in conjunction
with our consolidated financial statements and related notes included in our
Annual Report on Form 10-K for the year ended December 31, 2005.
Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Management,
LLC
Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of
Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware
corporation, is the sole stockholder of our general partner, Kinder Morgan G.P.,
Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report.
Kinder Morgan Management, LLC, a Delaware limited liability company, was
formed on February 14, 2001. Our general partner owns all of Kinder Morgan
Management, LLC's voting securities and, pursuant to a delegation of control
agreement, our general partner delegated to Kinder Morgan Management, LLC, to
the fullest extent permitted under Delaware law and our partnership agreement,
all of its power and authority to manage and control our business and affairs,
except that Kinder Morgan Management, LLC cannot take certain specified actions
without the approval of our general partner. Under the delegation of control
agreement, Kinder Morgan Management, LLC manages and controls our business and
affairs and the business and affairs of our operating limited partnerships and
their subsidiaries. Furthermore, in accordance with its limited liability
company agreement, Kinder Morgan Management, LLC's activities are limited to
being a limited partner in, and managing and controlling the business and
affairs of us, our operating limited partnerships and their subsidiaries. Kinder
Morgan Management, LLC is referred to as "KMR" in this report.
Basis of Presentation
Our consolidated financial statements include our accounts and those of our
operating partnerships and their majority-owned and controlled subsidiaries. All
significant intercompany items have been eliminated in consolidation.
Net Income Per Unit
We compute Basic Limited Partners' Net Income per Unit by dividing our
limited partners' interest in net income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the maximum potential dilution that could occur if units whose issuance
depends on the market price of the units at a future date were considered
outstanding, or if, by application of the treasury stock method, options to
issue units were exercised, both of which would result in the issuance of
additional units that would then share in our net income.
6
2. Acquisitions and Joint Ventures
During the first three months of 2006, we completed the following
acquisition. The acquisition was accounted for under the purchase method and the
assets acquired were recorded at their estimated fair market values as of the
acquisition date. The preliminary allocation of assets (and any liabilities
assumed) may be adjusted to reflect the final determined amounts during a period
of time following the acquisition. The results of operations from this
acquisition are included in our consolidated financial statements from the
acquisition date.
Entrega Gas Pipeline LLC
Effective February 23, 2006, Rockies Express Pipeline LLC acquired Entrega
Gas Pipeline LLC from EnCana Corporation for $240.0 million in cash. We
contributed $160.0 million, which corresponded to our 66 2/3% ownership interest
in Rockies Express Pipeline LLC. Sempra Energy holds the remaining 33 1/3%
ownership interest and contributed $80.0 million. At the time of acquisition,
Entegra Gas Pipeline LLC owned the Entrega Pipeline, an interstate natural gas
pipeline that will consist of two segments: (i) a 136-mile, 36-inch diameter
pipeline that extends from the Meeker Hub in Rio Blanco County, Colorado to the
Wamsutter Hub in Sweetwater County, Wyoming, and (ii) a 191-mile, 42-inch
diameter pipeline that extends from the Wamsutter Hub to the Cheyenne Hub in
Weld County, Colorado, where it will ultimately connect with our Rockies Express
Pipeline, an interstate natural gas pipeline that, at the time of acquisition,
was being developed by Rockies Express Pipeline LLC.
In combination, the Entrega and Rockies Express pipelines have the
potential to create a major new natural gas transmission pipeline that will
provide seamless transportation of natural gas from Rocky Mountain production
areas to Midwest and eastern Ohio markets. EnCana Corporation completed
construction of the first segment of the Entrega Pipeline and interim service
has begun. Under the terms of the purchase and sale agreement, we and Sempra
will construct the second segment of the Entrega Pipeline, and construction is
scheduled to begin this summer. It is anticipated that the entire Entrega system
will be placed into service by January 1, 2007.
In April 2006, Rockies Express Pipeline LLC merged with and into Entrega
Gas Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline
LLC. Going forward, the entire pipeline system will be known as the Rockies
Express Pipeline. Also in April 2006, we paid EnCana approximately $4.6 million
in cash as consideration for purchase prince adjustments recognized in the
second quarter of 2006.
As of March 31, 2006, our allocation of the purchase price to assets
acquired and liabilities assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs.......... $ 240,000
Liabilities assumed............................. --
---------
Total purchase price............................ $ 240,000
=========
Allocation of purchase price:
Current assets.................................. $ --
Property, plant and equipment................... 240,000
Deferred charges and other assets............... --
---------
$ 240,000
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement
information for the three months ended March 31, 2006 and 2005, assumes that all
of the acquisitions we have made and joint ventures we have entered into since
January 1, 2005, including the one listed above, had occurred as of the
beginning of the period presented. We have prepared these unaudited pro forma
financial results for comparative purposes only. These unaudited pro forma
financial results may not be indicative of the results that would have occurred
if we had completed these acquisitions and joint ventures as of January 1, 2005
or the results that will be attained in the future. Amounts presented below are
in thousands, except for the per unit amounts:
7
Pro Forma
Three Months Ended March 31,
----------------------------
2006 2005
------------ -------------
(Unaudited)
Revenues.......................................... $ 2,398,260 $ 2,004,783
Operating Income.................................. 305,331 277,706
Net Income........................................ $ 245,656 $ 228,690
Basic Limited Partners' Net Income per unit....... $ 0.53 $ 0.56
Diluted Limited Partners' Net Income per unit..... $ 0.53 $ 0.56
Acquisitions Subsequent to March 31, 2006
Oil and Gas Properties
On April 7, 2006, Kinder Morgan Production Company L.P. purchased various
oil and gas properties from Journey Acquisition - I, L.P. and Journey 2000, L.P.
The acquisition was made effective March 1, 2006. The properties are primarily
located in the Permian Basin area of West Texas, produce approximately 850
barrels of oil equivalent per day net, and include some fields with enhanced oil
recovery development potential near our current carbon dioxide operations. The
acquired operations are included as part of our CO2 business segment. During the
next several months, we will perform technical evaluations to confirm the carbon
dioxide enhanced oil recovery potential and generate definitive plans to develop
this potential if proven to be economic. The purchase price plus the anticipated
investment to both further develop carbon dioxide enhanced oil recovery and
construct a new carbon dioxide supply pipeline on all of the acquired properties
is approximately $115 million. However, since we intend to divest in the near
future those acquired properties that are not candidates for carbon dioxide
enhanced oil recovery, our total investment is likely to be considerably less.
April 2006 Terminal Assets
In April 2006, we acquired terminal assets and operations from A&L
Trucking, L.P. and U.S. Development Group in three separate transactions for an
aggregate consideration of approximately $61.9 million, consisting of $61.6
million in cash and $0.3 million in assumed liabilities.
The first transaction included the acquisition of equipment and
infrastructure on the Houston Ship Channel that loads and stores steel products.
The acquired assets complement our nearby bulk terminal facility purchased from
General Stevedores, L.P. in July 2005. The second acquisition included the
purchase of a rail terminal at the Port of Houston that handles both bulk and
liquids products. The rail terminal complements our existing Texas petroleum
coke terminal operations and maximizes the value of our existing deepwater
terminal by providing customers with both rail and vessel transportation options
for bulk products. Thirdly, we acquired the entire membership interest of Lomita
Rail Terminal LLC, a limited liability company that owns a high-volume rail
ethanol terminal in Carson, California. The terminal serves approximately 80% of
the southern California demand for reformulated fuel blend ethanol with
expandable offloading/distribution capacity, and the acquisition expanded our
existing rail transloading operations. All of the acquired assets are included
in our Terminals business segment. We will allocate our total purchase price to
assets acquired and liabilities assumed in the second quarter of 2006, and we
expect to assign approximately $17.6 million of goodwill to our Terminals
business segment.
3. Litigation, Environmental and Other Contingencies
Federal Energy Regulatory Commission Proceedings
SFPP, L.P.
SFPP, L.P., referred to in this report as SFPP, is the subsidiary limited
partnership that owns our Pacific operations, excluding CALNEV Pipe Line LLC and
related terminals acquired from GATX Corporation. Tariffs charged by SFPP are
subject to certain proceedings at the FERC, including shippers' complaints
regarding interstate rates on our Pacific operations' pipeline systems.
8
OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a
consolidated proceeding that began in September 1992 and includes a number of
shipper complaints against certain rates and practices on SFPP's East Line (from
El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California
to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson
Station in Carson, California. The complainants in the case are El Paso
Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company,
Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products
Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing
Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.),
Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco
Corporation (now part of ConocoPhillips Company). The FERC has ruled that the
complainants have the burden of proof in this proceeding.
A FERC administrative law judge held hearings in 1996, and issued an
initial decision in September 1997. The initial decision held that all but one
of SFPP's West Line rates were "grandfathered" under the Energy Policy Act of
1992 and therefore deemed to be just and reasonable; it further held that
complainants had failed to prove "substantially changed circumstances" with
respect to those rates and that the rates therefore could not be challenged in
the Docket No. OR92-8 et al. proceedings, either for the past or prospectively.
However, the initial decision also made rulings generally adverse to SFPP on
certain cost of service issues relating to the evaluation of East Line rates,
which are not "grandfathered" under the Energy Policy Act. Those issues included
the capital structure to be used in computing SFPP's "starting rate base," the
level of income tax allowance SFPP may include in rates and the recovery of
civil and regulatory litigation expenses and certain pipeline reconditioning
costs incurred by SFPP. The initial decision also held SFPP's Watson Station
gathering enhancement service was subject to FERC jurisdiction and ordered SFPP
to file a tariff for that service.
The FERC subsequently reviewed the initial decision, and issued a series of
orders in which it adopted certain rulings made by the administrative law judge,
changed others and modified a number of its own rulings on rehearing. Those
orders began in January 1999, with FERC Opinion No. 435, and continued through
June 2003.
The FERC affirmed that all but one of SFPP's West Line rates are
"grandfathered" and that complainants had failed to satisfy the threshold burden
of demonstrating "substantially changed circumstances" necessary to challenge
those rates. The FERC further held that the one West Line rate that was not
grandfathered did not need to be reduced. The FERC consequently dismissed all
complaints against the West Line rates in Docket Nos. OR92-8 et al. without any
requirement that SFPP reduce, or pay any reparations for, any West Line rate.
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.
9
In April 2003, SFPP paid complainants and other shippers reparations and/or
refunds as required by FERC's orders. In August 2003, SFPP paid shippers an
additional refund as required by FERC's most recent order in the Docket No.
OR92-8 et al. proceedings. We made aggregate payments of $44.9 million in 2003
for reparations and refunds pursuant to a FERC order.
Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond
Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for
review of FERC's Docket OR92-8 et al. orders in the United States Court of
Appeals for the District of Columbia Circuit. Certain of those petitions were
dismissed by the Court of Appeals as premature, and the remaining petitions were
held in abeyance pending completion of agency action. However, in December 2002,
the Court of Appeals returned to its active docket all petitions to review the
FERC's orders in the case through November 2001 and severed petitions regarding
later FERC orders. The severed orders were held in abeyance for later
consideration.
Briefing in the Court of Appeals was completed in August 2003, and oral
argument took place on November 12, 2003. On July 20, 2004, the Court of Appeals
issued its opinion in BP West Coast Products, LLC v. Federal Energy Regulatory
Commission, No. 99-1020, On Petitions for Review of Orders of the Federal Energy
Regulatory Commission (Circuit opinion), addressing in part the tariffs of SFPP,
L.P. Among other things, the court's opinion vacated the income tax allowance
portion of the FERC opinion and the order allowing recovery in SFPP's rates for
income taxes and remanded to the FERC this and other matters for further
proceedings consistent with the court's opinion. In reviewing a series of FERC
orders involving SFPP, the Court of Appeals held, among other things, that the
FERC had not adequately justified its policy of providing an oil pipeline
limited partnership with an income tax allowance equal to the proportion of its
limited partnership interests owned by corporate partners. By its terms, the
portion of the opinion addressing SFPP only pertained to SFPP, L.P. and was
based on the record in that case.
The Court of Appeals held that, in the context of the Docket No. OR92-8, et
al. proceedings, all of SFPP's West Line rates were grandfathered other than the
charge for use of SFPP's Watson Station gathering enhancement facility and the
rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded
that the FERC had a reasonable basis for concluding that the addition of a West
Line origin point at East Hynes, California did not involve a new "rate" for
purposes of the Energy Policy Act. It rejected arguments from West Line Shippers
that certain protests and complaints had challenged West Line rates prior to the
enactment of the Energy Policy Act.
The Court of Appeals also held that complainants had failed to satisfy
their burden of demonstrating substantially changed circumstances, and therefore
could not challenge grandfathered West Line rates in the Docket No. OR92-8 et
al. proceedings. It specifically rejected arguments that other shippers could
"piggyback" on the special Energy Policy Act exception permitting Navajo to
challenge grandfathered West Line rates, which Navajo had withdrawn under a
settlement with SFPP. The court remanded to the FERC the changed circumstances
issue "for further consideration" in light of the court's decision regarding
SFPP's tax allowance. While, the FERC had previously held in the OR96-2
proceeding (discussed following) that the tax allowance policy should not be
used as a stand-alone factor in determining when there have been substantially
changed circumstances, the FERC's May 4, 2005 income tax allowance policy
statement (discussed following) may affect how the FERC addresses the changed
circumstances and other issues remanded by the court.
The Court of Appeals upheld the FERC's rulings on most East Line rate
issues; however, it found the FERC's reasoning inadequate on some issues,
including the tax allowance.
The Court of Appeals held the FERC had sufficient evidence to use SFPP's
December 1988 stand-alone capital structure to calculate its starting rate base
as of June 1985; however, it rejected SFPP arguments that would have resulted in
a higher starting rate base.
The Court of Appeals accepted the FERC's treatment of regulatory litigation
costs, including the limitation of recoverable costs and their offset against
"unclaimed reparations" - that is, reparations that could have been awarded to
parties that did not seek them. The court also accepted the FERC's denial of any
recovery for the costs of civil litigation by East Line shippers against SFPP
based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix.
However, the court did not find adequate support for the FERC's decision to
allocate the limited litigation costs that SFPP was allowed to recover in its
rates equally between the East Line and the West Line, and ordered the FERC to
explain that decision further on remand.
10
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.
On December 17, 2004, the Court of Appeals issued orders directing that the
petitions for review relating to FERC orders issued after November 2001 in
OR92-8, which had previously been severed from the main Court of Appeals docket,
should continue to be held in abeyance pending completion of the remand
proceedings before the FERC. Petitions for review of orders issued in other FERC
dockets have since been returned to the court's active docket (discussed further
below in relation to the OR96-2 proceedings).
11
On January 3, 2005, SFPP filed a petition for a writ of certiorari asking the
United States Supreme Court to review the Court of Appeals' ruling that the
Arizona Grocery doctrine does not apply to "interim" rates, and that "FERC only
established a final rate at the completion of the OR92-8 proceedings." BP West
Coast Products and ExxonMobil also filed a petition for certiorari, on December
30, 2004, seeking review of the Court of Appeals' ruling that there was no
pending investigation of West Line rates at the time of enactment of the Energy
Policy Act (and thus that those rates remained grandfathered). On April 6, 2005,
the Solicitor General filed a brief in opposition to both petitions on behalf of
the FERC and United States, and Navajo, ConocoPhillips, Ultramar, Valero and
Western Refining filed an opposition to SFPP's petition. SFPP filed a reply to
those briefs on April 18, 2005. On May 16, 2005, the Supreme Court issued orders
denying the petitions for certiorari filed by SFPP and by BP West Coast Products
and ExxonMobil.
On June 1, 2005, the FERC issued its Order on Remand and Rehearing, which
addressed issues in both the OR92-8 and OR96-2 proceedings (discussed
following).
With respect to the OR92-8 proceedings, the June 1, 2005 order ruled on
several issues that had been remanded by the Court of Appeals in BP West Coast
Products. With respect to the income tax allowance, the FERC held that its May
4, 2005 policy statement would apply in the OR92-8 and OR96-2 proceedings and
that SFPP "should be afforded an income tax allowance on all of its partnership
interests to the extent that the owners of those interests had an actual or
potential tax liability during the periods at issue." It directed SFPP and
opposing parties to file briefs regarding the state of the existing record on
those questions and the need for further proceedings. Those filings are
described below in the discussion of the OR96-2 proceedings. The FERC held that
SFPP's allowable regulatory litigation costs in the OR92-8 proceedings should be
allocated between the East Line and the West Line based on the volumes carried
by those lines during the relevant period. In doing so, it reversed its prior
decision to allocate those costs between the two lines on a 50-50 basis. The
FERC affirmed its prior decision to exclude SFPP's pipeline reconditioning costs
from the cost of service in the OR92-8 proceedings, but stated that SFPP will
have an opportunity to justify much of those reconditioning expenses in the
OR96-2 proceedings. The FERC deferred further proceedings on the
non-grandfathered West Line turbine fuel rate until completion of its review of
the initial decision in phase two of the OR96-2 proceedings. The FERC held that
SFPP's contract charge for use of the Watson Station gathering enhancement
facilities was not grandfathered and required further proceedings before an
administrative law judge to determine the reasonableness of that charge; those
proceedings are currently in settlement negotiations before a FERC settlement
judge.
Petitions for review of the June 1, 2005 order by the United States Court
of Appeals for the District of Columbia Circuit have been filed by SFPP, Navajo,
Western Refining, BP West Coast Products, ExxonMobil, Chevron, ConocoPhillips,
Ultramar and Valero. SFPP has moved to intervene in the review proceedings
brought by the other parties. A briefing schedule has been set by the Court,
with initial briefs due May 30, 2006 and final briefs filed October 11, 2006.
On December 16, 2005, the FERC issued its Order on Initial Decision and on
Certain Remanded Cost Issues, which provided further guidance regarding
application of the FERC's income tax allowance policy in this case, which is
discussed below in connection with the OR96-2 proceedings. The December 16, 2005
order required SFPP to submit a revised East Line cost of service filing
following FERC's rulings regarding the income tax allowance and the ruling in
its June 1, 2005 order regarding the allocation of litigation costs. SFPP is
required to file interim East Line rates effective May 1, 2006 using the lower
of the revised OR92-8 (1994 test year) or OR96-2 (1999 test year) rates, as
adjusted for indexing through April 30, 2006. The December 16, 2005 order also
required SFPP to calculate costs-of-service for West Line turbine fuel movements
based on both a 1994 and 1999 test year and to file interim turbine fuel rates
to be effective May 1, 2006, using the lower of the two test year rates as
indexed through April 30, 2006. SFPP was further required to calculate estimated
reparations for complaining shippers consistent with the order. As described
further below, various parties filed requests for rehearing and petitions for
review of the December 16, 2005 order.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at the
FERC (Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipeline
(Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were
subject to the FERC's jurisdiction under the Interstate Commerce Act, and
claimed that the rate
12
for that service was unlawful. Several other West Line shippers filed similar
complaints and/or motions to intervene.
In an August 1997 order, the FERC held that the movements on the Sepulveda
pipeline were subject to its jurisdiction. On October 6, 1997, SFPP filed a
tariff establishing the initial interstate rate for movements on the Sepulveda
pipeline at five cents per barrel. Several shippers protested that rate.
In December 1997, SFPP filed an application for authority to charge a
market-based rate for the Sepulveda service, which application was protested by
several parties. On September 30, 1998, the FERC issued an order finding that
SFPP lacks market power in the Watson Station destination market and set a
hearing to determine whether SFPP possessed market power in the origin market.
In December 2000, an administrative law judge found that SFPP possessed
market power over the Sepulveda origin market. On February 28, 2003, the FERC
issued an order upholding that decision. SFPP filed a request for rehearing of
that order on March 31, 2003. The FERC denied SFPP's request for rehearing on
July 9, 2003.
As part of its February 28, 2003 order denying SFPP's application for
market-based ratemaking authority, the FERC remanded to the ongoing litigation
in Docket No. OR96-2, et al. the question of whether SFPP's current rate for
service on the Sepulveda pipeline is just and reasonable. Hearings in this
proceeding were held in February and March 2005. SFPP asserted various defenses
against the shippers' claims for reparations and refunds, including the
existence of valid contracts with the shippers and grandfathering protection. In
August 2005, the presiding administrative law judge issued an initial decision
finding that for the period from 1993 to November 1997 (when the Sepulveda FERC
tariff went into effect) the Sepulveda rate should have been lower. The
administrative law judge recommended that SFPP pay reparations and refunds for
alleged overcollections. SFPP filed in October 2005 a brief to the FERC taking
exception to this and other portions of the initial decision.
OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar
Diamond Shamrock Corporation filed a complaint at the FERC (Docket No. OR97-2)
challenging SFPP's West Line rates, claiming they were unjust and unreasonable
and no longer subject to grandfathering. In October 1997, ARCO, Mobil and Texaco
filed a complaint at the FERC (Docket No. OR98-1) challenging the justness and
reasonableness of all of SFPP's interstate rates, raising claims against SFPP's
East and West Line rates similar to those that have been at issue in Docket Nos.
OR92-8, et al. discussed above, but expanding them to include challenges to
SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno,
Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line. In
November 1997, Ultramar filed a similar, expanded complaint (Docket No. OR98-2).
Tosco Corporation filed a similar complaint in April 1998. The shippers seek
both reparations and prospective rate reductions for movements on all of SFPP's
lines. The FERC accepted the complaints and consolidated them into one
proceeding (Docket No. OR96-2, et al.), but held them in abeyance pending a FERC
decision on review of the initial decision in Docket Nos. OR92-8, et al.
In a companion order to Opinion No. 435, the FERC gave the complainants an
opportunity to amend their complaints in light of Opinion No. 435, which the
complainants did in January 2000. In August 2000, Navajo and Western filed
complaints against SFPP's East Line rates and Ultramar filed an additional
complaint updating its pre-existing challenges to SFPP's interstate pipeline
rates. These complaints were consolidated with the ongoing proceeding in Docket
No. OR96-2, et al.
A hearing in this consolidated proceeding was held from October 2001 to
March 2002. A FERC administrative law judge issued his initial decision in June
2003. The initial decision found that, for the years at issue, the complainants
had shown substantially changed circumstances for rates on SFPP's West, North
and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson
Station and thus found that those rates should not be "grandfathered" under the
Energy Policy Act of 1992. The initial decision also found that most of SFPP's
rates at issue were unjust and unreasonable.
On March 26, 2004, the FERC issued an order on the phase one initial
decision. The FERC's phase one order reversed the initial decision by finding
that SFPP's rates for its North and Oregon Lines should remain "grandfathered"
and amended the initial decision by finding that SFPP's West Line rates (i) to
Yuma, Tucson and CalNev, as of 1995, and (ii) to Phoenix, as of 1997, should no
longer be "grandfathered" and are not just and
13
reasonable. The FERC upheld these findings in its June 1, 2005 order, although
it appears to have found substantially changed circumstances as to SFPP's West
Line rates on a somewhat different basis than in the phase one order. The FERC's
phase one order did not address prospective West Line rates and whether
reparations were necessary. As discussed below, those issues have been addressed
in the FERC's December 16, 2005 order on phase two issues. The FERC's phase one
order also did not address the "grandfathered" status of the Watson Station fee,
noting that it would address that issue once it was ruled on by the Court of
Appeals in its review of the FERC's Opinion No. 435 orders; as noted above, the
FERC held in its June 1, 2005 order that the Watson Station fee is not
grandfathered. Several of the participants in the proceeding requested rehearing
of the FERC's phase one order. The FERC denied those requests in its June 1,
2005 order. In addition, several participants, including SFPP, filed petitions
with the United States Court of Appeals for the District of Columbia Circuit for
review of the FERC's phase one order. On August 13, 2004, the FERC filed a
motion to dismiss the pending petitions for review of the phase one order, which
Petitioners, including SFPP, answered on August 30, 2004. On December 20, 2004,
the Court of Appeals referred the FERC's motion to the merits panel and directed
the parties to address the issues in that motion on brief, thus effectively
dismissing the FERC's motion. In the same order, the Court of Appeals granted a
motion to hold the petitions for review of the FERC's phase one order in
abeyance and directed the parties to file motions to govern future proceeding 30
days after FERC disposition of the pending rehearing requests. In August 2005,
the FERC and SFPP jointly moved that the Court of Appeals hold the petitions for
review of the March 26, 2004 and June 1, 2005 orders in abeyance due to the
pendency of further action before the FERC on income tax allowance issues. In
December 2005, the Court of Appeals denied this motion and placed the petitions
seeking review of the two orders on the active docket.
The FERC's phase one order also held that SFPP failed to seek authorization
for the accounting entries necessary to reflect in SFPP's books, and thus in its
annual report to the FERC ("FERC Form 6"), the purchase price adjustment ("PPA")
arising from our 1998 acquisition of SFPP. The phase one order directed SFPP to
file for permission to reflect the PPA in its FERC Form 6 for the calendar year
1998 and each subsequent year. In its April 26, 2004 compliance filing, SFPP
noted that it had previously requested such permission and that the FERC's
regulations require an oil pipeline to include a PPA in its Form 6 without first
seeking FERC permission to do so. Several parties protested SFPP's compliance
filing. In its June 1, 2005 order, the FERC accepted SFPP's compliance filing.
In the June 1, 2005 order, the FERC directed SFPP to file a brief
addressing whether the records developed in the OR92-8 and OR96-2 cases were
sufficient to determine SFPP's entitlement to include an income tax allowance in
its rates under the FERC's new policy statement. On June 16, 2005, SFPP filed
its brief reviewing the pertinent records in the pending cases and applicable
law and demonstrating its entitlement to a full income tax allowance in its
interstate rates. SFPP's opponents in the two cases filed reply briefs
contesting SFPP's presentation. It is not possible to predict with certainty the
ultimate resolution of this issue, particularly given 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 in OR96-2
issued his initial decision in the phase two portion of this proceeding,
recommending establishment of prospective rates and the calculation of
reparations for complaining shippers with respect to the West Line and East
Line, relying upon cost of service determinations generally unfavorable to SFPP.
On December 16, 2005, the FERC issued an order addressing issues remanded
by the Court of Appeals in the Docket No. OR92-8 proceeding (discussed above)
and the phase two cost of service issues, including income tax allowance issues
arising from the briefing directed by the FERC's June 1, 2005 order. The FERC
directed SFPP to submit compliance filings and revised tariffs by February 28,
2006 (as extended to March 7, 2006) which were to address, in addition to the
OR92-8 matters discussed above, the establishment of interim West Line rates
based on a 1999 test year, indexed forward to a May 1, 2006 effective date and
estimated reparations. The FERC also resolved favorably a number of
methodological issues regarding the calculation of SFPP's income tax allowance
under the May 2005 policy statement and, in its compliance filings, directed
SFPP to submit further information establishing the amount of its income tax
allowance for the years at issue in the OR92-8 and OR96-2 proceedings.
SFPP and Navajo have filed requests for rehearing of the December 16, 2005
order. ExxonMobil, BP West Coast Products, Chevron, Ultramar, and ConocoPhillips
have filed petitions for review of the December 16, 2005 order with the United
States Court of Appeals for the District of Columbia Circuit. On February 13,
2006, the
14
FERC issued an order addressing the pending rehearing requests, granting the
majority of SFPP's requested changes regarding reparations and methodological
issues. SFPP, Navajo, and other parties have filed petitions for review of the
December 16, 2005 and February 13, 2006 orders with the United States Court of
Appeals for the District of Columbia Circuit.
On March 7, 2006, SFPP filed its compliance filings and revised tariffs.
Various shippers filed protests of the tariffs. On April 21, 2006, various
parties submitted comments challenging aspects of the costs of service and rates
reflected in the compliance filings and tariffs. On April 28, 2006, the FERC
issued an order accepting SFPP's tariffs lowering its West Line and East Line
rates in conformity with the FERC's December 2005 and February 2006 orders. On
May 1, 2006, these lower tariff rates became effective. The FERC indicated that
a subsequent order would address the issues raised in the comments. On May 1,
2006, SFPP filed reply comments.
We are not able to predict with certainty the final outcome of the pending
FERC proceedings involving SFPP, should they be carried through to their
conclusion, or whether we can reach a settlement with some or all of the
complainants. The final outcome will depend, in part, on the outcomes of the
appeals of these proceedings and the OR92-8, et al. proceedings taken by SFPP,
complaining shippers, and an intervenor.
We estimated, as of December 31, 2003, that shippers' claims for
reparations totaled approximately $154 million and that prospective rate
reductions would have an aggregate average annual impact of approximately $45
million, with the reparations amount and interest increasing as the timing for
implementation of rate reductions and the payment of reparations has extended
(estimated at a quarterly increase of approximately $9 million). Based on the
December 16, 2005 order, rate reductions will be implemented on May 1, 2006. We
now assume that reparations and accrued interest thereon will be paid no earlier
than the first quarter of 2007; however, the timing, and nature, of any rate
reductions and reparations that may be ordered will likely be affected by the
final disposition of the application of the FERC's new policy statement on
income tax allowances to our Pacific operations in the FERC Docket Nos. OR92-8
and OR96-2 proceedings. In 2005, we recorded an accrual of $105.0 million for an
expense attributable to an increase in our reserves related to our rate case
liability. We had previously estimated the combined annual impact of the rate
reductions and the payment of reparations sought by shippers would be
approximately 15 cents of distributable cash flow per unit. Based on our review
of the FERC's December 16, 2005 order and the FERC's February 13, 2006 order on
rehearing, and subject to the ultimate resolution of these issues in our
compliance filings and subsequent judicial appeals, we now expect the total
annual impact will be less than 15 cents per unit. The actual, partial year
impact on 2006 distributable cash flow per unit will likely be closer to 5 cents
per unit.
Chevron complaint OR02-4 and OR03-5 proceedings. On February 11, 2002,
Chevron, an intervenor in the Docket No. OR96-2, et al. proceeding, filed a
complaint against SFPP in Docket No. OR02-4 along with a motion to consolidate
the complaint with the Docket No. OR96-2, et al. proceeding. On May 21, 2002,
the FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed
a request for rehearing, which the FERC dismissed on September 25, 2002. In
October 2002, Chevron filed a request for rehearing of the FERC's September 25,
2002 Order, which the FERC denied on May 23, 2003. On July 1, 2003, Chevron
filed a petition for review of this denial at the U.S. Court of Appeals for the
District of Columbia Circuit.
On June 30, 2003, Chevron filed another complaint against SFPP (OR03-5) -
substantially similar to its previous complaint - and moved to consolidate the
complaint with the Docket No. OR96-2, et al. proceeding. Chevron requested that
this new complaint be treated as if it were an amendment to its complaint in
Docket No. OR02-4, which was previously dismissed by the FERC. By this request,
Chevron sought to, in effect, back-date its complaint, and claim for
reparations, to February 2002. SFPP answered Chevron's complaint on July 22,
2003, opposing Chevron's requests. On October 28, 2003, the FERC accepted
Chevron's complaint, but held it in abeyance pending the outcome of the Docket
No. OR96-2, et al. proceeding. The FERC denied Chevron's request for
consolidation and for back-dating. On November 21, 2003, Chevron filed a
petition for review of the FERC's October 28, 2003 order at the Court of Appeals
for the District of Columbia Circuit.
On August 18, 2003, SFPP filed a motion to dismiss Chevron's petition for
review in OR02-4 on the basis that Chevron lacks standing to bring its appeal
and that the case is not ripe for review. Chevron answered on September 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.
15
On January 8, 2004, the Court of Appeals granted Chevron's motion to have its
appeal of the FERC's decision in OR03-5 consolidated with Chevron's appeal of
the FERC's decision in the OR02-4 proceeding. Following motions to dismiss by
the FERC and SFPP, on December 10, 2004, the Court dismissed Chevron's petition
for review in Docket No. OR03-5 and set Chevron's appeal of the FERC's orders in
OR02-4 for briefing. On January 4, 2005, the Court granted Chevron's request to
hold such briefing in abeyance until after final disposition of the OR96-2
proceeding. Chevron continues to participate in the Docket No. OR96-2 et al.
proceeding as an intervenor.
Airlines OR04-3 proceeding. On September 21, 2004, America West Airlines,
Inc., Southwest Airlines, Co., Northwest Airlines, Inc. and Continental
Airlines, Inc. (collectively, the "Airlines") filed a complaint against SFPP at
the FERC. The Airlines' complaint alleges that the rates on SFPP's West Line and
SFPP's charge for its gathering enhancement service at Watson Station are not
just and reasonable. The Airlines seek rate reductions and reparations for two
years prior to the filing of their complaint. BP West Coast Products LLC and
ExxonMobil Oil Corporation, ConocoPhillips Company, Navajo Refining Company,
L.P., and ChevronTexaco Products Company all filed timely motions to intervene
in this proceeding. Valero Marketing and Supply Company filed a motion to
intervene one day after the deadline. SFPP answered the Airlines' complaint on
October 12, 2004. On October 29, 2004, the Airlines filed a response to SFPP's
answer and on November 12, 2004, SFPP replied to the Airlines' response. In
March and June 2005, the Airlines filed motions seeking expedited action on
their complaint, and in July 2005, the Airlines filed a motion seeking to sever
issues related to the Watson Station gathering enhancement fee from the OR04-3
proceeding and consolidate them in the proceeding regarding the justness and
reasonableness of that fee that the FERC docketed as part of the June 1, 2005
order. In August 2005, the FERC granted the Airlines' motion to sever and
consolidate the Watson Station fee issues.
OR05-4 and OR05-5 proceedings. On December 22, 2004, BP West Coast Products
LLC and ExxonMobil Oil Corporation filed a complaint against SFPP at the FERC,
which the FERC docketed as OR05-4. The complaint alleges that SFPP's interstate
rates are not just and reasonable, that certain rates found grandfathered by the
FERC are not entitled to such status, and, if so entitled, that "substantially
changed circumstances" have occurred, removing such protection. The complainants
seek rate reductions and reparations for two years prior to the filing of their
complaint and ask that the complaint be consolidated with the Airlines'
complaint in the OR04-3 proceeding. ConocoPhillips Company, Navajo Refining
Company, L.P., and Western Refining Company, L.P. all filed timely motions to
intervene in this proceeding. SFPP answered the complaint on January 24, 2005.
On December 29, 2004, ConocoPhillips filed a complaint against SFPP at the
FERC, which the FERC docketed as OR05-5. The complaint alleges that SFPP's
interstate rates are not just and reasonable, that certain rates found
grandfathered by the FERC are not entitled to such status, and, if so entitled,
that "substantially changed circumstances" have occurred, removing such
protection. ConocoPhillips seeks rate reductions and reparations for two years
prior to the filing of their complaint. BP West Coast Products LLC and
ExxonMobil Oil Corporation, Navajo Refining Company, L.P., and Western Refining
Company, L.P. all filed timely motions to intervene in this proceeding. SFPP
answered the complaint on January 28, 2005.
On February 25, 2005, the FERC consolidated the complaints in Docket Nos.
OR05-4 and OR05-5 and held them in abeyance until after the conclusion of the
various pending SFPP proceedings, deferring any ruling on the validity of the
complaints. On March 28, 2005, BP West Coast and ExxonMobil requested rehearing
of one aspect of the February 25, 2005 order; they argued that any tax allowance
matters in these proceedings could not be decided in, or as a result of, the
FERC's inquiry into income tax allowance in Docket No. PL05-5. On June 8, 2005,
the FERC denied the request for rehearing.
Consolidated Complaints. On February 13, 2006, the FERC consolidated the
complaints in Docket Nos. OR03-5, OR04-3, OR05-4, and OR05-5 and set for hearing
the portions of those complaints attacking SFPP's North Line and Oregon Line
rates, which rates remain grandfathered under the Energy Policy Act of 1992. A
procedural schedule, leading to hearing in early 2007, has been established in
that consolidated proceeding. Contemporaneously, settlement negotiations, under
the auspices of a FERC settlement judge are proceeding. The FERC also indicated
in its order that it would address the remaining portions of these complaints in
the context of its disposition of SFPP's compliance filings in the OR92-8/OR96-2
proceedings.
North Line rate case, IS05-230 proceeding. In April 2005, SFPP filed to
increase its North Line interstate rates to reflect increased costs, principally
due to the installation of replacement pipe between Concord and Sacramento,
16
California. Under FERC regulations, SFPP was required to demonstrate that there
was a substantial divergence between the revenues generated by its existing
North Line rates and its increased costs. SFPP's rate increase was protested by
various shippers and accepted subject to refund by the FERC. A hearing was held
in January and February 2006, and the case has now been briefed to the
administrative law judge.
Trailblazer Pipeline Company
On March 22, 2005, Marathon Oil Company filed a formal complaint with the
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 requested 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 asked the FERC to require Trailblazer to
bill Marathon the Expansion 2002 recourse rate for future billings. Marathon
estimated that the amount of Trailblazer's refund obligation at the time of the
filing was 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
of the May 20, 2005 order. On January 19, 2006, the FERC issued an order which
denied Marathon's rehearing request.
California Public Utilities Commission Proceeding
ARCO, Mobil and Texaco filed a complaint against SFPP with the California
Public Utilities Commission on April 7, 1997. The complaint challenges rates
charged by SFPP for intrastate transportation of refined petroleum products
through its pipeline system in the State of California and requests prospective
rate adjustments. On October 1, 1997, the complainants filed testimony seeking
prospective rate reductions aggregating approximately $15 million per year.
On August 6, 1998, the CPUC issued its decision dismissing the
complainants' challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC
granted limited rehearing of its August 1998 decision for the purpose of
addressing the proper ratemaking treatment for partnership tax expenses, the
calculation of environmental costs and the public utility status of SFPP's
Sepulveda Line and its Watson Station gathering enhancement facilities. In
pursuing these rehearing issues, complainants sought prospective rate reductions
aggregating approximately $10 million per year.
On March 16, 2000, SFPP filed an application with the CPUC seeking
authority to justify its rates for intrastate transportation of refined
petroleum products on competitive, market-based conditions rather than on
traditional, cost-of-service analysis.
On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC
asserting that SFPP's California intrastate rates are not just and reasonable
based on a 1998 test year and requesting the CPUC to reduce SFPP's rates
prospectively. The amount of the reduction in SFPP rates sought by the
complainants is not discernible from the complaint.
The rehearing complaint was heard by the CPUC in October 2000 and the April
2000 complaint and SFPP's market-based application were heard by the CPUC in
February 2001. All three matters stand submitted as of April 13, 2001, and
resolution of these submitted matters may occur within the second quarter of
2006.
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
17
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 second quarter of 2006.
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 third quarter of 2006.
We currently believe the CPUC complaints seek approximately $15 million in
tariff reparations and prospective annual tariff reductions, the aggregate
average annual impact of which would be approximately $31 million. There is no
way to quantify the potential extent to which the CPUC could determine that
SFPP's existing California rates are unreasonable. With regard to the amount of
dollars potentially subject to refund as a consequence of the CPUC resolution
requiring the provision by SFPP of cost-of-service data, referred to above, such
refunds could total about $6 million per year from October 2002 to the
anticipated date of a CPUC decision.
On January 26, 2006, SFPP filed a request for an annual rate increase of
approximately $5.4 million with the CPUC, to be effective as of March 2, 2006.
Protests to SFPP's rate increase application have been filed by Tesoro Refining
and Marketing Company, BP West Coast Products LLC, ExxonMobil Oil Corporation,
Southwest Airlines Company, Valero Marketing and Supply Company, Ultramar Inc.
and Chevron Products Company, asserting that the requested rate increase is
unreasonable. Pending the outcome of protests to SFPP's filing, the rate
increase, which will be collected in the form of a surcharge to existing rates,
will be collected subject to refund.
SFPP believes the submission of the required, representative cost data
required by the CPUC indicates that SFPP's existing rates for California
intrastate services remain reasonable and that no refunds are justified.
We believe that the resolution of such matters will not have a material
adverse effect on our business, financial position, results of operations or
cash flows.
Other Regulatory Matters
In addition to the matters described above, we may face additional
challenges to our rates in the future. Shippers on our pipelines do have rights
to challenge the rates we charge under certain circumstances prescribed by
applicable regulations. There can be no assurance that we will not face
challenges to the rates we receive for services on our pipeline systems in the
future or that such challenges will not have a material adverse effect on our
business, financial position, results of operations or cash flows. In addition,
since many of our assets are subject to regulation, we are subject to potential
future changes in applicable rules and regulations that may have a material
adverse effect on our business, financial position, results of operations or
cash flows.
Carbon Dioxide Litigation
Kinder Morgan CO2 Company, L.P., Kinder Morgan G.P., Inc., and Cortez
Pipeline Company were among the named defendants in Shores, et al. v. Mobil Oil
Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas
filed December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil
Corp., et al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed
March 29, 2001). These cases were originally filed as class actions on behalf of
classes of overriding royalty interest owners (Shores) and royalty interest
owners (Bank of Denton) for damages relating to alleged underpayment of
royalties on carbon dioxide produced from the McElmo Dome Unit. Although classes
were initially certified at the trial court level, appeals resulted in the
decertification and/or abandonment of the class claims. On February 22, 2005,
the trial judge dismissed both cases for lack of jurisdiction. Some of the
individual plaintiffs in these cases re-filed their claims in new lawsuits
(discussed below).
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On May 13, 2004, William Armor, one of the former plaintiffs in the Shores
matter whose claims were dismissed by the Court of Appeals for improper venue,
filed a new case alleging the same claims for underpayment of royalties against
the same defendants previously sued in the Shores case, including Kinder Morgan
CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. Armor v. Shell Oil
Company, et al, No. 04-03559 (14th Judicial District Court, Dallas County, Texas
filed May 13, 2004). Defendants filed their answers and special exceptions on
June 4, 2004. Trial is presently scheduled to occur on June 12, 2006, but will
likely take place in late 2006 on account of an uncontested motion filed by the
Plaintiffs to continue the trial date.
On May 20, 2005, Josephine Orr Reddy and Eastwood Capital, Ltd., two of the
former plaintiffs in the Bank of Denton matter, filed a new case in Dallas state
district court alleging the same claims for underpayment of royalties. Reddy and
Eastwood Capital, Ltd. v. Shell Oil Company, et al., No. 05-5021 (193rd Judicial
District Court, Dallas County, Texas filed May 20, 2005). The defendants include
Kinder Morgan CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. On June
23, 2005, the plaintiff in the Armor lawsuit filed a motion to transfer and
consolidate the Reddy lawsuit with the Armor lawsuit. On June 28, 2005, the
court in the Armor lawsuit granted the motion to transfer and consolidate and
ordered that the Reddy lawsuit be transferred and consolidated into the Armor
lawsuit. The defendants filed their answer and special exceptions on August 10,
2005. The consolidated Armor/Reddy trial is presently scheduled to occur on June
12, 2006, but will likely take place in late 2006 on account of an uncontested
motion filed by the Plaintiffs to continue the trial date.
Shell CO2 Company, Ltd., predecessor in interest to Kinder Morgan CO2
Company, L.P., is among the named counter-claim defendants in Shell Western E&P
Inc. v. Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial
District Court, Harris County, Texas filed June 17, 1998) (the "Bailey State
Court Action"). The counter-claim plaintiffs are overriding royalty interest
owners in the McElmo Dome Unit and have sued seeking damages for underpayment of
royalties on carbon dioxide produced from the McElmo Dome Unit. In the Bailey
State Court Action, the counter-claim plaintiffs asserted claims for
fraud/fraudulent inducement, real estate fraud, negligent misrepresentation,
breach of fiduciary duty, breach of contract, negligence, negligence per se,
unjust enrichment, violation of the Texas Securities Act, and open account. The
trial court in the Bailey State Court Action granted a series of summary
judgment motions filed by the counter-claim defendants on all of the
counter-plaintiffs' counter-claims except for the fraud-based claims. In 2004,
one of the counter-plaintiffs (Gerald Bailey) amended his counter-suit to allege
purported claims as a private relator under the False Claims Act and antitrust
claims. The federal government elected to not intervene in the False Claims Act
counter-suit. On March 24, 2005, Bailey filed a notice of removal, and the case
was transferred to federal court. Shell Western E&P Inc. v. Gerald O. Bailey and
Bridwell Oil Company, No. H-05-1029 (S.D. Tex., Houston Division removed March
24, 2005) (the "Bailey Houston Federal Court Action"). Also on March 24, 2005,
Bailey filed an instrument under seal in the Bailey Houston Federal Court Action
that was later determined to be a motion to transfer venue of that case to the
federal district court of Colorado, in which Bailey and two other plaintiffs
have filed another suit against Kinder Morgan CO2 Company, L.P. asserting claims
under the False Claims Act. The Houston federal district judge ordered that
Bailey take steps to have the False Claims Act case pending in Colorado
transferred to the Bailey Houston Federal Court Action, and also suggested that
the claims of other plaintiffs in other carbon dioxide litigation pending in
Texas should be transferred to the Bailey Houston Federal Court Action. In
response to the court's suggestion, the case of Gary Shores et al. v. ExxonMobil
Corp. et al., No. 05-1825 (S.D. Tex., Houston Division) was consolidated with
the Bailey Houston Federal Court Action on July 18, 2005. That case, in which
the plaintiffs assert claims for McElmo Dome royalty underpayment, includes
Kinder Morgan CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., and Cortez
Pipeline Company as defendants. Bailey requested the Houston federal district
court to transfer the Bailey Houston Federal Court Action to the federal
district court of Colorado. Bailey also filed a petition for writ of mandamus in
the Fifth Circuit Court of Appeals, asking that the Houston federal district
court be required to transfer the case to the federal district court of
Colorado. On June 3, 2005, the Fifth Circuit Court of Appeals denied Bailey's
petition for writ of mandamus. On June 22, 2005, the Fifth Circuit denied
Bailey's petition for rehearing en banc. On September 14, 2005, Bailey filed a
petition for writ of certiorari in the United States Supreme Court, which the
U.S. Supreme Court denied on November 28, 2005. On November 21, 2005, the
federal district court in Colorado transferred Bailey's False Claims Act case
pending in Colorado to the Houston federal district court. On November 30, 2005,
Bailey filed a petition for mandamus seeking to vacate the transfer. The Tenth
Circuit Court of Appeals denied the petition on December 19, 2005. The U.S.
Supreme Court has denied Bailey's petition for writ of certiorari. The Houston
federal district court subsequently realigned the parties in the Bailey Houston
Federal Court Action. Pursuant to the Houston federal district court's order,
Bailey and the other realigned plaintiffs have filed amended complaints in which
they assert claims for fraud/fraudulent inducement, real
19
estate fraud, negligent misrepresentation, breach of fiduciary and agency
duties, breach of contract and covenants, violation of the Colorado Unfair
Practices Act, civil theft under Colorado law, conspiracy, unjust enrichment,
and open account. Bailey also asserted claims as a private relator under the
False Claims Act and for violation of federal and Colorado antitrust laws. The
realigned plaintiffs seek actual damages, treble damages, punitive damages, a
constructive trust and accounting, and declaratory relief. The Shell and Kinder
Morgan defendants, along with Cortez Pipeline Company and ExxonMobil defendants,
have filed motions for summary judgment on all claims. No current trial date is
set.
On March 1, 2004, Bridwell Oil Company, one of the named
defendants/realigned plaintiffs in the Bailey actions, filed a new matter in
which it asserts claims which are virtually identical to the counter-claims it
asserts against Shell CO2 Company, Ltd. in the Bailey lawsuit. Bridwell Oil Co.
v. Shell Oil Co. et al, No. 160,199-B (78th Judicial District Court, Wichita
County, Texas filed March 1, 2004). The defendants in this action include Kinder
Morgan CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., various Shell
entities, ExxonMobil entities, and Cortez Pipeline Company. On June 25, 2004,
defendants filed answers, special exceptions, pleas in abatement, and motions to
transfer venue back to the Harris County District Court. On January 31, 2005,
the Wichita County judge abated the case pending resolution of the Bailey State
Court Action. The case remains abated.
On April 7, 2006, Harry Ptasynski, one of the plaintiffs in the Colorado
federal action filed by Bailey under the False Claims Act (which was transferred
to the Bailey Houston Federal Court Action as described above), filed suit
against Kinder Morgan G.P., Inc. in Colorado federal district court. Harry
Ptasynski v. Kinder Morgan G.P., Inc., No. 06-CV-00651 (LTB) (U.S. District
Court for the District of Colorado). Ptasynski, who holds an overriding royalty
interest at McElmo Dome, asserts claims for civil conspiracy, violation of the
Colorado Organized Crime Control Act, violation of Colorado antitrust laws,
violation of the Colorado Unfair Practices Act, breach of fiduciary duty and
confidential relationship, violation of the Colorado Payment of Proceeds Act,
fraudulent concealment, breach of contract and implied duties to market and good
faith and fair dealing, and civil theft and conversion. Ptasynski seeks actual
damages, treble damages, forfeiture, disgorgement, and declaratory and
injunctive relief. Kinder Morgan G.P., Inc. intends to seek dismissal of the
case or, alternatively, transfer of the case to the Bailey Houston Federal Court
Action. No trial date is currently set.
Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company are among the
named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al.,
No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case
involves claims by overriding royalty interest owners in the McElmo Dome and Doe
Canyon Units seeking damages for underpayment of royalties on carbon dioxide
produced from the McElmo Dome Unit, failure to develop carbon dioxide reserves
at the Doe Canyon Unit, and failure to develop hydrocarbons at both McElmo Dome
and Doe Canyon. The plaintiffs also possess a small working interest at Doe
Canyon. Plaintiffs claim breaches of contractual and potential fiduciary duties
owed by the defendants and also allege other theories of liability including
breach of covenants, civil theft, conversion, fraud/fraudulent concealment,
violation of the Colorado Organized Crime Control Act, deceptive trade
practices, and violation of the Colorado Antitrust Act. In addition to actual or
compensatory damages, plaintiffs seek treble damages, punitive damages, and
declaratory relief relating to the Cortez Pipeline tariff and the method of
calculating and paying royalties on McElmo Dome carbon dioxide. The Court denied
plaintiffs' motion for summary judgment concerning alleged underpayment of
McElmo Dome overriding royalties on March 2, 2005. The parties are continuing to
engage in discovery. No trial date is currently set.
Cortez Pipeline Company and Kinder Morgan CO2 Company, L.P., successor in
interest to Shell CO2 Company, Ltd., are among the named defendants in CO2
Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November
28, 2005. The arbitration arises from a dispute over a class action settlement
agreement which became final on July 7, 2003 and disposed of five lawsuits
formerly pending in the U.S. District Court, District of Colorado. The
plaintiffs in such lawsuits primarily included overriding royalty interest
owners, royalty interest owners, and small share working interest owners who
alleged underpayment of royalties and other payments on carbon dioxide produced
from the McElmo Dome Unit in southwest Colorado. The settlement imposed certain
future obligations on the defendants in the underlying litigation. The plaintiff
in the current arbitration is an entity that was formed as part of the
settlement for the purpose of monitoring compliance with the obligations imposed
by the settlement agreement. The plaintiff alleges that, in calculating royalty
and other payments, defendants used a transportation expense in excess of what
is allowed by the settlement agreement, thereby causing alleged underpayments of
approximately $10.3 million. The plaintiff also alleges that Cortez Pipeline
Company should have used certain
20
funds to further reduce its debt, which, in turn, would have allegedly increased
the value of royalty and other payments by approximately $0.2 million.
Defendants deny that there was any breach of the settlement agreement. The
arbitration panel has issued various preliminary evidentiary rulings. The
arbitration is currently scheduled to commence on June 26, 2006.
J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD,
individually and on behalf of all other private royalty and overriding royalty
owners in the Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v.
Kinder Morgan CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court,
Union County New Mexico)
This case involves a purported class action against Kinder Morgan CO2
Company, L.P. alleging that it has failed to pay the full royalty and overriding
royalty ("royalty interests") on the true and proper settlement value of
compressed carbon dioxide produced from the Bravo Dome Unit in the period
beginning January 1, 2000. The complaint purports to assert claims for violation
of the New Mexico Unfair Practices Act, constructive fraud, breach of contract
and of the covenant of good faith and fair dealing, breach of the implied
covenant to market, and claims for an accounting, unjust enrichment, and
injunctive relief. The purported class is comprised of current and former
owners, during the period January 2000 to the present, who have private property
royalty interests burdening the oil and gas leases held by the defendant,
excluding the Commissioner of Public Lands, the United States of America, and
those private royalty interests that are not unitized as part of the Bravo Dome
Unit. The plaintiffs allege that they were members of a class previously
certified as a class action by the United States District Court for the District
of New Mexico in the matter Doris Feerer, et al. v. Amoco Production Company, et
al., USDC N.M. Civ. No. 95-0012 (the "Feerer Class Action"). Plaintiffs allege
that Kinder Morgan CO2 Company's method of paying royalty interests is contrary
to the settlement of the Feerer Class Action. Kinder Morgan CO2 Company has
filed a motion to compel arbitration of this matter pursuant to the arbitration
provisions contained in the Feerer Class Action settlement agreement, which
motion was denied by the trial court. An appeal of that ruling has been filed
and is pending before the New Mexico Court of Appeals. Oral arguments took place
before the New Mexico Court of Appeals on March 23, 2006. No date for
arbitration or trial is currently set.
In addition to the matters listed above, various audits and administrative
inquiries concerning Kinder Morgan CO2 Company L.P.'s royalty and tax payments
on carbon dioxide produced from the McElmo Dome Unit are currently ongoing.
These audits and inquiries involve various federal agencies, the State of
Colorado, the Colorado oil and gas commission, and Colorado county taxing
authorities.
Commercial Litigation Matters
Union Pacific Railroad Company Easements
SFPP, L.P. and Union Pacific Railroad Company (the successor to Southern
Pacific Transportation Company and referred to in this report as UPRR) are
engaged in two proceedings to determine the extent, if any, to which the rent
payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR
should be adjusted pursuant to existing contractual arrangements for each of the
ten year periods beginning January 1, 1994 and January 1, 2004 (Southern Pacific
Transportation Company vs. Santa Fe Pacific Corporation, SFP Properties, Inc.,
Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al., Superior Court of the
State of California for the County of San Francisco, filed August 31, 1994; and
Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P.,
Kinder Morgan Operating L.P. "D", Kinder Morgan G.P., Inc., et al., Superior
Court of the State of California for the County of Los Angeles, filed July 28,
2004).
With regard to the first proceeding, covering the ten year period beginning
January 1, 1994, the trial court, on July 16, 2003, set the rent for years 1994
- - 2003 at approximately $5.0 million per year as of January 1, 1994, subject to
annual inflation increases throughout the ten year period. On February 23, 2005,
the California Court of Appeals affirmed the trial court's ruling, except that
it reversed a small portion of the decision and remanded it back to the trial
court for determination. On remand, the trial court held that there was no
adjustment to the rent relating to the portion of the decision that was
reversed, but awarded Southern Pacific Transportation Company interest on rental
amounts owing as of May 7, 1997.
21
In April 2006, we paid UPRR $15.3 million in satisfaction of our rental
obligations through December 31, 2003. However, we do not believe that the
assessment of interest awarded Southern Pacific Transportation Company on rental
amounts owing as of May 7, 1997 was proper, and we are seeking appellate review
of the interest award.
In addition, SFPP, L.P. and UPRR are engaged in a second proceeding to
determine the extent, if any, to which the rent payable by SFPP for the use of
pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to
existing contractual arrangements for the ten year period beginning January 1,
2004 (Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP,
L.P., Kinder Morgan Operating L.P. "D", Kinder Morgan G.P., Inc., et al.,
Superior Court of the State of California for the County of Los Angeles, filed
July 28, 2004). SFPP was served with this lawsuit on August 17, 2004. SFPP
expects that the trial in this matter will occur in late 2006.
SFPP and UPRR are also engaged in multiple disputes over the circumstances
under which SFPP must pay for a relocation of its pipeline within the UPRR right
of way and the safety standards that govern relocations. SFPP believes that it
must pay for relocation of the pipeline only when so required by the railroad's
common carrier operations, and in doing so, it need only comply with standards
set forth in the federal Pipeline Safety Act in conducting relocations. UPRR
contends that it has complete discretion to cause the pipeline to be relocated
at SFPP's expense at any time and for any reason, and that SFPP must comply with
the more expensive American Railway Engineering and Maintenance-of-Way
standards. Each party is seeking declaratory relief with respect to its
positions regarding relocations.
It is difficult to quantify the effects of the outcome of these cases on
SFPP because SFPP does not know UPRR's plans for projects or other activities
that would cause pipeline relocations. Even if SFPP is successful in advancing
its position, significant relocations for which SFPP must nonetheless bear the
expense (i.e. for railroad purposes, with the standards in the federal Pipeline
Safety Act applying) would have an adverse effect on our financial position and
results of operations. These effects would be even more in the event SFPP is
unsuccessful in one or more of these litigations.
RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et
al. (Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District).
On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with
the First Supplemental Petition filed by RSM Production Corporation on behalf of
the County of Zapata, State of Texas and Zapata County Independent School
District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition
to 15 other defendants, including two other Kinder Morgan affiliates. Certain
entities we acquired in the Kinder Morgan Tejas acquisition are also defendants
in this matter. The Petition alleges that these taxing units relied on the
reported volume and analyzed heating content of natural gas produced from the
wells located within the appropriate taxing jurisdiction in order to properly
assess the value of mineral interests in place. The suit further alleges that
the defendants undermeasured the volume and heating content of that natural gas
produced from privately owned wells in Zapata County, Texas. The Petition
further alleges that the County and School District were deprived of ad valorem
tax revenues as a result of the alleged undermeasurement of the natural gas by
the defendants. On December 15, 2001, the defendants filed motions to transfer
venue on jurisdictional grounds. On June 12, 2003, plaintiff served discovery
requests on certain defendants. On July 11, 2003, defendants moved to stay any
responses to such discovery.
United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil
Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado).
This action was filed on June 9, 1997 pursuant to the federal False Claims
Act and involves allegations of mismeasurement of natural gas produced from
federal and Indian lands. The Department of Justice has decided not to intervene
in support of the action. The complaint is part of a larger series of similar
complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately
330 other defendants). Certain entities we acquired in the Kinder Morgan Tejas
acquisition are also defendants in this matter. An earlier single action making
substantially similar allegations against the pipeline industry was dismissed by
Judge Hogan of the U.S. District Court for the District of Columbia on grounds
of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed
individual complaints in various courts throughout the country. In 1999, these
cases were consolidated by the Judicial Panel for Multidistrict Litigation, and
transferred to the District of Wyoming. The multidistrict litigation matter is
called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions
to dismiss were filed and an oral argument on the motion to dismiss occurred on
March 17, 2000. On July 20, 2000, the United States of America filed a motion to
dismiss those claims by Grynberg that deal with the manner in which defendants
valued gas produced from federal leases, referred to as valuation claims. Judge
Downes denied the defendant's motion to dismiss on May 18, 2001. The United
States' motion to dismiss most of plaintiff's valuation claims has been granted
by the court. Grynberg has appealed that dismissal to the 10th Circuit, which
has requested briefing regarding its jurisdiction over that appeal.
Subsequently, Grynberg's appeal was dismissed for lack of appellate
jurisdiction. Discovery to determine issues related to the Court's subject
matter jurisdiction arising out of the False Claims Act is complete. Briefing
has been completed and oral arguments on jurisdiction were held before the
Special Master on March 17 and 18, 2005. On May 7, 2003, Grynberg sought leave
to file a Third Amended Complaint, which adds allegations of undermeasurement
related to carbon dioxide production. Defendants have
22
filed briefs opposing leave to amend. Neither the Court nor the Special
Master has ruled on Grynberg's Motion to Amend.
On May 13, 2005, the Special Master issued his Report and Recommendations
to Judge Downes in the In Re Natural Gas Royalties Qui Tam Litigation, Docket
No. 1293. The Special Master found that there was a prior public disclosure of
the mismeasurement fraud Grynberg alleged, and that Grynberg was not an original
source of the allegations. As a result, the Special Master recommended dismissal
of the Kinder Morgan defendants on jurisdictional grounds. On June 27, 2005,
Grynberg filed a motion to modify and partially reverse the Special Master's
recommendations and the Defendants filed a motion to adopt the Special Master's
recommendations with modifications. An oral argument was held on December 9,
2005 on the motions concerning the Special Master's recommendations. It is
likely that Grynberg will appeal any dismissal to the 10th Circuit Court of
Appeals.
Weldon Johnson and Guy Sparks, individually and as Representative of Others
Similarly Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2 (Circuit
Court, Miller County Arkansas).
On October 8, 2004, plaintiffs filed the above-captioned matter against
numerous defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan
Energy Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder
Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.;
Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC;
and MidCon Corp. (the "Kinder Morgan Defendants"). The complaint purports to
bring a class action on behalf of those who purchased natural gas from the
CenterPoint defendants from October 1, 1994 to the date of class certification.
The complaint alleges that CenterPoint Energy, Inc., by and through its
affiliates, has artificially inflated the price charged to residential consumers
for natural gas that it allegedly purchased from the non-CenterPoint defendants,
including the above-listed Kinder Morgan entities. The complaint further alleges
that in exchange for CenterPoint's purchase of such natural gas at above market
prices, the non-CenterPoint defendants, including the above-listed Kinder Morgan
entities, sell natural gas to CenterPoint's non-regulated affiliates at prices
substantially below market, which in turn sells such natural gas to commercial
and industrial consumers and gas marketers at market price. The complaint
purports to assert claims for fraud, unlawful enrichment and civil conspiracy
against all of the defendants, and seeks relief in the form of actual, exemplary
and punitive damages, interest, and attorneys' fees. The parties have recently
concluded jurisdictional discovery and a hearing is scheduled for summer 2006 on
various defendants' assertion that the Arkansas courts lack personal
jurisdiction over them. Based on the information available to date and our
preliminary investigation, the Kinder Morgan Defendants believe that the claims
against them are without merit and intend to defend against them vigorously.
Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party
in interest for Enron Helium Company, a division of Enron Corp., Enron Liquids
Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder
Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252 (189th
Judicial District Court, Harris County, Texas)
On September 1, 2000, plaintiff Exxon Mobil Corporation filed its original
petition and application for declaratory relief against Kinder Morgan Operating
L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder
Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P.,
Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron
Helium Company. Plaintiff added Enron Corp. as party in interest for Enron
Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a
defendant. The claims against Enron Corp. were severed into a separate cause of
action. Plaintiff's claims are based on a gas processing agreement entered into
on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company
relating to gas produced in the Hugoton Field in Kansas and processed at the
Bushton Plant, a natural gas processing facility located in Kansas. Plaintiff
also asserts claims relating to the helium extraction agreement entered between
Enron Helium Company (a division of Enron Corp.) and Mobil Oil Corporation dated
March 14, 1988. Plaintiff alleges that defendants failed to deliver propane and
to allocate plant products to the 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, the 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
23
processing agreement, civil conspiracy, fraud, breach of a duty of good faith
and fair dealing, negligent misrepresentation and conversion. As of April 7,
2003, the plaintiff alleged economic damages for the period from November 1987
through March 1997 in the amount of $30.7 million. On May 2, 2003, the plaintiff
added claims for the period from April 1997 through February 2003 in the amount
of $12.9 million. On June 23, 2003, the plaintiff filed a fourth amended
petition that reduced its total claim for economic damages to $30.0 million. On
October 5, 2003, the plaintiff filed a fifth amended petition that purported to
add a cause of action for embezzlement. On February 10, 2004, the 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. On February 21, 2006, the Court of
Appeals unanimously affirmed the judgment in our favor entered by the trial
court, and ordered ExxonMobil to pay all costs incurred in the appeal.
ExxonMobil has not filed an appeal of this decision to the Texas Supreme Court,
so the matter is now concluded.
Cannon Interests-Houston v. Kinder Morgan Texas Pipeline, L.P., No.
2005-36174 (333rd Judicial District, Harris County, Texas).
On June 6, 2005, after unsuccessful mediation, Cannon Interests sued Kinder
Morgan Texas Pipeline, L.P., referred to in this report as KMTP, and alleged
breach of contract for the purchase of natural gas storage capacity and for
failure to pay under a profit-sharing arrangement. KMTP counterclaimed that
Cannon Interests failed to provide it with five billion cubic feet of winter
storage capacity in breach of the contract. The plaintiff is claiming
approximately $13 million in damages. A trial date has been set for September
18, 2006. KMTP will defend the case vigorously, and based upon the information
available to date, it believes that the claims against it are without merit and
will be more than offset by its claims against Cannon Interests.
Federal Investigation at Cora and Grand Rivers Coal Facilities
On June 22, 2005, we announced that the Federal Bureau of Investigation is
conducting an investigation related to our coal terminal facilities located in
Rockwood, Illinois and Grand Rivers, Kentucky. The investigation involves
certain coal sales from our Cora, Illinois and Grand Rivers, Kentucky coal
terminals that occurred from 1997 through 2001. During this time period, we sold
excess coal from these two terminals for our own account, generating less than
$15 million in total net sales. Excess coal is the weight gain that results from
moisture absorption into existing coal during transit or storage and from scale
inaccuracies, which are typical in the industry. During the years 1997 through
1999, we collected, and, from 1997 through 2001, we subsequently sold, excess
coal for our own account, as we believed we were entitled to do under
then-existing customer contracts.
We have conducted an internal investigation of the allegations and
discovered no evidence of wrongdoing or improper activities at these two
terminals. Furthermore, we have contacted customers of these terminals during
the applicable time period and have offered to share information with them
regarding our excess coal sales. Over the five year period from 1997 to 2001, we
moved almost 75 million tons of coal through these terminals, of which less than
1.4 million tons were sold for our own account (including both excess coal and
coal purchased on the open market). We have not added to our inventory of excess
coal since 1999 and we have not sold coal for our own account since 2001, except
for minor amounts of scrap coal. We are fully cooperating with federal law
enforcement authorities in this investigation. In September 2005 and subsequent
thereto, we responded to a subpoena in this matter by producing a large volume
of documents, which, we understand, are being reviewed by the FBI and auditors
from the Tennessee Valley Authority, which is a customer of the Cora and Grand
Rivers terminals. We do not expect that the resolution of the investigation will
have a material adverse impact on our business, financial position, results of
operations or cash flows.
Queen City Railcar Litigation
On August 28, 2005, a railcar containing the chemical styrene began leaking
styrene gas in Cincinnati, Ohio while en route to our Queen City Terminal. The
railcar was sent by the Westlake Chemical Corporation from Louisiana,
transported by Indiana & Ohio Railway, and consigned to Westlake at its
dedicated storage tank at Queen City Terminals, Inc., a subsidiary of Kinder
Morgan Bulk Terminals, Inc. The railcar leak resulted in the evacuation
24
of many residents and the alleged temporary closure of several businesses in the
Cincinnati area. Within three weeks of the incident, seven separate class action
complaints were filed in the Hamilton County Court of Common Pleas, including
case numbers: A0507115, A0507120, A0507121, A0507149, A0507322, A0507332, and
A0507913. In addition, a complaint was filed by the city of Cincinnati,
described further below.
On September 28, 2005, the court consolidated the complaints under
consolidated case number A0507913. Concurrently, thirteen designated class
representatives filed a Master Class Action Complaint against Westlake Chemical
Corporation, Indiana and Ohio Railway Corporation, Queen City Terminals, Inc.,
Kinder Morgan Liquids Terminals, LLC, Kinder Morgan GP, Inc. and Kinder Morgan
Energy Partners, L.P., collectively the defendants, in the Hamilton County Court
of Common Pleas, case number A0507105. The complaint alleges negligence,
absolute nuisance, nuisance, trespass, negligence per se, and strict liability
against all defendants stemming from the styrene leak. The complaint seeks
compensatory damages in excess of $25,000, punitive damages, pre and
post-judgment interest, and attorney fees. The claims against the Indiana and
Ohio Railway and Westlake are based generally on an alleged failure to deliver
the railcar in a timely manner which allegedly caused the styrene to become
unstable and leak from the railcar. The plaintiffs allege that we had a legal
duty to monitor the movement of the railcar en route to our terminal and
guarantee its timely arrival in a safe and stable condition.
On October 28, 2005, we filed an answer denying the material allegations of
the complaint. On December 1, 2005, the plaintiffs filed a motion for class
certification. On December 12, 2005, we filed a motion for an extension of time
to respond to plaintiffs' motion for class certification in order to conduct
discovery regarding class certification. On February 10, 2006, the court granted
our motion for additional time to conduct class discovery. The court has not
established a scheduling order or trial date, and discovery is ongoing.
On September 6, 2005, the city of Cincinnati, the plaintiff, filed a
complaint on behalf of itself and in parens patriae against Westlake, Indiana
and Ohio Railway, Kinder Morgan Liquids Terminals, LLC, Queen City Terminals,
Inc. and Kinder Morgan GP, Inc., collectively the defendants, in the Court of
Common Pleas, Hamilton County, Ohio, case number A0507323. Plaintiff's complaint
arose out of the same railcar incident reported immediately above. The
plaintiff's complaint alleges public nuisance, negligence, strict liability, and
trespass. The complaint seeks compensatory damages in excess of $25,000,
punitive damages, pre and post-judgment interest, and attorney fees. On
September 28, 2005, Kinder Morgan filed a motion to dismiss the parens patriae
claim. On December 15, 2005, Kinder Morgan filed a motion for summary judgment.
The plaintiff has not responded to either motion. A trial date has not been set.
Leukemia Cluster Litigation
We are a party to several lawsuits in Nevada that allege that the
plaintiffs have developed leukemia as a result of exposure to harmful
substances. Based on the information available to date, our own preliminary
investigation, and the positive results of investigations conducted by State and
Federal agencies, we believe that the claims against us in these matters are
without merit and intend to defend against them vigorously. The following is a
summary of these cases.
Marie Snyder, et al v. City of Fallon, United States Department of the
Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas
Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District
Court, District of Nevada)("Snyder"); Frankie Sue Galaz, et al v. United States
of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy
Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No.
cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)("Galaz
I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial District Court,
State of Nevada, County of Washoe) ("Galaz II"); Frankie Sue Galaz, et al v. The
United States of America, the City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC (United States District
Court, District of Nevada)("Galaz III")
On July 9, 2002, we were served with a purported complaint for class action
in the Snyder case, in which the plaintiffs, on behalf of themselves and others
similarly situated, assert that a leukemia cluster has developed in the
25
City of Fallon, Nevada. The complaint alleges that the plaintiffs have been
exposed to unspecified "environmental carcinogens" at unspecified times in an
unspecified manner and are therefore "suffering a significantly increased fear
of serious disease." The plaintiffs seek a certification of a class of all
persons in Nevada who have lived for at least three months of their first ten
years of life in the City of Fallon between the years 1992 and the present who
have not been diagnosed with leukemia.
The complaint purports to assert causes of action for nuisance and "knowing
concealment, suppression, or omission of material facts" against all defendants,
and seeks relief in the form of "a court-supervised trust fund, paid for by
defendants, jointly and severally, to finance a medical monitoring program to
deliver services to members of the purported class that include, but are not
limited to, testing, preventative screening and surveillance for conditions
resulting from, or which can potentially result from exposure to environmental
carcinogens," incidental damages, and attorneys' fees and costs.
The defendants responded to the complaint by filing motions to dismiss on
the grounds that it fails to state a claim upon which relief can be granted. On
November 7, 2002, the United States District Court granted the motion to dismiss
filed by the United States, and further dismissed all claims against the
remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs
filed a motion for reconsideration and leave to amend, which was denied by the
court on December 30, 2002. Plaintiffs filed a notice of appeal to the United
States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit
affirmed the dismissal of this case.
On December 3, 2002, plaintiffs filed an additional complaint for class
action in the Galaz I matter asserting the same claims in the same court on
behalf of the same purported class against virtually the same defendants,
including us. On February 10, 2003, the defendants filed motions to dismiss the
Galaz I Complaint on the grounds that it also fails to state a claim upon which
relief can be granted. This motion to dismiss was granted as to all defendants
on April 3, 2003. Plaintiffs filed a notice of appeal to the United States Court
of Appeals for the 9th Circuit. On November 17, 2003, the 9th Circuit dismissed
the appeal, upholding the District Court's dismissal of the case.
On June 20, 2003, plaintiffs filed an additional complaint for class action
(the "Galaz II" matter) asserting the same claims in Nevada State trial court on
behalf of the same purported class against virtually the same defendants,
including us (and excluding the United States Department of the Navy). On
September 30, 2003, the Kinder Morgan defendants filed a motion to dismiss the
Galaz II Complaint along with a motion for sanctions. On April 13, 2004,
plaintiffs' counsel voluntarily stipulated to a dismissal with prejudice of the
entire case in State Court. The court has accepted the stipulation and the case
was dismissed on April 27, 2004.
Also on June 20, 2003, the plaintiffs in the previously filed Galaz matters
(now dismissed) filed yet another complaint for class action in the United
States District Court for the District of Nevada (the "Galaz III" matter)
asserting the same claims in United States District Court for the District of
Nevada on behalf of the same purported class against virtually the same
defendants, including us. The Kinder Morgan defendants filed a motion to dismiss
the Galaz III matter on August 15, 2003. On October 3, 2003, the plaintiffs
filed a motion for withdrawal of class action, which voluntarily drops the class
action allegations from the matter and seeks to have the case proceed on behalf
of the Galaz family only. On December 5, 2003, the District Court granted the
Kinder Morgan defendants' motion to dismiss, but granted plaintiff leave to file
a second amended complaint. Plaintiff filed a second amended complaint on
December 13, 2003, and a third amended complaint on January 5, 2004. The Kinder
Morgan defendants filed a motion to dismiss the third amended complaint on
January 13, 2004. The motion to dismiss was granted with prejudice on April 30,
2004. On May 7, 2004, plaintiff filed a notice of appeal in the United States
Court of Appeals for the 9th Circuit. On March 31, 2006, the 9th Circuit
affirmed the District Court's dismissal of the case. On April 27, 2006,
plaintiff filed a motion for an en banc review of this decision by the full 9th
Circuit Court of Appeals. The Kinder Morgan defendants intend to oppose this
motion.
Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No.
CV03-03482 (Second Judicial District Court, State of Nevada, County of Washoe)
("Jernee").
On May 30, 2003, a separate group of plaintiffs, individually and on behalf
of Adam Jernee, filed a civil action in the Nevada State trial court against us
and several Kinder Morgan related entities and individuals and additional
unrelated defendants. Plaintiffs in the Jernee matter claim that defendants
negligently and intentionally failed to inspect, repair and replace unidentified
segments of their pipeline and facilities, allowing "harmful substances and
26
emissions and gases" to damage "the environment and health of human beings."
Plaintiffs claim that "Adam Jernee's death was caused by leukemia that, in turn,
is believed to be due to exposure to industrial chemicals and toxins."
Plaintiffs purport to assert claims for wrongful death, premises liability,
negligence, negligence per se, intentional infliction of emotional distress,
negligent infliction of emotional distress, assault and battery, nuisance,
fraud, strict liability (ultra hazardous acts), and aiding and abetting, and
seek unspecified special, general and punitive damages. The Jernee case has been
consolidated for pretrial purposes with the Sands case (see below). Plaintiffs
have filed a third amended complaint and all defendants have filed motions to
dismiss all causes of action excluding plaintiffs' cause of action for
negligence. Defendants have also filed motions to strike portions of the
complaint. These motions remain pending before the court. As is its practice,
the court has not scheduled argument on any such motions.
In addition to the above, the parties have filed motions to implement case
management orders, the Jernee matter having now been deemed "complex" by the
court. Such orders are designed to stage discovery, motions and pretrial
proceedings. The court initially entered the case management order proposed by
the defendants. Following plaintiffs' motion for reconsideration, however, the
court reversed itself, vacated the original case management order, and entered a
case management order submitted by the plaintiffs. Defendants plan to file a
motion to vacate this second case management order and re-institute the original
case management order.
Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326
(Second Judicial District Court, State of Nevada, County of Washoe) ("Sands").
On August 28, 2003, a separate group of plaintiffs, represented by the
counsel for the plaintiffs in the Jernee matter, individually and on behalf of
Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court
against us and several Kinder Morgan related entities and individuals and
additional unrelated defendants. The Kinder Morgan defendants were served with
the complaint on January 10, 2004. Plaintiffs in the Sands matter claim that
defendants negligently and intentionally failed to inspect, repair and replace
unidentified segments of their pipeline and facilities, allowing "harmful
substances and emissions and gases" to damage "the environment and health of
human beings." Plaintiffs claim that Stephanie Suzanne Sands' death was caused
by leukemia that, in turn, is believed to be due to exposure to industrial
chemicals and toxins. Plaintiffs purport to assert claims for wrongful death,
premises liability, negligence, negligence per se, intentional infliction of
emotional distress, negligent infliction of emotional distress, assault and
battery, nuisance, fraud, strict liability (ultra hazardous acts), and aiding
and abetting, and seek unspecified special, general and punitive damages. The
Sands case has been consolidated for pretrial purposes with the Jernee case (see
above). Plaintiffs have filed a second amended complaint and all defendants have
filed motions to dismiss all causes of action excluding plaintiffs' cause of
action for negligence. Defendants have also filed motions to strike portions of
the complaint. These motions remain pending before the court. As is its
practice, the court has not scheduled argument on any such motions.
In addition to the above, the parties have filed motions to implement case
management orders, the Sands matter having now been deemed "complex" by the
court. Such orders are designed to stage discovery, motions and pretrial
proceedings. The court initially entered the case management order proposed by
the defendants. Following plaintiffs' motion for reconsideration, however, the
court reversed itself, vacated the original case management order, and entered a
case management order submitted by the plaintiffs. Defendants plan to file a
motion to vacate this second case management order and re-institute the original
case management order.
Pipeline Integrity and Releases
Meritage Homes Corp., Monterey Homes Construction, Inc., and Monterey Homes
Arizona, Inc. v. Kinder Morgan Energy Partners, L.P. and SFPP Limited
Partnership, No. CIV 05 021 TUCCKJ, United States District Court, Arizona.
On January 28, 2005, Meritage Homes Corp. and its above-named affiliates
filed a complaint in the above-entitled action against Kinder Morgan Energy
Partners, L.P. and SFPP, L.P. The plaintiffs are homebuilders who constructed a
subdivision known as Silver Creek II located in Tucson, Arizona. Plaintiffs
allege that, as a result of a July 30, 2003 pipeline rupture and accompanying
release of petroleum products, soil and groundwater adjacent to, on and
underlying portions of Silver Creek II became contaminated. Plaintiffs allege
that they have incurred and continue to incur costs, damages and expenses
associated with the delay of closings of home sales within Silver
27
Creek II and damage to their reputation and goodwill as a result of the rupture
and release. Plaintiffs' complaint purports to assert claims for negligence,
breach of contract, trespass, nuisance, strict liability, subrogation and
indemnity, and negligence per se. Plaintiffs seek "no less than $1.5 million in
compensatory damages and necessary response costs," a declaratory judgment,
interest, punitive damages and attorneys' fees and costs. The parties have
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 installation project hired by East Bay Municipal Utility District
("EBMUD"), struck and ruptured an underground petroleum pipeline owned and
operated by SFPP, L.P. in Walnut Creek, California. An explosion occurred
immediately following the rupture that resulted in five fatalities and several
injuries to employees or contractors of Mountain Cascade. The explosion and fire
also caused other property damage.
On May 5, 2005, the California Division of Occupational Safety and Health
("CalOSHA") issued two civil citations against us relating to this incident
assessing civil fines of $140,000 based upon our alleged failure to mark the
location of the pipeline properly prior to the excavation of the site by the
contractor. CalOSHA, with the assistance of the Contra Costa County District
Attorney's office, is continuing to investigate the facts and circumstances
surrounding the incident for possible criminal violations. In addition, on June
27, 2005, the Office of the California State Fire Marshal, Pipeline Safety
Division ("CSFM") issued a Notice of Violation against us which also alleges
that we did not properly mark the location of the pipeline in violation of state
and federal regulations. The CSFM assessed a proposed civil penalty of $500,000.
The location of the incident was not our work site, nor did we have any direct
involvement in the water main replacement project. We believe that SFPP acted in
accordance with applicable law and regulations, and further that according to
California law, excavators, such as the contractor on the project, must take the
necessary steps (including excavating with hand tools) to confirm the exact
location of a pipeline before using any power operated or power driven
excavation equipment. Accordingly, we disagree with certain of the findings of
CalOSHA and the CSFM, and we have appealed the civil penalties while, at the
same time, continuing to work cooperatively with CalOSHA and the CSFM to resolve
these matters.
As a result of the accident, fifteen separate lawsuits have been filed.
Eleven are personal injury and wrongful death actions. These are: Knox, et al.
v.. Mountain Cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-00281); Farley
v. Mountain cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-01573); Reyes,
et al. v. East Bay Municipal Utility District, et al. (Alameda Sup. Ct. Case No.
RG-05-207720); Arias, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case No.
RG-05-195567); Angeles, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case
No. RG-05-195680); Ramos, et al. v. East Bay Municipal Utility District, et al.
(Contra Costa County Superior Court Case No. C05-01840); Taylor, et al. v. East
Bay Municipal Utility District, et al. (Contra Costa County Superior Court Case
No. C05-02306); Becerra v. Kinder Morgan Energy Partners, L.P., et al., (Contra
Costa County Superior Court Case No. C05-02451); Im, et al. v. Kinder Morgan,
Inc. et al. (Contra Costa County Superior Court Case No. C05-02077); Paasch, et
al. v. East Bay Municipal Utility District, et al. (Contra Costa County Superior
Court Case No. C05-01844); and Fuentes et al. v. Kinder Morgan, et al. (Contra
Costa County Superior Court Case No. C05-02286). These complaints all allege,
among other things, that SFPP/Kinder Morgan failed to properly field mark the
area where the accident occurred. All of these plaintiffs seek compensatory and
punitive damages. These complaints also allege that the general contractor who
struck the pipeline, Mountain Cascade, Inc. ("MCI"), and EBMUD were at fault for
negligently failing to locate the pipeline. Some of these complaints also name
various engineers on the project for negligently failing to draw up adequate
plans indicating the bend in the pipeline. A number of these actions also name
Comforce Technical Services as a defendant. Comforce supplied SFPP with
temporary employees/independent contractors who performed line marking and
inspections of the pipeline on behalf of SFPP. Some of these complaints also
named various governmental entities--such as the City of Walnut Creek, Contra
Costa County, and the Contra Costa Flood Control and Water Conservation
District--as defendants.
Two of the fifteen suits are related to alleged damage to a residence near
the accident site. These are: USAA v. East Bay Municipal Utility District, et
al., (Contra Costa County Superior Court Case No. C05-02128); and Chabot v. East
Bay Municipal Utilities District, et al., (Contra Costa Superior Court Case No.
C05-02312). The remaining two suits are by MCI and the welding subcontractor,
Matamoros. These are: Matamoros v. Kinder Morgan Energy
28
Partners, L.P., et al., (Contra Costa County Superior Court Case No.
C05-02349); and Mountain Cascade, Inc. v. Kinder Morgan Energy Partners,
L.P., et al, (Contra Costa County Superior Court Case No. C-05-02576). Like
the personal injury and wrongful death suits, these lawsuits allege that
SFPP/Kinder Morgan failed to properly mark its pipeline, causing damage to
these plaintiffs. The Chabot and USAA plaintiffs allege property damage,
while MCI and Matamoros Welding allege damage to their business as a result
of SFPP/Kinder Morgan's alleged failures, as well as indemnity and other
common law and statutory tort theories of recovery.
Fourteen of these lawsuits are currently coordinated in Contra Costa County
Superior Court; the fifteenth is expected to be coordinated with the other
lawsuits in the near future. There are also several cross-complaints for
indemnity between the co-defendants in the coordinated lawsuits.
Based upon our investigation of the cause of the rupture of SFPP, LP's
petroleum pipeline by Mountain Cascade, Inc. and the resulting explosion and
fire, we have denied liability for the resulting deaths, injuries and damages,
are vigorously defending against such claims, and seeking contribution and
indemnity from the responsible parties.
Cordelia, California
On April 28, 2004, SFPP, L.P. discovered a spill of diesel fuel into a
marsh near Cordelia, California from a section of SFPP's 14-inch Concord to
Sacramento, California pipeline. Estimates indicated that the size of the spill
was approximately 2,450 barrels. Upon discovery of the spill and notification to
regulatory agencies, a unified response was implemented with the United States
Coast Guard, the California Department of Fish and Game, the Office of Spill
Prevention and Response and SFPP. The damaged section of the pipeline was
removed and replaced, and the pipeline resumed operations on May 2, 2004. SFPP
has completed recovery of diesel from the marsh and has completed an enhanced
biodegradation program for removal of the remaining constituents bound up in
soils. The property has been turned back to the owners for its stated purpose.
There will be ongoing monitoring under the oversight of the California Regional
Water Quality Control Board until the site conditions demonstrate there are no
further actions required.
SFPP is currently in negotiations with the United States Environmental
Protection Agency, the United States Fish & Wildlife Service, the California
Department of Fish & Game and the San Francisco Regional Water Quality Control
Board regarding potential civil penalties and natural resource damages
assessments. Since the April 2004 release in the Suisun Marsh area near
Cordelia, California, SFPP has cooperated fully with federal and state agencies
and has worked diligently to remediate the affected areas. As of December 31,
2005, the remediation was substantially complete.
Oakland, California
In February 2005, we were contacted by the U.S. Coast Guard regarding a
potential release of jet fuel in the Oakland, California area. Our northern
California team responded and discovered that one of our product pipelines had
been damaged by a third party, which resulted in a release of jet fuel which
migrated to the storm drain system and the Oakland estuary. We have coordinated
the remediation of the impacts from this release, and are investigating the
identity of the third party who damaged the pipeline in order to obtain
contribution, indemnity, and to recover any damages associated with the rupture.
The United States Environmental Protection Agency, the San Francisco Bay
Regional Water Quality Control Board, the California Department of Fish and
Game, and possibly the County of Alameda are asserting civil penalty claims with
respect to this release. We are currently in settlement negotiations with these
agencies. We will vigorously contest any unsupported, duplicative or excessive
civil penalty claims, but hope to be able to resolve the demands by each
governmental entity through out-of-court settlements.
Donner Summit, California
In April 2005, our SFPP pipeline in Northern California, which transports
refined petroleum products to Reno, Nevada, experienced a failure in the line
from external damage, resulting in a release of product that affected a limited
area adjacent to the pipeline near the summit of Donner Pass. The release was
located on land administered by the Forest Service, an agency within the U.S.
Department of Agriculture. Initial remediation has been conducted in the
immediate vicinity of the pipeline. All agency requirements have been met and
the site will be closed upon completion of the remediation. We have received
civil penalty claims on behalf of the United States Environmental
29
Protection Agency, the California Department of Fish and Game, and the Lahontan
Regional Water Quality Control Board. We are currently in settlement
negotiations with these agencies. We will vigorously contest any unsupported,
duplicative or excessive civil penalty claims, but hope to be able to resolve
the demands by each governmental entity through out-of-court settlements.
Baker California
In November 2004, near Baker, California, our CALNEV Pipeline experienced a
failure in its pipeline from external damage, resulting in a release of gasoline
that affected approximately two acres of land in the high desert administered by
The Bureau of Land Management, an agency within the U.S. Department of the
Interior. Remediation has been conducted and continues for product in the soils.
All agency requirements have been met and the site will be closed upon
completion of the soil remediation. The State of California Department of Fish &
Game has alleged a small natural resource damage claim that is currently under
review. CALNEV expects to work cooperatively with the Department of Fish & Game
to resolve this claim.
Henrico County, Virginia
On April 17, 2006, Plantation Pipeline, which transports refined petroleum
products across the southeastern United States and which is 51.17% owned and
operated by us, experienced a pipeline release of turbine fuel from its 12-inch
pipeline. The release occurred in a residential area and impacted adjacent
homes, yards and common areas, as well as a nearby stream. Drinking water
sources were not impacted. The released product did not ignite and there were no
deaths or injuries. Plantation currently estimates the amount of product
released to be approximately 665 barrels. Immediately following the release, the
pipeline was shut down and emergency remediation activities were initiated.
Remediation and monitoring activities are ongoing under the supervision of the
United States Environmental Protection Agency (referred to in this report as the
EPA) and the Virginia Department of Environmental Quality pursuant to the terms
of an Emergency Removal/Response Administrative Order issued by the EPA under
section 311(c) of the Clean Water Act. Repairs to the pipeline were completed on
April 19, 2006 with the approval of the United States Department of
Transportation, Pipeline and Hazardous Materials Safety Administration, referred
to in this report as the PHMSA, and pipeline service resumed on April 20, 2006.
On April 20, 2006, the PHMSA issued a Corrective Action Order which, among other
things, requires that Plantation maintain a 20% reduction in the operating
pressure along the pipeline between the Richmond and Newington, Virginia pump
stations. The cause of the release is currently under investigation.
Proposed Office of Pipeline Safety Civil Penalty and Compliance Order
On July 15, 2004, the U.S. Department of Transportation's Office of
Pipeline Safety ("OPS") issued a Proposed Civil Penalty and Proposed Compliance
Order concerning alleged violations of certain federal regulations concerning
our products pipeline integrity management program. The violations alleged in
the proposed order are based upon the results of inspections of our integrity
management program at our products pipelines facilities in Orange, California
and Doraville, Georgia conducted in April and June of 2003, respectively. As a
result of the alleged violations, the OPS seeks to have us implement a number of
changes to our integrity management program and also seeks to impose a proposed
civil penalty of approximately $0.3 million. We have already addressed a number
of the concerns identified by the OPS and intend to continue to work with the
OPS to ensure that our integrity management program satisfies all applicable
regulations. However, we dispute some of the OPS findings and disagree that
civil penalties are appropriate, and therefore 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 by the end of the fourth quarter of 2006.
Pipeline and Hazardous Materials Safety Administration Corrective Action
Order
On August 26, 2005, we announced that we had received a Corrective Action
Order issued by the PHMSA. The corrective order instructs us to comprehensively
address potential integrity threats along the pipelines that comprise our
Pacific operations. The corrective order focused primarily on eight pipeline
incidents, seven of which occurred in the State of California. The PHMSA
attributed five of the eight incidents to "outside force damage," such as
30
third-party damage caused by an excavator or damage caused during pipeline
construction.
Following the issuance of the corrective order, we engaged in cooperative
discussions with the PHMSA and we reached an agreement in principle on the terms
of a consent agreement with the PHMSA, subject to the PHMSA's obligation to
provide notice and an opportunity to comment on the consent agreement to
appropriate state officials pursuant to 49 USC Section 60112(c). This comment
period closed on March 26, 2006.
On April 10, 2006, we announced the final consent agreement, which will,
among other things, require us to perform a thorough analysis of recent pipeline
incidents, provide for a third-party independent review of our operations and
procedural practices, and restructure our internal inspections program.
Furthermore, we have reviewed all of our policies and procedures and are
currently implementing various measures to strengthen our integrity management
program, including a comprehensive evaluation of internal inspection
technologies and other methods to protect our pipelines. We expect to spend
approximately $90 million on pipeline integrity activities for our Pacific
operations' pipelines over the next five years. Of that amount, approximately
$26 million is related to this consent agreement. We do not expect that our
compliance with the consent agreement will have a material adverse effect on our
business, financial position, results of operations or cash flows.
General
Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions. Furthermore, to the extent an assessment of
the matter is possible, if it is probable that a liability has been incurred and
the amount of loss can be reasonably estimated, we believe that we have
established an adequate reserve to cover potential liability. We also believe
that these matters will not have a material adverse effect on our business,
financial position, results of operations or cash flows.
Environmental Matters
Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids
Terminals, Inc. and ST Services, Inc.
On April 23, 2003, Exxon Mobil Corporation filed a complaint in the
Superior Court of New Jersey, Gloucester County. We filed our answer to the
complaint on June 27, 2003, in which we denied ExxonMobil's claims and
allegations as well as included counterclaims against ExxonMobil. The lawsuit
relates to environmental remediation obligations at a Paulsboro, New Jersey
liquids terminal owned by ExxonMobil from the mid-1950s through November 1989,
by GATX Terminals Corp. from 1989 through September 2000, and owned currently by
ST Services, Inc. Prior to selling the terminal to GATX Terminals, ExxonMobil
performed the environmental site assessment of the terminal required prior to
sale pursuant to state law. During the site assessment, ExxonMobil discovered
items that required remediation and the New Jersey Department of Environmental
Protection issued an order that required ExxonMobil to perform various
remediation activities to remove hydrocarbon contamination at the terminal.
ExxonMobil, we understand, is still remediating the site and has not been
removed as a responsible party from the state's cleanup order; however,
ExxonMobil claims that the remediation continues because of GATX Terminals'
storage of a fuel additive, MTBE, at the terminal during GATX Terminals'
ownership of the terminal. When GATX Terminals sold the terminal to ST Services,
the parties indemnified one another for certain environmental matters. When GATX
Terminals was sold to us, GATX Terminals' indemnification obligations, if any,
to ST Services may have passed to us. Consequently, at issue is any
indemnification obligation we may owe to ST Services for environmental
remediation of MTBE at the terminal. The complaint seeks any and all damages
related to remediating MTBE at the terminal, and, according to the New Jersey
Spill Compensation and Control Act, treble damages may be available for actual
dollars incorrectly spent by the successful party in the lawsuit for remediating
MTBE at the terminal. The parties have completed limited discovery. In October
2004, the judge assigned to the case dismissed himself from the case based on a
conflict, and the new judge has ordered the parties to participate in mandatory
mediation. The parties participated in a mediation on November 2, 2005 but no
resolution was reached regarding the claims set out in the lawsuit. At this
time, the parties are considering another mediation session but no date is
confirmed.
31
Other Environmental
Our Kinder Morgan Transmix Company has been in discussions with the United
States Environmental Protection Agency regarding allegations by the EPA that it
violated certain provisions of the Clean Air Act and the Resource Conservation &
Recovery Act. Specifically, the EPA claims that we failed to comply with certain
sampling protocols at our Indianola, Pennsylvania transmix facility in violation
of the Clean Air Act's provisions governing fuel. The EPA further claims that we
improperly accepted hazardous waste at our transmix facility in Indianola.
Finally, the EPA claims that we failed to obtain batch samples of gasoline
produced at our Hartford (Wood River), Illinois facility in 2004. In addition to
injunctive relief that would require us to maintain additional oversight of our
quality assurance program at all of our transmix facilities, the EPA is seeking
monetary penalties of $0.6 million.
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 subject to environmental cleanup and enforcement actions from time
to time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) generally imposes joint and several
liability for cleanup and enforcement costs on current or predecessor owners and
operators of a site, among others, without regard to fault or the legality of
the original conduct. Our operations are also subject to federal, state and
local laws and regulations relating to protection of the environment. Although
we believe our operations are in substantial compliance with applicable
environmental law and regulations, risks of additional costs and liabilities are
inherent in pipeline, terminal and carbon dioxide field and oil field
operations, and there can be no assurance that we will not incur significant
costs and liabilities. Moreover, it is possible that other developments, such as
increasingly stringent environmental laws, regulations and enforcement policies
thereunder, and claims for damages to property or persons resulting from our
operations, could result in substantial costs and liabilities to us.
We are currently involved in several governmental proceedings involving
groundwater and soil remediation efforts under administrative orders or related
state remediation programs issued by various regulatory authorities related to
compliance with environmental regulations associated with our assets. We have
established a reserve to address the costs associated with the cleanup.
We are also involved with and have been identified as a potentially
responsible party in several federal and state superfund sites. Environmental
reserves have been established for those sites where our contribution is
probable and reasonably estimable. In addition, we are from time to time
involved in civil proceedings relating to damages alleged to have occurred as a
result of accidental leaks or spills of refined petroleum products, natural gas
liquids, natural gas and carbon dioxide.
See "--Pipeline Integrity and Ruptures" above for information with respect
to the environmental impact of recent ruptures of some of our pipelines.
Although no assurance can be given, we believe that the ultimate resolution
of the environmental matters set forth in this note will not have a material
adverse effect on our business, financial position, results of operations or
cash flows. However, we are not able to reasonably estimate when the eventual
settlements of these claims will occur. Many factors may change in the future
affecting our reserve estimates, such as regulatory changes, groundwater and
land use near our sites, and changes in cleanup technology. As of March 31,
2006, we have accrued an environmental reserve of $50.1 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.
32
4. Asset Retirement Obligations
We account for our legal obligations associated with the retirement of
long-lived assets pursuant to Statement of Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides
accounting and reporting guidance for legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction
or normal operation of a long-lived asset.
SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. Under SFAS No. 143,
the fair value of asset retirement obligations are recorded as liabilities on a
discounted basis when they are incurred, which is typically at the time the
assets are installed or acquired. Amounts recorded for the related assets are
increased by the amount of these obligations. Over time, the liabilities will be
accreted for the change in their present value and the initial capitalized costs
will be depreciated over the useful lives of the related assets. The liabilities
are eventually extinguished when the asset is taken out of service.
In our CO2 business segment, we are required to plug and abandon oil and
gas wells that have been removed from service and to remove our surface wellhead
equipment and compressors. As of March 31, 2006, we have recognized asset
retirement obligations in the aggregate amount of $41.9 million relating to
these requirements at existing sites within our CO2 business segment.
In our Natural Gas Pipelines business segment, if we were to cease
providing utility services, we would be required to remove surface facilities
from land belonging to our customers and others. Our Texas intrastate natural
gas pipeline group has various condensate drip tanks and separators located
throughout its natural gas pipeline systems, as well as inactive gas processing
plants, laterals and gathering systems which are no longer integral to the
overall mainline transmission systems, and asbestos-coated underground pipe
which is being abandoned and retired. Our Kinder Morgan Interstate Gas
Transmission system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of March 31, 2006, we have recognized asset
retirement obligations in the aggregate amount of $1.6 million relating to the
businesses within our Natural Gas Pipelines business segment.
We have included $0.8 million of our total asset retirement obligations as
of March 31, 2006 with "Accrued other current liabilities" in our accompanying
consolidated balance sheet. The remaining $42.7 million obligation is reported
separately as a non-current liability. No assets are legally restricted for
purposes of settling our asset retirement obligations. A reconciliation of the
beginning and ending aggregate carrying amount of our asset retirement
obligations for each of the three months ended March 31, 2006 and 2005 is as
follows (in thousands):
Three Months Ended March 31,
----------------------------
2006 2005
------------- -------------
Balance at beginning of period......... $ 43,227 $ 38,274
Liabilities incurred................. 58 (238)
Liabilities settled.................. (350) (233)
Accretion expense.................... 596 520
Revisions in estimated cash flows.... -- --
-------- --------
Balance at end of period............... $ 43,531 $ 38,323
======== ========
5. Distributions
On February 14, 2006, we paid a cash distribution of $0.80 per unit to our
common unitholders and our Class B unitholders for the quarterly period ended
December 31, 2005. KMR, our sole i-unitholder, received 997,180 additional
i-units based on the $0.80 cash distribution per common unit. The distributions
were declared on January 18, 2006, payable to unitholders of record as of
January 31, 2006.
On April 19, 2006, we declared a cash distribution of $0.81 per unit for
the quarterly period ended March 31, 2006. The distribution will be paid on May
15, 2006, to unitholders of record as of April 28, 2006. Our common unitholders
and Class B unitholders will receive cash. KMR will receive a distribution in
the form of additional
33
i-units based on the $0.81 distribution per common unit. The number of i-units
distributed will be 1,093,826. For each outstanding i-unit that KMR holds, a
fraction of an i-unit (0.018566) will be issued. The fraction was determined by
dividing:
o $0.81, the cash amount distributed per common unit
by
o $43.629, the average of KMR's shares' closing market prices from April
11-25, 2006, the ten consecutive trading days preceding the date on
which the shares began to trade ex-dividend under the rules of the New
York Stock Exchange.
6. Intangibles
Our intangible assets include goodwill, lease value, contracts, customer
relationships and agreements. Excluding goodwill, our other intangible assets
have definite lives, are being amortized on a straight-line basis over their
estimated useful lives, and are reported separately as "Other intangibles, net"
in our accompanying consolidated balance sheets. For our investments in
affiliated entities that are included in our consolidation, the excess cost over
underlying fair value of net assets is referred to as goodwill and reported
separately as "Goodwill" in our accompanying consolidated balance sheets.
According to the provisions of SFAS No. 142, "Goodwill and Other Intangible
Assets," goodwill is not subject to amortization but must be tested for
impairment at least annually.
Following is information related to our intangible assets subject to
amortization and our goodwill (in thousands):
March 31, December 31,
2006 2005
--------- ------------
Goodwill
Gross carrying amount......... $ 813,101 $ 813,101
Accumulated amortization...... (14,142) (14,142)
---------- ----------
Net carrying amount........... 798,959 798,959
---------- ----------
Lease value
Gross carrying amount......... 6,592 6,592
Accumulated amortization...... (1,204) (1,168)
---------- ----------
Net carrying amount........... 5,388 5,424
---------- ----------
Contracts and other
Gross carrying amount......... 224,250 221,250
Accumulated amortization...... (13,050) (9,654)
---------- ----------
Net carrying amount........... 211,200 211,596
---------- ----------
Total intangibles, net.......... $1,015,547 $1,015,979
========== ==========
Amortization expense on our intangibles consisted of the following (in
thousands):
Three Months Ended March 31,
2006 2005
----------- -----------
Lease value............... $ 36 $ 36
Contracts and other....... 3,396 330
------- ------
Total amortization........ $ 3,432 $ 366
======= ======
As of March 31, 2006, our weighted average amortization period for our
intangible assets was approximately 19.3 years. Our estimated amortization
expense for these assets for each of the next five fiscal years is approximately
$13.3 million, $13.2 million, $12.0 million, $11.8 million and $11.7 million,
respectively.
There were no changes in the carrying amount of our goodwill for the three
months ended March 31, 2006. The carrying amount of our goodwill as of March 31,
2006 and as of December 31, 2005 is summarized as follows (in thousands):
34
Products Natural Gas
Pipelines Pipelines CO2 Terminals Total
--------- --------- --- --------- -----
Balance as of
March 31, 2006 and
December 31, 2005........ $ 263,182 $ 288,435 $ 46,101 $ 201,241 $ 798,959
========= ========= ======== ========= =========
In addition, pursuant to ABP No. 18, any premium paid by an investor, which
is analogous to goodwill, must be identified. For the investments we account for
under the equity method of accounting, this premium or excess cost over
underlying fair value of net assets is referred to as equity method goodwill.
According to the provisions of SFAS No. 142, equity method goodwill is not
subject to amortization but rather to impairment testing in accordance with
Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for
Investments in Common Stock." The impairment test under APB No. 18 considers
whether the fair value of the equity investment as a whole, not the underlying
net assets, has declined and whether that decline is other than temporary.
Therefore, in addition to our annual impairment test of goodwill, we
periodically reevaluate the amount at which we carry the excess of cost over
fair value of net assets accounted for under the equity method. As of both March
31, 2006 and December 31, 2005, we have reported $138.2 million in equity method
goodwill within the caption "Investments" in our accompanying consolidated
balance sheets.
We also, periodically, reevaluate the difference between the fair value of
net assets accounted for under the equity method and our proportionate share of
the underlying book value (that is, the investee's net assets per its financial
statements) of the investee at date of acquisition. In almost all instances,
this differential, relating to the discrepancy between our share of the
investee's recognized net assets at book values and at current fair values,
represents our share of undervalued depreciable assets, and since those assets
(other than land) are subject to depreciation, we amortize this portion of our
investment cost against our share of investee earnings. We reevaluate this
differential, as well as the amortization period for such undervalued
depreciable assets, to determine whether current events or circumstances warrant
adjustments to our carrying value and/or revised estimates of useful lives in
accordance with APB Opinion No. 18.
7. Debt
Our outstanding short-term debt as of March 31, 2006 was $1,060.8 million.
The balance consisted of:
o $1,051.3 million of commercial paper borrowings;
o a $5.7 million portion of 5.23% senior notes (our subsidiary, Kinder
Morgan Texas Pipeline, L.P., is the obligor on the notes); and
o a $5 million portion of 7.84% senior notes (our subsidiary, Central
Florida Pipe Line LLC, is the obligor on the notes); and
o an offset of $1.2 million (which represents the net of other
borrowings and the accretion of discounts on our senior note
issuances).
As of March 31, 2006, 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 5.527% during the first quarter of 2006 and 4.901% during the
first quarter of 2005.
Credit Facility
As of March 31, 2006, we had two credit facilities:
o a $1.6 billion unsecured five-year credit facility due August 18,
2010; and
35
o a $250 million unsecured nine-month credit facility due November 21,
2006.
We entered into our nine-month credit facility on February 22, 2006, and
this facility contains borrowing rates and restrictive financial covenants that
are similar to the borrowing rates and covenants under our $1.6 billion bank
facility. Our credit facilities are with a syndicate of financial institutions,
and Wachovia Bank, National Association is the administrative agent. There were
no borrowings under either credit facility as of March 31, 2006, and there were
no borrowings under our five-year credit facility as of December 31, 2005.
The amount available for borrowing under our credit facilities as of March
31, 2006 was reduced by:
o our outstanding commercial paper borrowings ($1,051.3 million as of
March 31, 2006);
o a combined $394 million in five letters of credit that support our
hedging of commodity price risks associated with the sale of natural
gas, natural gas liquids, oil and carbon dioxide;
o a combined $49 million in two letters of credit that support
tax-exempt bonds; and
o $16.2 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 December 31, 2005, our commercial paper program provided for the
issuance of up to $1.6 billion of commercial paper. In April 2006, we increased
our commercial paper program by $250 million to provide for the issuance of up
to $1.85 billion. As of March 31, 2006, we had $1,051.3 million of commercial
paper outstanding with an average interest rate of 4.6854%. Borrowings under our
commercial paper program reduce the borrowings allowed under our credit
facilities.
Debt Issuances Subsequent to March 31, 2006
On April 28, 2006, Rockies Express Pipeline LLC entered into a $2.0 billion
five-year, unsecured revolving credit facility due April 28, 2011. This credit
facility will support a planned $2.0 billion commercial paper program, and
borrowings under the planned commercial paper program will reduce the borrowings
allowed under the credit facility. As of April 28, 2006, there were no
borrowings under the credit facility, and terms of the commercial paper program
were being negotiated. Borrowings under the credit facility and commercial paper
program will be primarily used to finance the construction of the Rockies
Express interstate natural gas pipeline, and the borrowings will not reduce the
borrowings allowed under our credit facilities.
Rockies Express Pipeline LLC is a limited liability company owned 66 2/3%
and controlled by us. Sempra Energy holds the remaining 33 1/3% ownership
interest. Both we and Sempra have agreed to guarantee borrowings under the
Rockies Express credit facility in the same proportion as our percentage
ownership of the member interests in Rockies Express Pipeline LLC.
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.
36
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 March 31, 2006, the debt facilities of Cortez Capital Corporation
consisted of:
o $75 million of Series D notes due May 15, 2013;
o a $125 million short-term commercial paper program; and
o a $125 million five-year committed revolving credit facility due
December 22, 2009 (to support the above-mentioned $125 million
commercial paper program).
As of March 31, 2006, Cortez Capital Corporation had $87.1 million of
commercial paper outstanding with an average interest rate of 4.6332%, the
average interest rate on the Series D notes was 7.14%, and there were no
borrowings under the credit facility.
Red Cedar Gathering Company Debt
In October 1998, Red Cedar Gathering Company sold $55 million in aggregate
principal amount of Senior Notes due October 31, 2010. The $55 million was sold
in 10 different notes in varying amounts with identical terms.
The Senior Notes are collateralized by a first priority lien on the
ownership interests, including our 49% ownership interest, in Red Cedar
Gathering Company. The Senior Notes are also guaranteed by us and the other
owner of Red Cedar Gathering Company jointly and severally. The principal is to
be repaid in seven equal installments beginning on October 31, 2004 and ending
on October 31, 2010. As of March 31, 2006, $39.3 million in principal amount of
notes were outstanding.
Nassau County, Florida Ocean Highway and Port Authority Debt
Nassau County, Florida Ocean Highway and Port Authority is a political
subdivision of the State of Florida. During 1990, Ocean Highway and Port
Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal
amount of $38.5 million for the purpose of constructing certain port
improvements located in Fernandino Beach, Nassau County, Florida. The bond
indenture is for 30 years and allows the bonds to remain outstanding until
December 1, 2020. A letter of credit was issued as security for the Adjustable
Demand Revenue Bonds and was guaranteed by the parent company of Nassau
Terminals LLC, the operator of the port facilities. In July 2002, we
37
acquired Nassau Terminals LLC and became guarantor under the letter of credit
agreement. In December 2002, we issued a $28 million letter of credit under our
credit facilities and the former letter of credit guarantee was terminated.
Principal payments on the bonds are made on the first of December each year, and
corresponding reductions are made to the letter of credit. As of March 31, 2006,
this letter of credit had an outstanding balance under our credit facility of
$24.9 million.
Certain Relationships and Related Transactions
In conjunction with our acquisition of Natural Gas Pipelines assets from
KMI on December 31, 1999 and 2000, KMI became a guarantor of approximately
$522.7 million of our debt. In conjunction with our acquisition of all of the
partnership interests in TransColorado Gas Transmission Company from two
wholly-owned subsidiaries of KMI on November 1, 2004, KMI became a guarantor of
approximately $210.8 million of our debt. Thus, KMI was a guarantor of a total
of approximately $733.5 million of our debt as of March 31, 2006, and 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, 2005.
8. Partners' Capital
As of March 31, 2006 and December 31, 2005, our partners' capital consisted
of the following limited partner units:
March 31, December31,
2006 2005
----------- -----------
Common units....................... 157,015,376 157,005,326
Class B units...................... 5,313,400 5,313,400
i-units............................ 58,915,553 57,918,373
----------- -----------
Total limited partner units...... 221,244,329 220,237,099
=========== ===========
The total limited partner units represent our limited partners' interest
and an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights.
As of March 31, 2006, our common unit totals consisted of 142,659,641 units
held by third parties, 12,631,735 units held by KMI and its consolidated
affiliates (excluding our general partner), and 1,724,000 units held by our
general partner. As of December 31, 2005, our common unit total consisted of
142,649,591 units held by third parties, 12,631,735 units held by KMI and its
consolidated affiliates (excluding our general partner) and 1,724,000 units held
by our general partner.
On both March 31, 2006 and December 31, 2005, our Class B units were held
entirely by a wholly-owned subsidiary of KMI and our i-units were held entirely
by KMR. All of our Class B units were issued to a wholly-owned subsidiary of KMI
in December 2000. The Class B units are similar to our common units except that
they are not eligible for trading on the New York Stock Exchange.
Our i-units are a separate class of limited partner interests in us. All of
our i-units are owned by KMR and are not publicly traded. In accordance with its
limited liability company agreement, KMR's activities are restricted to being a
limited partner in us, and controlling and managing our business and affairs and
the business and affairs of our operating limited partnerships and their
subsidiaries. Through the combined effect of the provisions in our partnership
agreement and the provisions of KMR's limited liability company agreement, the
number of outstanding KMR shares and the number of i-units will at all times be
equal.
Under the terms of our partnership agreement, we agreed that we will not,
except in liquidation, make a distribution on an i-unit other than in additional
i-units or a security that has in all material respects the same rights and
privileges as our i-units. The number of i-units we distribute to KMR is based
upon the amount of cash we distribute to the owners of our common units. When
cash is paid to the holders of our common units, we will issue
38
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 997,180 i-units from us on February
14, 2006. These additional i-units distributed were based on the $0.80 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 $0.80 per unit paid on February 14, 2006 for
the fourth quarter of 2005 required an incentive distribution to our general
partner of $125.6 million. Our distribution of $0.74 per unit paid on February
14, 2005 for the fourth quarter of 2004 required an incentive distribution to
our general partner of $106.0 million. The increased incentive distribution to
our general partner paid for the fourth quarter of 2005 over the distribution
paid for the fourth 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 first quarter of 2006 of $0.81 per unit
will result in an incentive distribution to our general partner of approximately
$128.3 million. This compares to our distribution of $0.76 per unit and
incentive distribution to our general partner of approximately $111.1 million
for the first quarter of 2005.
9. Comprehensive Income
SFAS No. 130, "Accounting for Comprehensive Income," requires that
enterprises report a total for comprehensive income. For each of the three
months ended March 31, 2006 and March 31, 2005, the difference between our net
income and our comprehensive income resulted from unrealized gains or losses on
derivatives utilized for hedging purposes and from foreign currency translation
adjustments. For more information on our hedging activities, see Note 10. Our
total comprehensive income is as follows (in thousands):
Three Months Ended
March 31,
---------------------
2006 2005
--------- ---------
Net income................................. $ 246,709 $ 223,621
Foreign currency translation adjustments... 119 (227)
Change in fair value of derivatives
used for hedging purposes.................. (218,012) (556,835)
Reclassification of change in fair
value of derivatives to net income......... 102,173 60,920
--------- ---------
Total other comprehensive income/(loss).. (115,720) (496,142)
--------- ---------
Comprehensive income/(loss)................ $ 130,989 $(272,521)
========= =========
10. Risk Management
Energy Commodity Price Risk Management
Certain of our business activities expose us to risks associated with
changes in the market price of natural gas, natural gas liquids and crude oil.
We use energy financial instruments to reduce our risk of changes in the prices
of
39
natural gas, natural gas liquids and crude oil markets, 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 (underlying) financial instrument, variable or asset.
Examples of derivative instruments include the following: forward contracts,
futures contracts, options and swaps (also called contracts for differences).
Pursuant to our management's approved risk management policy, we use energy
financial instruments as a hedging (offset) mechanism against the volatility of
energy commodity prices caused by shifts in the supply and demand for a
commodity, as well as its location. Characteristically, we use energy financial
instruments to hedge or reduce our exposure to price risk associated with:
o pre-existing or anticipated physical natural gas, natural gas liquids
and crude oil sales;
o natural gas purchases; and
o system use and storage.
Our risk management activities are primarily used in order to protect our
profit margins and our risk management policies prohibit us from engaging in
speculative trading. Commodity-related activities of our risk management group
are monitored by our risk management committee, which is charged with the review
and enforcement of our management's risk management policy.
Specifically, our risk management committee is a separately designated
standing committee comprised of 15 executive-level employees of KMI or KMGP
Services Company, Inc. whose job responsibilities involve operations exposed to
commodity market risk and other external risks in the ordinary course of
business. Our risk management committee is chaired by our President and is
charged with the following three responsibilities:
o establish and review risk limits consistent with our risk tolerance
philosophy;
o recommend to the audit committee of our general partner's delegate any
changes, modifications, or amendments to our risk management policy;
and
o address and resolve any other high-level risk management issues.
A derivative contract's cash flow or fair value fluctuates and varies based
on the changes in one or more underlying variables (for example, a specified
interest rate, commodity price, or other variable), and the contract is based on
one or more notional amounts or payment provisions or both (for example, a
number of commodities, shares, or other units specified in a derivative
instrument). While the value of the underlying variable changes due to changes
in market conditions, the notional amount remains constant throughout the life
of the derivative contract. Together, the underlying and the notional amounts
determine the amount of settlement, and, in some cases, whether or not a
settlement is required.
Current accounting standards require derivatives to be reflected as assets
or liabilities at their fair market values and current market values should be
used to track changes in derivative holdings; that is, mark-to-market valuation
should be employed. The fair value of our 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.
Furthermore, if a company uses derivatives to hedge the fair value of an
asset, liability, or firm commitment, then reporting changes in the fair value
of the hedged item as well as in the value of the derivative is appropriate. In
SFAS No. 133, the Financial Accounting Standards Board defined these hedges as
fair value hedges, and the balance sheet impact for a fair value hedge results
in both the derivative (asset or liability) and the hedged item being reported
at fair value. When changes in the value of the derivative exactly offset
changes in the value of the hedged item, there should be no impact on earnings
(net income); however, when the derivative is not effective in exactly
offsetting changes in the value of the hedged item, then the ineffective amount
should be included in earnings.
40
To be considered effective, changes in the value of the derivative or its
resulting cash flows must substantially offset changes in the value or cash
flows of the item being hedged. A perfectly effective hedge is one in which
changes in the value of the derivative exactly offset changes in the value of
the hedged item or expected cash flow of the future transactions in reporting
periods covered by the hedging instrument. 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.
Our energy commodity derivatives hedge the commodity price risks derived
from our normal business activities, which include the sale of natural gas,
natural gas liquids and crude oil, and these derivatives have been designated by
us as cash flow hedges as defined by SFAS No. 133. A cash flow hedge uses a
derivative to hedge the anticipated future cash flow of a transaction that is
expected to occur but whose value is uncertain. With a cash flow hedge, it is
the cash flow from an expected future transaction that is being hedged (as
opposed to the value of an asset, liability, or firm commitment) and so there is
no balance sheet entry for the hedged item.
According to the provisions of SFAS No. 133, the FASB allows for special
accounting treatment for cash flow hedges--the change in the fair value of the
hedging instrument (derivative), to the extent that the hedge is effective, is
initially reported as a component of other comprehensive income (outside "Net
Income" reported in our consolidated statements of income). Other comprehensive
income consists of those financial items that are included in "Accumulated other
comprehensive loss" in our accompanying consolidated balance sheets but not
included in our net income. Thus, in highly effective cash flow hedges, where
there is no ineffectiveness, other comprehensive income changes by exactly as
much as the derivatives and there is no impact on earnings. When the hedged
forecasted transaction does take place and affects earnings, the effective part
of the hedge is also recognized in the income statement, and the earlier
recognized amounts are removed from "Accumulated other comprehensive loss." If
the forecasted transaction results in an asset or liability, amounts in
"Accumulated other comprehensive loss" should be reclassified into earnings when
the asset or liability affects earnings through cost of sales, depreciation,
interest expense, etc.
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 hedging of anticipated future
cash flows from the sales and purchases of natural gas, natural gas liquids and
crude oil. As described above, these gains and losses are reclassified into
earnings as the hedged sales and purchases take place. During the three months
ended March 31, 2006, we reclassified $102.2 million of Accumulated other
comprehensive loss into earnings as a result of hedged forecasted transactions
occurring during the period. During the three months ended March 31, 2005, we
reclassified $60.9 million of Accumulated other comprehensive loss into earnings
as a result of hedged forecasted transactions occurring during the period.
None of the reclassification of Accumulated other comprehensive loss into
earnings during the first three months of 2006 or 2005 resulted from the
discontinuance of cash flow hedges due to a determination that the forecasted
transactions would no longer occur by the end of the originally specified time
period, but rather resulted from the hedged forecasted transactions actually
affecting earnings (for example, when the forecasted sales and purchases
actually occurred). For all of our derivatives combined, approximately $437.3
million of the Accumulated other comprehensive loss balance of $1,195.4 million
as of March 31, 2006 is expected to be reclassified into earnings during the
next twelve months.
As discussed above, the part of the change in the value of derivatives that
are not effective in offsetting undesired changes in expected cash flows (the
ineffective portion) is required to be recognized currently in earnings.
Accordingly, we recognized a loss of $0.2 million during the first quarter of
2006, and a loss of $0.2 million during the first quarter of 2005 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 three months ended March 31, 2006 and 2005, we did not exclude
any component of the derivative instruments' gain or loss from the assessment of
hedge effectiveness.
The fair values of our energy financial instruments are included in our
accompanying consolidated balance sheets within "Other current assets,"
"Deferred charges and other assets," "Accrued other current liabilities," "Other
41
long-term liabilities and deferred credits," and, as of December 31, 2005 only,
"Accounts payable-Related parties." The following table summarizes the fair
values of our energy financial instruments associated with our commodity market
risk management activities and included on our accompanying consolidated balance
sheets as of March 31, 2006 and December 31, 2005 (in thousands):
March 31, December 31,
2006 2005
----------- --------------
Derivatives-net asset/(liability)
Other current assets................ $ 85,789 $ 109,437
Deferred charges and other assets... 25,459 47,682
Accounts payable-Related parties.... -- (16,057)
Accrued other current liabilities... (514,992) (507,306)
Other long-term liabilities and
deferred credits.................... $(791,307) $(727,929)
Our over-the-counter swaps and options are instruments we entered into with
counterparties outside centralized trading facilities such as a futures, options
or stock exchange. These contracts are with a number of parties, all of which
had investment grade credit ratings as of March 31, 2006. We both owe money and
are owed money under these financial instruments. Defaults by counterparties
under over-the-counter swaps and options could expose us to additional commodity
price risks in the event that we are unable to enter into replacement contracts
for such swaps and options on substantially the same terms. Alternatively, we
may need to pay significant amounts to the new counterparties to induce them to
enter into replacement swaps and options on substantially the same terms. While
we enter into derivative transactions principally with investment grade
counterparties and actively monitor their credit ratings, it is nevertheless
possible that from time to time losses will result from counterparty credit risk
in the future.
In addition, in conjunction with the purchase of exchange-traded
derivatives or when the market value of our derivatives with specific
counterparties exceeds established limits, we are required to provide collateral
to our counterparties, which may include posting letters of credit or placing
cash in margin accounts. As of March 31, 2006, we had five outstanding letters
of credit totaling $394 million in support of our hedging of commodity price
risks associated with the sale of natural gas, natural gas liquids and crude
oil. As of December 31, 2005, we had five outstanding letters of credit totaling
$534 million in support of our hedging of commodity price risks. As of March 31,
2006, our margin deposits associated with our commodity contract positions and
over-the-counter swap partners totaled $33.1 million; as of December 31, 2005,
we had no cash margin deposits associated with our commodity contract positions
and over-the-counter swap partners.
Certain of our business activities expose us to foreign currency
fluctuations. However, due to the limited size of this exposure, we do not
believe the risks associated with changes in foreign currency will have a
material adverse effect on our business, financial position, results of
operations or cash flows. As a result, we do not significantly hedge our
exposure to fluctuations in foreign currency.
Interest Rate Risk Management
In order to maintain a cost effective capital structure, it is our policy
to borrow funds using a mix of fixed rate debt and variable rate debt. As of
both March 31, 2006 and December 31, 2005, we were a party to interest rate swap
agreements with notional principal amounts of $2.1 billion. We entered into
these agreements for the purposes of:
o hedging the interest rate risk associated with our fixed rate debt
obligations; and
o transforming a portion of the underlying cash flows related to our
long- term fixed rate debt securities into variable rate debt in order
to achieve our desired mix of fixed and variable rate debt.
Since the fair value of fixed rate debt varies with changes in the market
rate of interest, we enter into swaps to receive fixed and pay variable
interest. Such swaps result in future cash flows that vary with the market rate
of interest, and therefore hedge against changes in the fair value of our fixed
rate debt due to market rate changes.
42
As of March 31, 2006, a notional principal amount of $2.1 billion of these
agreements effectively converts the interest expense associated with the
following series of our senior notes from fixed rates to variable rates based on
an interest rate of LIBOR plus a spread:
o $200 million principal amount of our 5.35% senior notes due August 15,
2007;
o $250 million principal amount of our 6.30% senior notes due February
1, 2009;
o $200 million principal amount of our 7.125% senior notes due March 15,
2012;
o $250 million principal amount of our 5.0% senior notes due December
15, 2013;
o $200 million principal amount of our 5.125% senior notes due November
15, 2014;
o $300 million principal amount of our 7.40% senior notes due March 15,
2031;
o $200 million principal amount of our 7.75% senior notes due March 15,
2032;
o $400 million principal amount of our 7.30% senior notes due August 15,
2033; and
o $100 million principal amount of our 5.80% senior notes due March 15,
2035.
These swap agreements have termination dates that correspond to the
maturity dates of the related series of senior notes, therefore, as of March 31,
2006, the maximum length of time over which we have hedged a portion of our
exposure to the variability in the value of this debt due to interest rate risk
is through March 15, 2035.
The swap agreements related to our 7.40% senior notes contain mutual
cash-out provisions at the then-current economic value every seven years. The
swap agreements related to our 7.125% senior notes contain cash-out provisions
at the then-current economic value in March 2009. The swap agreements related to
our 7.75% senior notes and our 7.30% senior notes contain mutual cash-out
provisions at the then-current economic value every five or seven years.
Our interest rate swaps have been designated as fair value hedges as
defined by SFAS No. 133. As discussed above, 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.
Our interest rate swaps meet the conditions required to assume no
ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed by SFAS No. 133 for fair value hedges of
a fixed rate asset or liability using an interest rate swap. Accordingly, we
adjust the carrying value of each swap to its fair value each quarter, with an
offsetting entry to adjust the carrying value of the debt securities whose fair
value is being hedged. We record interest expense equal to the variable rate
payments under the swaps. Interest expense is accrued monthly and paid
semi-annually. When there is no ineffectiveness in the hedging relationship,
employing the shortcut method results in the same net effect on earnings,
accrual and payment of interest, net effect of changes in interest rates, and
level-yield amortization of hedge accounting adjustments as produced by
explicitly amortizing the hedge accounting adjustments on the debt.
The differences between the fair value and the original carrying value
associated with our interest rate swap agreements, that is, the derivatives'
changes in fair value, are included within "Deferred charges and other assets"
and "Other long-term liabilities and deferred credits" in our accompanying
consolidated balance sheets. The offsetting entry to adjust the carrying value
of the debt securities whose fair value was being hedged is recognized as
"Market value of interest rate swaps" on our accompanying consolidated balance
sheets.
43
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 March 31, 2006
and December 31, 2005 (in thousands):
March 31, December 31,
2006 2005
---------- ------------
Derivatives-net asset/(liability)
Deferred charges and other assets........ $ 51,406 $ 112,386
Other long-term liabilities and
deferred credits......................... (41,167) (13,917)
--------- ---------
Market value of interest rate swaps.... $ 10,239 $ 98,469
========= =========
We are exposed to credit related losses in the event of nonperformance by
counterparties to these interest rate swap agreements. While we enter into
derivative 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. As of March 31,
2006, all of our interest rate swap agreements were with counterparties with
investment grade credit ratings.
11. Reportable Segments
We divide our operations into four reportable business segments:
o Products Pipelines;
o Natural Gas Pipelines;
o CO2; and
o Terminals.
We evaluate performance principally based on each segments' earnings before
depreciation, depletion and amortization, which exclude general and
administrative expenses, third-party debt costs and interest expense,
unallocable interest income and minority interest. Our reportable segments are
strategic business units that offer different products and services. Each
segment is managed separately because each segment involves different products
and marketing strategies.
Our Products Pipelines segment derives its revenues primarily from the
transportation and terminaling of refined petroleum products, including
gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas
Pipelines segment derives its revenues primarily from the sale, transmission,
storage and gathering of natural gas. Our CO2 segment derives its revenues
primarily from the production, sale, and transportation of crude oil from fields
in the Permian Basin of West Texas 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
March 31,
-------------------------
2006 2005
----------- -----------
Revenues
Products Pipelines........................ $ 180,526 $ 171,283
Natural Gas Pipelines..................... 1,829,996 1,472,892
CO2....................................... 174,691 163,163
Terminals................................. 206,388 164,594
----------- -----------
Total consolidated revenues.............. $ 2,391,601 $ 1,971,932
=========== ===========
44
Three Months Ended
March 31,
-------------------------
2006 2005
----------- -----------
Operating expenses(a)
Products Pipelines........................ $ 60,647 $ 52,056
Natural Gas Pipelines..................... 1,697,766 1,357,095
CO2....................................... 58,609 49,509
Terminals................................. 115,781 85,416
----------- -----------
Total consolidated operating expenses..... $ 1,932,803 $ 1,544,076
=========== ===========
Depreciation, depletion and amortization
Products Pipelines........................ $ 20,242 $ 19,394
Natural Gas Pipelines..................... 15,933 14,758
CO2....................................... 39,272 38,702
Terminals................................. 17,274 12,173
----------- -----------
Total consol. depreciation, depletion
and amortization.......................... $ 92,721 $ 85,027
=========== ===========
Earnings from equity investments
Products Pipelines........................ $ 7,865 $ 8,385
Natural Gas Pipelines..................... 11,162 8,430
CO2....................................... 5,658 9,248
Terminals................................. 36 9
----------- -----------
Total consolidated equity earnings....... $ 24,721 $ 26,072
=========== ===========
Amortization of excess cost of equity
investments
Products Pipelines........................ $ 841 $ 844
Natural Gas Pipelines..................... 69 69
CO2....................................... 504 504
Terminals................................. - -
----------- -----------
Total consol. amortization of excess
cost of investments....................... $ 1,414 $ 1,417
=========== ===========
Interest income
Products Pipelines........................ $ 1,111 $ 1,149
Natural Gas Pipelines..................... 150 171
CO2....................................... - -
Terminals................................. - -
----------- -----------
Total segment interest income............ 1,261 1,320
Unallocated interest income............... 603 172
----------- -----------
Total consolidated interest income....... $ 1,864 $ 1,492
=========== ===========
Other, net - income (expense)
Products Pipelines........................ $ 95 $ 142
Natural Gas Pipelines..................... 302 (254)
CO2....................................... 1 1
Terminals................................. 1,377 (1,210)
----------- ------------
Total consolidated Other, net - income
(expense)................................. $ 1,775 $ (1,321)
=========== ============
Income tax benefit (expense)
Products Pipelines........................ $ (3,055) $ (3,301)
Natural Gas Pipelines..................... (312) (457)
CO2....................................... (73) (45)
Terminals................................. (2,051) (3,772)
------------ ------------
Total consolidated income tax benefit
(expense)................................. $ (5,491) $ (7,575)
============ ============
Segment earnings
Products Pipelines........................ $ 104,812 $ 105,364
Natural Gas Pipelines..................... 127,530 108,860
CO2....................................... 81,892 83,652
Terminals................................. 72,695 62,032
----------- -----------
Total segment earnings(b)................. 386,929 359,908
Interest and corporate administrative
expenses(c)............................... (140,220) (136,287)
------------ ------------
Total consolidated net income............ $ 246,709 $ 223,621
=========== ===========
45
Three Months Ended
March 31,
-------------------------
2006 2005
----------- --------
Segment earnings before depreciation,
depletion, amortization and amortization of
excess cost of equity investments(d)
Products Pipelines........................ $ 125,895 $ 125,602
Natural Gas Pipelines..................... 143,532 123,687
CO2....................................... 121,668 122,858
Terminals................................. 89,969 74,205
----------- -----------
Total segment earnings before DD&A........ 481,064 446,352
Total consol. depreciation, depletion
and amortization.......................... (92,721) (85,027)
Total consol. amortization of excess
cost of investments....................... (1,414) (1,417)
Interest and corporate administrative
expenses.................................. (140,220) (136,287)
----------- -----------
Total consolidated net income............. $ 246,709 $ 223,621
=========== ===========
Capital expenditures
Products Pipelines........................ $ 56,705 $ 41,070
Natural Gas Pipelines..................... 20,469 9,659
CO2....................................... 74,197 52,557
Terminals................................. 42,292 40,522
----------- -----------
Total consolidated capital expenditures(e) $ 193,663 $ 143,808
=========== ===========
March 31, December 31,
--------- ------------
2006 2005
--------- ------------
Assets
Products Pipelines........................ $ 3,881,020 $ 3,873,939
Natural Gas Pipelines..................... 4,186,027 4,139,969
CO2....................................... 1,770,149 1,772,756
Terminals................................. 2,098,814 2,052,457
----------- -----------
Total segment assets..................... 11,936,010 11,839,121
Corporate assets(f)....................... 85,241 84,341
----------- -----------
Total consolidated assets................ $12,021,251 $11,923,462
=========== ===========
(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 $25,665 and $24,209 for the
three months ended March 31, 2006 and 2005, 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 March 31, 2006 and 2005, we
reported (in thousands) total consolidated interest expense of $77,570 and
$60,219, 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
46
for those employees currently in the plan during their retirement years. SFPP's
post-retirement benefit plan is frozen, and no additional participants may join
the plan.
The noncontributory defined benefit pension plan covering the former
employees of Kinder Morgan Bulk Terminals is the Kinder Morgan, Inc. Retirement
Plan. The benefits under this plan are based primarily upon years of service and
final average pensionable earnings; however, benefit accruals were frozen as of
December 31, 1998.
Net periodic benefit costs for the SFPP post-retirement benefit plan
includes the following components (in thousands):
Other Post-retirement Benefits
------------------------------
Three Months Ended March 31,
------------------------------
2006 2005
------------ ------------
Net periodic benefit cost
Service cost......................... $ 2 $ 2
Interest cost........................ 67 77
Expected return on plan assets....... --- --
Amortization of prior service cost... (29) (29)
Actuarial (gain)..................... (113) (127)
----- -----
Net periodic benefit cost............ $(73) $(77)
===== =====
Our net periodic benefit cost for the first quarter of 2006 was a credit of
$73,000, which resulted in increases to income, largely due to the amortization
of an unrecognized net actuarial gain and to the amortization of a negative
prior service cost, primarily related to the following:
o there have been changes to the plan for both 2004 and 2005 which
reduced liabilities, creating a negative prior service cost that is
being amortized each year; and
o there was a significant drop in 2004 in the number of retired
participants reported as pipeline retirees by Burlington Northern
Santa Fe, which holds a 0.5% special limited partner interest in SFPP,
L.P.
As of March 31, 2006, we estimate our overall net periodic post-retirement
benefit cost for the year 2006 will be an annual credit of approximately $0.3
million. This amount could change in the remaining months of 2006 if there is a
significant event, such as a plan amendment or a plan curtailment, which would
require a remeasurement of liabilities.
13. Related Party Transactions
Plantation Pipe Line Company
We own a 51.17% equity interest in Plantation Pipe Line Company. An
affiliate of ExxonMobil owns the remaining 48.83% interest. In July 2004,
Plantation repaid a $10 million note outstanding and $175 million in outstanding
commercial paper borrowings with funds of $190 million borrowed from its owners.
We loaned Plantation $97.2 million, which corresponds to our 51.17% ownership
interest, in exchange for a seven year note receivable bearing interest at the
rate of 4.72% per annum. The note provides for semiannual payments of principal
and interest on December 31 and June 30 each year beginning on December 31, 2004
based on a 25 year amortization schedule, with a final principal payment of
$157.9 million due July 20, 2011. We funded our loan of $97.2 million with
borrowings under our commercial paper program. An affiliate of ExxonMobil owns
the remaining 48.83% equity interest in Plantation and funded the remaining
$92.8 million on similar terms.
As of both March 31, 2006 and December 31, 2005, the principal amount
receivable from this note was $94.2 million. We included $2.2 million of this
balance within "Accounts, notes and interest receivable, net-Related parties" on
our accompanying consolidated balance sheets, and we included the remaining
$92.0 million balance within "Notes receivable-Related parties."
47
Coyote Gas Treating, LLC
We own a 50% equity interest in Coyote Gas Treating, LLC, referred to in
this report as Coyote Gulch. Coyote Gulch is a joint venture, and Enterprise
Field Services LLC owns the remaining 50% equity interest. We are the managing
partner of Coyote Gulch. In June 2001, Coyote repaid the $34.2 million in
outstanding borrowings under its 364-day credit facility with funds borrowed
from its owners. We loaned Coyote $17.1 million, which corresponds to our 50%
ownership interest, in exchange for a one-year note receivable bearing interest
payable monthly at LIBOR plus a margin of 0.875%. On June 30, 2002 and June 30,
2003, the note was extended for one year. On June 30, 2004, the term of the note
was made month-to-month. In 2005, we reduced our investment in the note by $0.1
million to account for our share of investee losses in excess of the carrying
value of our equity investment in Coyote, and as of December 31, 2005, we
included the principal amount of $17.0 million related to this note within
"Notes Receivable-Related Parties" on our consolidated balance sheet.
In March 2006, Enterprise and we agreed to a resolution that would transfer
Coyote Gulch's notes payable to Enterprise and us to members' equity. According
to the provisions of this resolution, we then contributed the principal amount
of $17.0 million related to our note receivable to our equity investment in
Coyote Gulch. The $17.0 million amount is included within "Investments" on our
consolidated balance sheet as of March 31, 2006.
14. Regulatory Matters
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). In a
FERC order on rehearing and clarification issued January 19, 2006, the FERC
modified its previous policy statement and now will again permit the use of gas
commodity basis differentials in negotiated rate transactions without regard to
rate or revenue caps. On March 23, 2006, the FERC dismissed rehearing requests
and denied requests for clarification--all related to the January 19, 2006
order.
Accounting for Integrity Testing Costs
On November 5, 2004, the FERC issued a Notice of Proposed Accounting
Release that would require FERC jurisdictional entities to recognize costs
incurred in performing pipeline assessments that are a part of a pipeline
integrity management program as maintenance expense in the period incurred. The
proposed accounting ruling was in response to the FERC's finding of diverse
practices within the pipeline industry in accounting for pipeline assessment
activities. The proposed ruling would standardize these practices. Specifically,
the proposed ruling clarifies the distinction between costs for a "one-time
rehabilitation project to extend the useful life of the system," which could be
capitalized, and costs for an "on-going inspection and testing or maintenance
program," which would be accounted for as maintenance and charged to expense in
the period incurred.
On June 30, 2005, the FERC issued an order providing guidance to the
industry on accounting for costs associated with pipeline integrity management
requirements. The order is effective prospectively from January 1, 2006. Under
the order, the costs to be expensed as incurred include those to:
o prepare a plan to implement the program;
o identify high consequence areas;
o develop and maintain a record keeping system; and
48
o inspect affected pipeline segments.
The costs of modifying the pipeline to permit in-line inspections, such as
installing pig launchers and receivers, are to be capitalized, as are certain
costs associated with developing or enhancing computer software or to add or
replace other items of plant.
The Interstate Natural Gas Association of America sought rehearing of the
FERC's June 30, 2005 order. The FERC denied INGAA's request for rehearing on
September 19, 2005. On December 15, 2005, INGAA filed with the United States
Court of Appeals for the District of Columbia Circuit, in docket No. 05-1426, a
petition for review asking the court whether the FERC lawfully ordered that
interstate pipelines subject to FERC rate regulation and related accounting
rules must treat certain costs incurred in complying with the Pipeline Safety
Improvement Act of 2002, along with related pipeline testing costs, as expenses
rather than capital items for purposes of complying with the FERC's regulatory
accounting regulations.
The implementation of this FERC order on January 1, 2006, had no material
impact on our financial position, results of operations, or cash flows in the
first quarter of 2006. Our Kinder Morgan Interstate Gas Transmission system
expects an increase of approximately $0.8 million in operating expenses in 2006
related to pipeline integrity management programs due to its implementation of
this FERC order on January 1, 2006, which will cause KMIGT to expense certain
program costs that previously were capitalized.
In addition, our intrastate natural gas pipelines located within the State
of Texas are not FERC-regulated but instead follow accounting regulations
promulgated by the Railroad Commission of Texas. We will maintain our current
accounting procedures with respect to our accounting for pipeline integrity
testing costs for our intrastate natural gas pipelines.
Selective Discounting
On November 22, 2004, the FERC issued a notice of inquiry seeking comments
on its policy of selective discounting. Specifically, the FERC is asking parties
to submit comments and respond to inquiries regarding the FERC's practice of
permitting pipelines to adjust their ratemaking throughput downward in rate
cases to reflect discounts given by pipelines for competitive reasons - when the
discount is given to meet competition from another gas pipeline. Comments were
filed by numerous entities, including Natural Gas Pipeline Company of America (a
Kinder Morgan, Inc. affiliate), on March 2, 2005. Several reply comments have
subsequently been filed. By an order issued on May 31, 2005, the FERC reaffirmed
its existing policy on selective discounting by interstate pipelines without
change. Several entities filed for rehearing; however, by an order issued on
November 17, 2005, the FERC denied all requests for rehearing. On January 9,
2006, a petition for judicial review of the FERC's May 31, 2005 and November 17,
2005 orders was filed by the Northern Municipal District Group/Midwest Region
Gas Task Force Association.
Index of Customer Audit
On July 14, 2005, the FERC commenced an audit of TransColorado Gas
Transmission Company, as well as a number of other interstate gas pipelines, to
test compliance with the FERC's requirements related to the filing and posting
of the Index of Customers report. On September 21, 2005, the FERC's staff issued
a draft audit report which cited two minor issues with TransColorado's Index of
Customers filings and postings. Subsequently, on October 11, 2005, the FERC
issued a final order which closed its examination, citing the minor issues
contained in its draft report and approving the corrective actions planned or
already taken by TransColorado. TransColorado has implemented corrective actions
and has applied those actions to its most recent Index of Customer filing, dated
October 1, 2005. No further compliance action is expected and TransColorado
anticipates operating in compliance with applicable FERC rules regarding the
filing and posting of its future Index of Customers reports.
Notice of Proposed Rulemaking - Market Based Storage Rates
On December 22, 2005, the FERC issued a notice of proposed rulemaking to
amend its regulations by establishing two new methods for obtaining market based
rates for underground natural gas storage services. First,
49
the FERC is proposing to modify its market power analysis to better reflect
competitive alternatives to storage. Doing so would allow a storage applicant to
include other storage services as well as non-storage products such as pipeline
capacity, local production, or liquefied natural gas supply in its calculation
of market concentration and its analysis of market share. Secondly, the FERC is
proposing to modify its regulations to permit the FERC to allow market based
rates for new storage facilities even if the storage provider is unable to show
that it lacks market power. Such modifications would be allowed provided the
FERC finds that the market based rates are in the public interest, are necessary
to encourage the construction of needed storage capacity, and that customers are
adequately protected from the abuse of market power. KMI's Natural Gas Pipeline
Company of America and our Kinder Morgan Interstate Gas Transmission LLC, as
well as numerous other parties, filed comments on the notice of proposed
rulemaking on February 27, 2006.
15. Recent Accounting Pronouncements
SFAS No. 123R
On December 16, 2004, the Financial Accounting Standards Board issued SFAS
No. 123R (revised 2004), "Share-Based Payment." This Statement amends SFAS No.
123, "Accounting for Stock-Based Compensation," and requires companies to
expense the value of employee stock options and similar awards. Significant
provisions of SFAS No. 123R include the following:
o share-based payment awards result in a cost that will be measured at
fair value on the awards' grant date, based on the estimated number of
awards that are expected to vest. Compensation cost for awards that vest
would not be reversed if the awards expire without being exercised;
o when measuring fair value, companies can choose an option-pricing
model that appropriately reflects their specific circumstances and the
economics of their transactions;
o companies will recognize compensation cost for share-based payment
awards as they vest, including the related tax effects. Upon
settlement of share-based payment awards, the tax effects will be
recognized in the income statement or additional paid-in capital; and
o public companies are allowed to select from three alternative
transition methods - each having different reporting implications.
For us, this Statement became effective January 1, 2006. However, we have
not granted common unit options or made any other share-based payment awards
since May 2000, and as of December 31, 2005, all outstanding options to purchase
our common units were fully vested. Therefore, the adoption of this Statement
did not have an effect on our consolidated financial statements due to the fact
that we have reached the end of the requisite service period for any
compensation cost resulting from share-based payments made under our common unit
option plan.
SFAS No. 154
On June 1, 2005, the FASB issued SFAS No. 154, "Accounting Changes and
Error Corrections." This Statement replaces Accounting Principles Board Opinion
No. 20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes in
Interim Financial Statements." SFAS No. 154 applies to all voluntary changes in
accounting principle, and changes the requirements for accounting for and
reporting of a change in accounting principle.
SFAS No. 154 requires retrospective application to prior periods' financial
statements of a voluntary change in accounting principle unless it is
impracticable. In contrast, APB No. 20 previously required that most voluntary
changes in accounting principle be recognized by including in net income of the
period of the change the cumulative effect of changing to the new accounting
principle. The FASB believes the provisions of SFAS No. 154 will improve
financial reporting because its requirement to report voluntary changes in
accounting principles via retrospective application, unless impracticable, will
enhance the consistency of financial information between periods.
50
The provisions of this Statement are effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005
(January 1, 2006 for us). The Statement does not change the transition
provisions of any existing accounting pronouncements, including those that are
in a transition phase as of the effective date of this Statement. Adoption of
this Statement did not have any immediate effect on our consolidated financial
statements, and we will apply this guidance prospectively.
EITF 04-5
In June 2005, the Emerging Issues Task Force reached a consensus on Issue
No. 04-5, or EITF 04-5, "Determining Whether a General Partner, or the General
Partners as a Group, Controls a Limited Partnership or Similar Entity When the
Limited Partners Have Certain Rights." EITF 04-5 provides guidance for purposes
of assessing whether certain limited partners rights might preclude a general
partner from controlling a limited partnership.
For general partners of all new limited partnerships formed, and for
existing limited partnerships for which the partnership agreements are modified,
the guidance in EITF 04-5 is effective after June 29, 2005. For general partners
in all other limited partnerships, the guidance is effective no later than the
beginning of the first reporting period in fiscal years beginning after December
15, 2005 (January 1, 2006, for us). The adoption of EITF 04-5 did not have an
effect on our consolidated financial statements.
SFAS No. 155
On February 16, 2006, the FASB issued SFAS No. 155, "Accounting for Certain
Hybrid Financial Instruments." This Statement amends SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities" and SFAS No. 140, "Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities." The Statement improves the financial reporting of certain hybrid
financial instruments by requiring more consistent accounting that eliminates
exemptions and provides a means to simplify the accounting for these
instruments. Specifically, it allows financial instruments that have embedded
derivatives to be accounted for as a whole (eliminating the need to bifurcate
the derivative form its host) if the holder elects to account for the whole
instrument on a fair value basis.
The provisions of this Statement are effective for all financial
instruments acquired or issued after the beginning of an entity's first fiscal
year that begins after September 15, 2006 (January 1, 2007 for us). Adoption of
this Statement should not have any immediate effect on our consolidated
financial statements, and we will apply this guidance prospectively.
SFAS No. 156
On March 17, 2006, the FASB issued SFAS No. 156, "Accounting for Servicing
of Financial Assets." This Statement amends SFAS No. 140 and simplifies the
accounting for servicing assets and liabilities, such as those common with
mortgage securitization activities. Specifically, this Statement addresses the
recognition and measurement of separately recognized servicing assets and
liabilities, and provides an approach to simplify efforts to obtain hedge-like
(offset) accounting by permitting a servicer that uses derivative financial
instruments to offset risks on servicing to report both the derivative financial
instrument and related servicing asset or liability by using a consistent
measurement attribute--fair value.
An entity should adopt this Statement as of the beginning of its first
fiscal year that begins after September 15, 2006 (January 1, 2007 for us).
Earlier adoption is permitted as of the beginning of an entity's fiscal year,
provided the entity has not yet issued financial statements, including interim
financial statements, for any period of that fiscal year. The effective date of
this Statement is the date an entity adopts the requirements of this Statement.
Adoption of this Statement should not have any immediate effect on our
consolidated financial statements, and we will apply this guidance
prospectively.
51
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
The following discussion and analysis of our financial condition and
results of operations provides you with a narrative on our financial results. It
contains a discussion and analysis of the results of operations for each segment
of our business, followed by a discussion and analysis of our financial
condition. The following discussion and analysis should be read in conjunction
with:
o our accompanying interim consolidated financial statements and related
notes (included elsewhere in this report), and
o our consolidated financial statements, related notes and management's
discussion and analysis of financial condition and results of
operations included in our Annual Report on Form 10-K for the year
ended December 31, 2005.
Critical Accounting Policies and Estimates
Certain amounts included in or affecting our consolidated financial
statements and related disclosures must be estimated, requiring us to make
certain assumptions with respect to values or conditions that cannot be known
with certainty at the time the financial statements are prepared. These
estimates and assumptions affect the amounts we report for assets and
liabilities and our disclosure of contingent assets and liabilities at the date
of our financial statements. We routinely evaluate these estimates, utilizing
historical experience, consultation with experts and other methods we consider
reasonable in the particular circumstances. Nevertheless, actual results may
differ significantly from our estimates. Any effects on our business, financial
position or results of operations resulting from revisions to these estimates
are recorded in the period in which the facts that give rise to the revision
become known.
In preparing our consolidated financial statements and related disclosures,
we must use estimates in determining the economic useful lives of our assets,
the fair values used to determine possible asset impairment charges, provisions
for uncollectible accounts receivable, exposures under contractual
indemnifications and various other recorded or disclosed amounts. Further
information about us and information regarding our accounting policies and
estimates that we consider to be "critical" can be found in our Annual Report on
Form 10-K for the year ended December 31, 2005. There have not been any
significant changes in these policies and estimates during the three months
ended March 31, 2006.
Results of Operations
Consolidated
Three Months Ended March 31,
----------------------------
2006 2005
----------- ----------
(In thousands)
Earnings before depreciation, depletion and
amortization expense and amortization of
excess cost of equity investments
Products Pipelines..................................$ 125,895 $ 125,602
Natural Gas Pipelines............................... 143,532 123,687
CO2................................................. 121,668 122,858
Terminals........................................... 89,969 74,205
----------- ----------
Segment earnings before depreciation,
depletion and amortization expense and
amortization of excess cost of equity
investments(a)...................................... 481,064 446,352
Depreciation, depletion and amortization
expense............................................. (92,721) (85,027)
Amortization of excess cost of equity investments... (1,414) (1,417)
Interest and corporate administrative expenses(b)... (140,220) (136,287)
----------- ----------
Net income............................................$ 246,709 $ 223,621
=========== ==========
- -------
(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 (including unallocated litigation and
environmental expenses) and minority interest expense.
52
Driven by improved natural gas sales and storage margins, higher natural
gas transportation revenues, and earnings contributions from bulk and liquids
terminal operations acquired since the first quarter of 2005, our consolidated
net income for the first quarter of 2006 was $246.7 million ($0.53 per diluted
unit), as compared to $223.6 million ($0.54 per diluted unit) in consolidated
net income for the first quarter of 2005. Total operating revenues earned in the
first quarter of 2006 totaled $2,391.6 million, a 21% improvement over revenues
of $1,971.9 million earned in the same quarter last year.
Additionally, in the first quarter of 2006, we recognized a $5.6 million
increase in environmental expense associated with environmental liability
adjustments. The $5.6 million increase in environmental expense resulted in a
$4.9 million increase in expense to our Products Pipelines segment, a $0.7
million increase in expense to our Terminals business segment, a $0.1 million
increase in expense to our Natural Gas Pipelines business segment, and a $0.1
million decrease in expense to our CO2 business segment. The adjustment included
a $5.6 million increase in our overall accrued environmental and related claim
liabilities, and we included the additional expense within "Operations and
maintenance" in our accompanying consolidated statement of income for the three
months ended March 31, 2006.
Because our partnership agreement requires us to distribute 100% of our
available cash to our partners on a quarterly basis (available cash consists
primarily of all our cash receipts, less cash disbursements and changes in
reserves), we consider each period's earnings before all non-cash depreciation,
depletion and amortization expenses, including amortization of excess cost of
equity investments, to be an important measure of our success in maximizing
returns to our partners. We also use this measure of profit and loss internally
for evaluating segment performance and deciding how to allocate resources to our
business segments. In the first quarter of 2006, our total segment earnings
before depreciation, depletion and amortization totaled $481.1 million, up 8%
from the $446.4 million in total segment earnings before depreciation, depletion
and amortization in last year's first quarter.
Furthermore, we declared a cash distribution of $0.81 per unit for the
first quarter of 2006 (an annualized rate of $3.24). This distribution is almost
7% higher than the $0.76 per unit distribution we made for the first quarter of
2005. We hope to declare cash distributions of at least $3.28 per unit for 2006;
however, no assurance can be given that we will be able to achieve this level of
distribution. Our expectation does not take into account:
o any impact from rate reductions due to our Pacific operations' rate
case, which we now estimate will be approximately $20 million in 2006;
or
o the expected $45 million shortfall to our budgeted crude oil
production at our SACROC field unit, as described below in "--CO2."
Our general partner and our common and Class B unitholders receive
quarterly distributions in cash, while KMR, the sole owner of our i-units,
receives quarterly distributions in additional i-units. The value of the
quarterly per-share distribution of i-units is based on the value of the
quarterly per-share cash distribution made to our common and Class B
unitholders.
Products Pipelines
Three Months Ended March 31,
----------------------------
2006 2005
------------ ------------
(In thousands, except
operating statistics)
Revenues........................................ $ 180,526 $ 171,283
Operating expenses(a)........................... (60,647) (52,056)
Earnings from equity investments................ 7,865 8,385
Interest income and Other, net-income (expense) 1,206 1,291
Income taxes.................................... (3,055) (3,301)
----------- ----------
Earnings before depreciation, depletion and
amortization expense and amortization of 125,895 125,602
excess cost of equity investments...........
Depreciation, depletion and amortization
expense......................................... (20,242) (19,394)
Amortization of excess cost of equity
investments..................................... (841) (844)
----------- ----------
Segment earnings.............................. $ 104,812 $ 105,364
=========== ==========
53
Three Months Ended March 31,
----------------------------
2006 2005
------------ ------------
Gasoline (MMBbl)............................... 111.6 108.9
Diesel fuel (MMBbl)............................ 38.7 40.2
Jet fuel (MMBbl)............................... 29.5 29.3
---------- ----------
Total refined product volumes (MMBbl)........ 179.8 178.4
Natural gas liquids (MMBbl).................... 9.8 9.6
---------- ----------
Total delivery volumes (MMBbl)(b)............ 189.6 188.0
========== ==========
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
Segment Earnings before Depreciation, Depletion and Amortization
Our Products Pipelines segment reported earnings before depreciation,
depletion and amortization of $125.9 million for the first quarter of 2006,
essentially flat versus the $125.6 million of earnings before depreciation,
depletion and amortization in the first quarter of 2005. As referred to above in
"--Consolidated," the segment's 2006 earnings also include a charge of $4.9
million from the adjustment of our environmental liabilities. The segment's
overall $0.3 million increase in quarter-to-quarter segment earnings before
depreciation, depletion and amortization expenses primarily consisted of the
following:
o a $2.1 million (3%) increase from our combined West Coast refined
petroleum products pipelines and terminal operations, which include
our Pacific operations, our CALNEV Pipeline and our West Coast
terminals. The overall increase reflected higher earnings before
depreciation, depletion and amortization from our CALNEV Pipeline
operations, driven by a $2.3 million (17%) increase in operating
revenues. The increase in revenues was due to an almost 12% increase
in product delivery volumes and to higher average tariff rates. The
higher volumes in 2006 were attributable to both strong demand,
primarily from the Las Vegas, Nevada market, and to service
interruptions in the first quarter of 2005 resulting from adverse
weather on the West Coast. The higher tariffs were due to a Federal
Energy Regulatory Commission tariff index increase in July 2005
(producer price index-finished goods adjustment).
Earnings before depreciation, depletion and amortization expenses from
our Pacific operations and West Coast terminal operations increased
$0.3 million and decreased $0.3 million, respectively, in the first
quarter of 2006 versus the first quarter of 2005. The increase in
earnings from our Pacific operations was driven by a $5.4 million (7%)
increase in operating revenues, but largely offset by incremental
environmental expenses of $2.7 million and by a $2.0 million (26%)
increase in fuel and power costs. The decrease in earnings before
depreciation, depletion and amortization expense from our West Coast
terminals related to higher property tax expense accruals in the first
quarter of 2006, and to settlement income, recognized in the first
quarter of 2005, related to sale negotiations on our Gaffey Street
terminal, which was closed in the fourth quarter of 2004;
o a $0.9 million (13%) increase from our Southeast product terminal
operations, primarily due to higher product inventory sales at higher
average prices;
o a $0.8 million (7%) decrease from our approximate 51% ownership
interest in Plantation Pipe Line Company, chiefly due to lower equity
earnings. The decrease reflects lower overall net income earned by
Plantation in the first quarter of 2006, due primarily to higher oil
loss expenses related to higher product prices, and lower
transportation revenues. Compared to last year's first quarter,
Plantation's overall pipeline deliveries of refined products declined
4% in 2006, due principally to warmer than normal winter weather, and
partly to incremental volumes being diverted to competing pipelines in
the first quarter of 2006 versus the first quarter of 2005; and
o a $0.6 million decrease from each of our North System, Central Florida
Pipeline, and petroleum pipeline transmix processing operations. The
decrease from our North System was primarily due to a 50% increase in
fuel and power expenses, due to higher fuel and natural gas prices in
first quarter 2006 versus first quarter 2005. The decrease from our
Central Florida Pipeline was largely due to incremental environmental
expenses
54
of $1.1 million. The decrease from our transmix operations was
primarily due to lower revenues as a result of a 7% decrease in
overall processing volumes, largely due to a decrease at our
Indianola, Pennsylvania transmix facility.
Segment Details
The segment reported revenues of $180.5 million in the first quarter of
2006 and $171.3 million in the first quarter of 2005. The $9.2 million (5%)
quarter-to-quarter increase in segment revenues was primarily due to the
following:
o a $5.4 million (7%) increase from our Pacific operations, consisting
of a $3.5 million (6%) increase in refined product delivery revenues
and a $1.9 million (9%) increase in product terminal revenues. The
increase from product delivery revenues was due to an over 3% increase
in mainline delivery volumes and an over 2% increase in average tariff
rates, which included both the FERC approved 2005 annual indexed
interstate tariff increase and a requested rate increase with the
California Public Utility Commission.
In November 2004, we filed an application with the CPUC requesting a
$9 million increase in existing intrastate transportation rates to
reflect the in-service date of our $95 million North Line expansion
project. Pursuant to CPUC regulations, this increase automatically
became effective as of December 22, 2004, but is being collected
subject to refund, pending resolution of protests to the application
by certain shippers. The CPUC may resolve the matter in the second
quarter of 2006. The increase from terminal revenues was due to the
higher transportation volumes and to incremental revenues from diesel
lubricity-improving injection services that we began offering in May
2005;
o a $2.3 million (17%) increase from our CALNEV Pipeline, as discussed
above;
o a $1.7 million (13%) increase from our West Coast terminals, related
to rent escalations, higher throughput barrels and rates at various
locations, and additional tank capacity at our Los Angeles Harbor
terminal;
o a $0.5 million (5%) increase from our Central Florida Pipeline, driven
by an over 6% increase in the average tariff per barrel moved; and
o a $1.1 million (7%) decrease from our Southeast terminals, largely
attributable to lower butane revenues (partially offset by lower
butane purchases) related to changes in customer agreements, partly
offset by higher revenues from expanded storage agreements from
terminal operations we acquired in November 2004 from Charter Terminal
Company and Charter-Triad Terminals, LLC.
Combining all of the segment's operations, total delivery volumes of
refined petroleum products increased 0.8% in the first quarter of 2006, compared
to the first quarter of 2005. Increases on our Pacific and CALNEV systems were
offset by decreases on Plantation and Central Florida, due principally to warmer
winter weather in the Southeast. Gasoline volumes for all pipelines in this
segment were up 2.5% quarter-over-quarter, and excluding Plantation, segment
deliveries of gasoline, diesel fuel and jet fuel increased 0.9%, 4.7% and 7.3%,
respectively, in the first quarter of 2006, compared to the first quarter of
2005. Quarter-to-quarter deliveries of natural gas liquids were up 2.1%, as
higher volumes on our Cypress Pipeline more than offset a drop in volumes on our
North System. The increase from Cypress was due to increased demand from a
petrochemical plant in Lake Charles, Louisiana that is served by the pipeline;
the decrease from our North System was due to continued low demand for propane,
primarily due to warmer winter weather across the Midwest. The FERC has set the
oil pipeline tariff rate index increase that will apply beginning July 1, 2006,
at producer price index plus 1.3%, which will positively impact the results of
operations of our Products Pipelines segment beginning in the third quarter.
The segment's combined operating expenses, which consist of all cost of
sales expenses, operating and maintenance expenses, fuel and power expenses, and
all tax expenses, excluding income taxes, increased $8.6 million (17%) in the
first quarter of 2006, compared to the same year-ago period. The overall
increase in operating expenses was mainly due to the following:
55
o a $5.2 million (28%) increase from our Pacific operations, due to the
incremental environmental expenses of $2.7 million and the $2.0
million increase in fuel and power costs described above, and to a
$0.5 million increase in operating expenses mainly associated with
increased terminal activities. The increase in fuel and power expenses
was due to both product delivery volume and utility rate increases, in
2006, and a utility rebate credit received in the first quarter of
2005;
o a $1.8 million (42%) increase from our West Coast terminals, primarily
related to incremental environmental expenses and to higher labor
expenses, due to pay period timing differences and an increase in the
number of employees;
o a $1.1 million (56%) increase from our Central Florida Pipeline
operations, due to the first quarter 2006 environmental expense
adjustments discussed above;
o a $0.8 million (16%) increase from our North System, due to higher
fuel and power expenses and slightly higher natural gas liquids
product losses;
o a $0.7 million (13%) increase from the operation of the Plantation
Pipeline, due primarily to higher labor expenses following timing
differences that resulted in an additional pay period in the first
quarter of 2006 versus the first quarter of 2005; and
o a $2.0 million (27%) decrease from our Southeast terminals, largely
attributable to lower butane purchases, discussed above, and higher
fuel costs.
The segment's equity investments consist of our approximate 51% interest in
Plantation Pipe Line Company, our 50% interest in the Heartland Pipeline
Company, and our 50% interest in Johnston County Terminal, LLC that was included
in our November 2004 Charter products terminals acquisition. Earnings from these
investments decreased $0.5 million (6%) in the first quarter of 2006, when
compared to the same period last year. The decrease was primarily due to a $0.7
million (10%) decrease in equity earnings from our investment in Plantation, due
to overall lower net income as described above.
The segment's income from allocable interest income and other income and
expense items remained flat quarter-over-quarter, and income tax expenses
decreased $0.2 million (7%) in the first quarter of 2006, due primarily to the
lower pre-tax earnings from Plantation.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of equity investments, increased $0.8 million (4%)
in the first quarter of 2006, when compared to the same period last year. The
increase was primarily due to incremental depreciation charges associated with
our Southeast terminal and Pacific operations' assets. The increase from our
Southeast terminals reflected additional depreciation charges related to our
final purchase price allocation, made in the fourth quarter of 2005, for
depreciable terminal assets we acquired in November 2004 from Charter Terminal
Company and Charter-Triad Terminals, LLC. The increase from our Pacific
operations related to higher depreciable costs as a result of the capital
spending we have made since the end of the first quarter of 2005.
56
Natural Gas Pipelines
Three Months Ended March 31,
----------------------------
2006 2005
----------- -----------
(In thousands, except
operating statistics)
Revenues......................................... $ 1,829,996 $ 1,472,892
Operating expenses(a)............................ (1,697,766) (1,357,095)
Earnings from equity investments................. 11,162 8,430
Interest income and Other, net-income (expense).. 452 (83)
Income taxes..................................... (312) (457)
----------- -----------
Earnings before depreciation, depletion
and amortization expense and amortization
of excess cost of equity investments......... 143,532 123,687
Depreciation, depletion and amortization
expense.......................................... (15,933) (14,758)
Amortization of excess cost of equity
investments...................................... (69) (69)
----------- -----------
Segment earnings............................... $ 127,530 $ 108,860
=========== ===========
Natural gas transport volumes
(Trillion Btus)(b)............................... 336.6 338.0
=========== ===========
Natural gas sales volumes (Trillion Btus)(c)..... 223.5 226.6
=========== ===========
- ----------
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
(b) Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate
natural gas pipeline group, Trailblazer and TransColorado pipeline volumes.
(c) Represents Texas intrastate natural gas pipeline group.
Segment Earnings before Depreciation, Depletion and Amortization
Our Natural Gas Pipelines segment reported earnings before depreciation,
depletion and amortization of $143.5 million in the first quarter of 2006, and
$123.7 million in earnings before depreciation, depletion and amortization in
the first quarter of 2005. The segment's overall $19.8 million (16%) increase in
the first quarter of 2006 versus the first quarter of 2005 primarily consisted
of the following:
o a $16.3 million (26%) increase from our Texas intrastate natural gas
pipeline group, due primarily to improved margins from natural gas
sales activities and higher natural gas transportation and storage
demand revenues on our Kinder Morgan Texas and Kinder Morgan Tejas
pipeline systems. Combined, these two systems reported a $14.4 million
(25%) increase in quarter-to-quarter earnings before depreciation,
depletion and amortization, driven by a $9.4 million (33%) increase in
gross margin (revenues less cost of sales) from natural gas sales and
purchases, higher transportation and storage revenues, and favorable
settlements of pipeline transportation imbalances. Margin is defined
as the difference between the prices at which we buy gas in our supply
areas and the prices at which we sell gas in our market areas, less
the cost of fuel to transport. We realize earnings by capturing the
favorable differences between the changes in our gas sales prices,
purchase prices and transportation costs, including fuel.
In addition, our Texas intrastate group earns revenues from natural
gas sales and transportation activities on our Mier-Monterrey Mexico
and Kinder Morgan North Texas pipelines. Combined, these two systems
reported a $1.9 million (38%) increase in earnings before
depreciation, depletion and amortization in 2006 compared to 2005,
primarily due to incremental gross margins from natural gas sales on
our Kinder Morgan North Texas Pipeline;
o a $3.0 million (42%) increase from our 49% equity investment in the
Red Cedar Gathering Company, related to Red Cedar's higher
year-over-year net income in 2006 that was largely driven by higher
prices on incremental sales of excess fuel gas and by higher natural
gas gathering revenues;
o a $1.8 million (21%) increase from our TransColorado Pipeline, due
primarily to higher gas transmission revenues, related to higher
delivery volumes. The increase in volumes resulted from system
improvements
57
associated with an expansion, completed since the end of the first
quarter of 2005, on the northern portion of the pipeline.
TransColorado's north system expansion project was in-service on
January 1, 2006, and provides for up to 300 million cubic feet per day
of additional northbound transportation capacity;
o a $1.8 million (55%) increase from our Casper Douglas natural gas
gathering and processing operations, due mainly to favorable gas
imbalance gains and to comparative differences in hedge settlements
associated with the rolling-off of older low price crude oil and
propane positions at December 31, 2005; and
o a $3.6 million (22%) decrease from our Trailblazer Pipeline, due to
timing differences on the settlements of pipeline transportation
imbalances in the first quarter of 2006 versus the first quarter of
2005. These pipeline imbalances were due to differences between the
volumes nominated and volumes delivered at an inter-connecting point
by the pipeline.
Additionally, on April 18, 2006, we announced that we have entered into a
long-term agreement with CenterPoint Energy Resources Corp. to provide the
natural gas utility with firm transportation and storage services through our
Texas intrastate natural gas pipeline group. According to the provisions of the
agreement, CenterPoint Energy has contracted for one billion cubic feet per day
of natural gas transportation capacity and 16 billion cubic feet of natural gas
storage capacity, effective April 1, 2007. Currently, our Intrastate group is
pursuing projects to expand the transport and storage capabilities in its system
in order to take advantage of increasing gas production in East Texas and
pending liquefied natural gas supplies targeted for the Texas Gulf Coast.
Segment Details
Total segment operating revenues, including revenues from natural gas
sales, increased $357.1 million (24%) in the first quarter of 2006, compared to
the same year-earlier quarter. Combined operating expenses, including natural
gas purchase costs, increased $340.7 million (25%).
The increases in revenues and operating expenses were largely due to higher
natural gas sales revenues and higher natural gas cost of sales, respectively,
due mainly to higher average natural gas prices in the first quarter of 2006,
and to the purchase and sales activities of our Texas intrastate natural gas
pipeline group. Although the Intrastate group's natural gas sales volumes
decreased 1% in the first quarter of 2006 versus the first quarter of 2005,
revenues from the sales of natural gas increased $339.9 million (25%);
similarly, the Texas intrastate group's costs of sales, including natural gas
purchase costs, increased $329.6 million (25%) in the first three months of 2006
versus the first three months of 2005.
Changes in the segment's period-to-period sales revenues and costs of sales
are largely impacted by changes in energy commodity prices. However, due to the
fact that our Texas intrastate group sells natural gas in the same price
environment in which it is purchased, the increases in gas sales revenues are
largely offset by corresponding increases in gas purchase costs.
For the comparative three month periods, the average price for natural gas
sold by our Kinder Morgan Texas and Kinder Morgan Tejas systems increased 28%
(from $5.93 per million British thermal units in 2005 to $7.57 per million
British thermal units in 2006). The increases in natural gas sales and costs of
sales from the Texas intrastate group also included incremental amounts of $19.1
million and $18.4 million, respectively, from our Kinder Morgan North Texas
Pipeline, due to the fact that the pipeline did not begin purchasing and selling
natural gas until June 2005.
The purchase and sale activities of our Texas intrastate group result in
considerably higher revenues and operating expenses compared to the interstate
operations of our Rocky Mountain pipelines, which include our Kinder Morgan
Interstate Gas Transmission, Trailblazer, TransColorado and Rockies Express
pipelines. All four pipelines charge a transportation fee for gas transmission
service and have the authority to initiate natural gas sales for operational
purposes, but none engage in significant gas purchases for resale.
Our Rockies Express Pipeline began limited interim service in the first
quarter of 2006 on its westernmost segment (the segment that extends from
Meeker, Colorado to Wamsutter, Wyoming). Construction of the second segment of
the pipeline (that extends from Wamsutter to Cheyenne, Wyoming) is scheduled to
begin this summer, and the entire line is expected to be in service by January
1, 2007. Our revenues and expenses will not be impacted
58
during the construction of the pipeline due to the fact that regulatory
accounting provisions require capitalization of revenues and expenses until the
second segment of the project is complete and in-service.
We account for the segment's investments in Red Cedar Gathering Company,
Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC under the equity
method of accounting. In the first quarter of 2006, equity earnings from these
three investees increased $2.7 million (32%), when compared to the first quarter
of 2005. The increase was chiefly due to the $3.0 million increase in equity
earnings from Red Cedar, as described above.
The segment's interest income and earnings from other income items
increased $0.5 million in the first quarter of 2006, compared to the first
quarter of 2005. The increase was mainly due to incremental litigation expense
accruals, recognized in the first quarter of 2005, by our Kinder Morgan North
Texas Pipeline.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased $1.2 million (8%) in the
first quarter of 2006, when compared to the same period last year. The increase
was largely due to higher depreciation charges on our Kinder Morgan Texas system
due to the acquisition of our North Dayton, Texas natural gas storage facility
in August 2005. We allocated $64.1 million of our total purchase price of $109.4
million to our depreciable asset base.
CO2
Three Months Ended March 31,
---------------------------
2006 2005
----------- ----------
(In thousands, except
operating statistics)
Revenues....................................... $ 174,691 $ 163,163
Operating expenses(a).......................... (58,609) (49,509)
Earnings from equity investments............... 5,658 9,248
Other, net-income (expense).................... 1 1
Income taxes................................... (73) (45)
----------- ----------
Earnings before depreciation, depletion
and amortization expense and amortization
of excess cost of equity investments......... 121,668 122,858
Depreciation, depletion and amortization
expense(b)..................................... (39,272) (38,702)
Amortization of excess cost of equity
investments.................................... (504) (504)
----------- ----------
Segment earnings............................. $ 81,892 $ 83,652
=========== ==========
Carbon dioxide delivery volumes (Bcf)(c)......... 172.4 169.9
=========== ==========
SACROC oil production (gross)(MBbl/d)(d)......... 31.3 33.8
=========== ==========
SACROC oil production (net)(MBbl/d)(e)........... 26.1 28.1
=========== ==========
Yates oil production (gross)(MBbl/d)(d).......... 25.0 24.1
=========== ==========
Yates oil production (net)(MBbl/d)(e)............ 11.1 10.7
=========== ==========
Natural gas liquids sales volumes
(net)(MBbl/d)(e)................................. 9.3 9.7
=========== ==========
Realized weighted average oil price
per Bbl(f)(g).................................... $ 30.47 $ 28.81
=========== ==========
Realized weighted average natural gas
liquids price per Bbl(g)(h)...................... $ 41.35 $ 33.97
=========== ==========
- ----------
(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 producing and gas processing activities in the amount of
$34,590 for the first quarter of 2006 and $34,313 for the first quarter of
2005. Includes depreciation, depletion and amortization expense associated
with sales and transportation services activities in the amount of $4,682
for the first quarter of 2006 and $4,389 for the first quarter of 2005.
(c) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos
pipeline volumes.
(d) Represents 100% of the production from the field. We own an approximate 97%
working interest in the SACROC unit and an approximate 50% working interest
in the Yates unit.
(e) Net to Kinder Morgan, after royalties and outside working interests. (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.
59
Segment Earnings before Depreciation, Depletion and Amortization
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, marketing and transportation of crude oil, natural gas and
natural gas liquids. For the first quarter of 2006, the segment reported
earnings before depreciation, depletion and amortization of $121.7 million, down
a slight 1% from the $122.9 million of earnings before depreciation, depletion
and amortization reported for the first quarter last year. The overall $1.2
million decrease in quarter-to-quarter segment earnings before depreciation,
depletion and amortization included the following:
o a $6.6 million (8%) decrease in earnings before depreciation,
depletion and amortization expenses from the segment's oil and natural
gas producing activities, which include its natural gas processing
activities. The decrease was largely attributable to a $10.0 million
(18%) increase in combined operating expenses, due primarily to higher
well workover expenses, higher fuel and power expenses, and higher
property and severance taxes. The increase in operating expenses more
than offset a $3.4 million (2%) increase in revenues, due primarily to
increased prices on the sales of both natural gas liquids and crude
oil, as discussed below; and
o a $5.4 million (15%) increase in earnings before depreciation,
depletion and amortization from the segment's carbon dioxide sales and
transportation activities. The increase was driven by higher revenues
from carbon dioxide sales, higher carbon dioxide and crude oil
pipeline transportation revenues, and higher oil field and processing
plant service revenues.
On a gross basis (meaning total quantity produced) combined daily oil
production from the two largest oil field units in which we hold ownership
interests decreased almost 3% in the first quarter of 2006, as compared to the
same prior-year period. The two oil field interests include our approximate 97%
working interest in the SACROC unit and our approximate 50% working interest in
the Yates oil field unit, both located in the Permian Basin area of West Texas.
Similarly, natural gas plant liquids product sales volumes decreased 4% in the
first quarter of 2006 when compared with the first quarter last year, largely
due to the quarter-to-quarter decrease in production from the SACROC unit.
Average oil production increased by almost 4% quarter-over-quarter at
Yates, but decreased 7% at the SACROC unit. For the entire year of 2006,
production at Yates is expected to exceed our budgeted average oil production of
24.6 thousand barrels per day by approximately one thousand barrels per day. At
SACROC, the decline in production is specific to one section of the field that
is underperforming, and we now expect oil production to average approximately
three to four thousand barrels per day less for the year than its budget. As a
result of this projected shortfall at SACROC, we expect our CO2 segment to
underperform its annual published budget of segment earnings before
depreciation, depletion and amortization expenses by approximately 8%, or
approximately $45 million.
However, we benefited from increases of 45%, 22% and 6%, respectively, in
our realized weighted average price of carbon dioxide, natural gas liquids and
crude oil per barrel in the first quarter of 2006, versus the first quarter of
2005. The increase in average sale prices for carbon dioxide in 2006 compared to
2005 was largely related to an overall improvement in energy prices and to
continuing strong demand for carbon dioxide from tertiary oil recovery projects.
We do not recognize profits on carbon dioxide sales to ourselves.
The higher prices for natural gas liquids reflect favorable gas processing
margins, which is the relative difference in economic value (on an energy
content basis) between natural gas liquids as a separated liquid, on the one
hand, and as a portion of the residue natural gas stream, on the other hand. Had
we not used energy financial instruments to transfer commodity price risk, our
crude oil sale prices would have averaged $60.62 per barrel in the first quarter
of 2006, and $47.93 per barrel in the first quarter of 2005. Because we are
exposed to market risks related to the price volatility of crude oil, natural
gas and natural gas liquids, we mitigate our commodity price risk through a
long-term hedging strategy that is intended to generate more stable, predictable
realized prices. Our strategy involves the use and designation of energy
financial instruments (derivatives) as hedges to the exposure of fluctuating
expected future cash flows produced by unpredictable changes in crude oil and
natural gas liquids sales prices. All of our hedge gains and losses for crude
oil and natural gas liquids are included in our realized average price for oil;
none are allocated to natural gas liquids. For more information on our hedging
activities, see Note 10 to our consolidated financial statements, included
elsewhere in this report.
60
Segment Details
Our CO2 segment reported revenues of $174.7 million in the first quarter of
2006 and $163.2 million in the first quarter of 2005. The $11.5 million (7%)
quarter-to-quarter increase in segment revenues included increases of $4.9
million (16%) and $1.4 million (1%), respectively, in plant product and crude
oil sales revenues. As described above, the increases were attributable to
higher average prices partially offset by decreases in production.
In addition, revenues from carbon dioxide sales increased $6.9 million
(92%) in the first quarter of 2006 versus the first quarter of 2005, due mainly
to higher average sale prices, discussed above, and to slightly higher sales
volumes. Carbon dioxide and crude oil pipeline transportation revenues increased
$1.2 million (9%) in the three month period of 2006 versus 2005, due primarily
to an over 1% increase in carbon dioxide delivery volumes and a $0.4 million
(6%) increase in crude oil transportation revenues from our Wink Pipeline. Oil
field and processing plant service revenues increased $0.6 million (21%) in the
first quarter of 2006 compared to the first quarter of 2005, largely due to
increased produced gas third-party processing fees in and around the SACROC oil
field unit.
Partially offsetting the overall quarter-to-quarter increase in segment
revenues was a $4.1 million (66%) decrease in natural gas sales revenues,
attributable to lower sales volumes. The decrease in volumes sold was largely
due to natural gas volumes used at the power plant we constructed at the SACROC
oil field unit and placed in service in June 2005. As a result, we had lower
volumes of gas available for sale in the first quarter of 2006 versus the first
quarter last year.
The segment's combined operating expenses increased $9.1 million (18%) in
the first quarter of 2006, versus the same prior-year period. The increase was
primarily the result of higher field operating and maintenance expenses,
property and production taxes, and fuel and power expenses.
The increase in field operating and maintenance expenses was largely due to
higher well workover and completion expenses, including labor, related to
infrastructure expansions at the SACROC and Yates oil field units since the end
of the first quarter last year. Workover expenses relate to incremental
operating and maintenance charges incurred on producing wells in order to
restore or increase production. Workovers are often performed in order to
stimulate production, add pumping equipment, remove fill from the wellbore, to
mechanically repair the well, or for other reasons.
The increase in property taxes was related to both increased asset
infrastructure and higher assessed property values since the end of the first
quarter of 2005. The increase in production (severance) taxes was driven by
higher crude oil revenues. The increase in fuel and power expenses was due to
increased carbon dioxide compression and equipment utilization, higher fuel
costs, and higher electricity expenses due to higher rates as a result of higher
fuel costs to electricity providers. Overall higher electricity costs were
partly offset by the benefits provided from the power plant we constructed at
the SACROC oil field unit, described above. KMI operates the power plant, which
provides the majority of SACROC's electricity needs, and we reimburse KMI for
its costs to operate and maintain the plant.
Earnings from equity investments, representing the equity earnings from our
50% ownership interest in the Cortez Pipeline Company, decreased $3.6 million
(39%) in the first quarter of 2006, when compared to the first quarter of 2005.
The decrease was due to lower overall net income earned by Cortez. The lower
earnings were primarily due to lower carbon dioxide transportation revenues as a
result of lower average tariff rates, which more than offset an almost 3%
increase in carbon dioxide delivery volumes.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, increased $0.6 million (1%) in the
first quarter of 2006, when compared to the same period last year. The increase
was due to higher depreciable costs, related to incremental capital spending
since March 2005.
61
Terminals
Three Months Ended March 31,
----------------------------
2006 2005
----------- ----------
(In thousands, except
operating statistics)
Revenues....................................... $ 206,388 $ 164,594
Operating expenses(a).......................... (115,781) (85,416)
Earnings from equity investments............... 36 9
Other, net-income (expense).................... 1,377 (1,210)
Income taxes................................... (2,051) (3,772)
----------- ----------
Earnings before depreciation, depletion
and amortization expense and amortization
of excess cost of equity investments......... 89,969 74,205
Depreciation, depletion and amortization
expense........................................ (17,274) (12,173)
Amortization of excess cost of equity
investments.................................... - -
----------- ----------
Segment earnings............................. $ 72,695 $ 62,032
=========== ===========
Bulk transload tonnage (MMtons)(b)............. 22.0 23.1
=========== ==========
Liquids leaseable capacity (MMBbl)............. 42.8 36.6
=========== ==========
Liquids utilization %.......................... 97.8% 96.7%
=========== ==========
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) Volumes for acquired terminals are included for both periods.
Segment Earnings before Depreciation, Depletion and Amortization
Our Terminals segment includes the operations of our petroleum and
petrochemical-related liquids terminal facilities (other than those included in
our Products Pipelines segment) as well as all of our coal and dry-bulk material
services, including all transload, engineering and other in-plant services. For
the first three months of 2006 and 2005, the segment reported earnings before
depreciation, depletion and amortization of $90.0 million and $74.2 million,
respectively.
Terminal operations acquired since the end of the first quarter of 2005 and
identified separately in post-acquisition periods included the following:
o our Texas petroleum coke terminals and repair shop assets, located in
and around the Ports of Houston and Beaumont, Texas, acquired
separately in April and September 2005, respectively;
o three terminals acquired separately in July 2005: our Kinder Morgan
Staten Island terminal, a dry-bulk terminal located in Hawesville,
Kentucky and a liquids/dry-bulk facility located in Blytheville,
Arkansas;
o all of the ownership interests in General Stevedores, L.P., which
operates a break-bulk terminal facility located along the Houston Ship
Channel, acquired July 31, 2005; and
o our Kinder Morgan Blackhawk terminal located in Black Hawk County,
Iowa, acquired in August 2005.
Combined, these operations accounted for incremental amounts of earnings
before depreciation, depletion and amortization of $15.1 million, revenues of
$30.0 million and operating expenses of $14.9 million in the first quarter of
2006. Most of the increase in operating results from acquisitions was
attributable to our Texas petroleum coke bulk terminals, which we acquired from
Trans-Global Solutions, Inc. for an aggregate consideration of approximately
$247.2 million. The acquired assets include facilities at the Port of Houston,
the Port of Beaumont and the TGS Deepwater Terminal located on the Houston Ship
Channel. Combined, these terminal operations accounted for incremental amounts
of earnings before depreciation, depletion and amortization of $13.0 million,
revenues of $24.7 million and operating expenses of $11.7 million in the first
quarter of 2006.
For all other terminal operations (those owned during both years), earnings
before depreciation, depletion and amortization were essentially flat,
increasing $0.7 million (1%) in the first quarter of 2006 versus the first
quarter of
62
2005. The overall increase included a $2.3 million (14%) increase from our
Pasadena and Galena Park, Texas Gulf Coast liquids facilities, two large
terminals located on the Houston Ship Channel that serve as a distribution hub
for Houston's crude oil refineries. The increase was driven by higher revenues
from excess throughput charges, incremental sales of petroleum transmix, new
customer agreements and higher truck loading rack service fees. We also
benefited from record volumes of steel imports at our bulk terminal located in
Fairless Hills, Pennsylvania and record volumes of fertilizer imports at both
our Port Sutton, Florida terminal and our Elizabeth River bulk terminal located
in Chesapeake, Virginia.
The overall increase in earnings from terminals owned both quarters was
offset by a $1.2 million (14%) decrease from our Lower Mississippi River
(Louisiana) region, largely due to a $2.3 million decrease from our
International Marine Terminals facility, a Louisiana partnership owned 66 2/3%
by us. IMT, located in Port Sulphur, Louisiana, suffered property damage and a
general loss of business due to the effects of Hurricane Katrina, which struck
the Gulf Coast in the third quarter of 2005.
For our entire liquids terminals combined, total throughput volumes
decreased 3.6% in the first quarter of 2006, versus the same period in 2005. The
decrease was primarily due to lower petroleum volumes at our Pasadena terminal,
due in large part to the continued shutdown of a Texas-based refinery that was
impacted by Hurricane Rita, which struck the Texas-Louisiana Gulf Coast in the
third quarter of 2005; however, earnings before depreciation, depletion and
amortization were still up in first quarter 2006 versus first quarter 2005 due
to the factors discussed above. Through a combination of business acquisitions
and internal capital spending, we have increased our liquids leaseable capacity
by 6.2 million barrels (17%) since the end of the first quarter of 2005, while
at the same time, increasing our liquids utilization rate (the ratio of our
actual capacity to our estimated potential capacity) by 1.1%.
Segment Details
Segment revenues for all terminals owned during both three month periods
increased $11.8 million (7%) in the first quarter of 2006, when compared to the
same prior-year period. The quarter-to-quarter increase was primarily due to the
following:
o a $4.4 million (19%) increase from our Mid-Atlantic region, due
primarily to higher steel volumes at our Fairless Hills terminal, and
to higher tank rentals and cement and petroleum coke volumes at our
Shipyard River terminal, located in Charleston, South Carolina;
o a $3.5 million (15%) increase from our Pasadena and Galena Park Gulf
Coast facilities, as discussed above; and
o a $3.3 million (96%) increase from engineering and terminal design
services, due to both incremental revenues from new clients and
increased revenues from existing clients starting new projects due to
economic growth.
Operating expenses for all terminals owned during both quarters increased
$15.5 million (18%) in the first quarter of 2006, when compared to the first
quarter of 2005. The overall increase in segment operating expenses included
increases of:
o $4.9 million (26%) from our Louisiana terminals, largely due to
additional insurance, property damage and demurrage expenses related
to hurricanes Katrina and Rita;
o $3.6 million (110%) from engineering-related services, due primarily
to higher salary, overtime and other employee-related expenses, as
well as increased contract labor, all associated with the increased
project work described above;
o $2.8 million (21%) from our Mid-Atlantic terminals, largely due to
higher operating and maintenance expenses at our Fairless Hills
terminal, due to the increase in steel products handled. This includes
higher wharfage, trucking and general maintenance expenses;
63
o $1.4 million (10%) from our Midwest terminals, mainly due to a $0.5
million increase at our Cora, Illinois coal terminal and a $0.4
million increase at our Argo, Illinois liquids terminal facility. Both
increases were largely due to higher operating and maintenance
expenses--related to a 32% increase in coal transfer volumes at Cora,
and a 15% increase in liquids throughput volume at Argo;
o $1.2 million (17%) from our Pasadena and Galena Park, Texas Gulf Coast
terminals, due to incremental labor expenses, power expenses and
permitting fees; and
o $1.1 million (18%) from our Southeast region, due primarily to higher
labor and equipment maintenance at our Port Sutton, Florida bulk
terminal, related to higher bulk tonnage.
The segment's other income items increased $2.6 million in the first
quarter of 2006, versus the first quarter of 2005. The increase included
incremental income of $1.8 million, recognized in the first quarter of 2006,
related to a favorable settlement associated with our purchase of the Kinder
Morgan St. Gabriel terminal in September 2002. The overall increase in other
income also included a $1.2 million increase due to a disposal loss, recognized
in the first quarter of 2005, on warehouse property at our Elizabeth River bulk
terminal.
The segment's income tax expenses decreased $1.7 million (46%) in the first
three months of 2006, compared to the first three months of 2005. The decrease
was due to lower taxable earnings from Kinder Morgan Bulk Terminals, Inc., the
tax-paying entity that owns many of our bulk terminal businesses.
Compared to the first quarter of 2005, non-cash depreciation, depletion and
amortization charges increased $5.1 million (42%) in the first quarter of 2006.
In addition to increases associated with normal capital spending, the periodic
increase reflected higher depreciation charges due to the terminal acquisitions
we have made since the end of the first quarter of 2005. Collectively, these
terminal assets, described above, accounted for incremental depreciation
expenses of $4.3 million in the first quarter of 2006.
Other
Three Months Ended March 31,
----------------------------
2006 2005
---------- ----------
(In thousands-income/(expense))
General and administrative expenses............ $ (60,883) $ (73,852)
Unallocable interest, net...................... (76,967) (60,047)
Minority interest.............................. (2,370) (2,388)
---------- ----------
Interest and corporate administrative expenses $ (140,220) $ (136,287)
========== ==========
Items not attributable to any segment include general and administrative
expenses, unallocable interest income, interest expense and minority interest.
General and administrative expenses include such items as salaries and
employee-related expenses, payroll taxes, insurance, office supplies and
rentals, unallocated litigation and environmental expenses, and shared corporate
services, including accounting, information technology, human resources, and
legal fees.
Our total general and administrative expenses decreased $13.0 million (18%)
in the first quarter of 2006, when compared to the first quarter of 2005. The
overall decrease in general and administrative expenses included a decrease of
$27.4 million related to unallocated litigation and environmental settlement
expenses that we recognized in the first quarter of 2005--consisting of a $25
million expense for a settlement reached between us and a joint venture partner
on our Kinder Morgan Tejas natural gas pipeline system, a $5.4 million expense
related to settlements of environmental matters at certain of our operating
sites located in the State of California, and a $3.0 million decrease in expense
related to favorable settlements of obligations that Enron Corp. had to us in
conjunction with derivatives we were accounting for as hedges under Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities."
Offsetting the decrease related to unallocated litigation and environmental
settlement expenses were higher general and administrative expenses, in the
first quarter of 2006, in the amount of $14.4 million, primarily due to higher
period-to-period corporate services--due in part to acquisitions made since the
first quarter of 2005, and to higher employee benefit costs, payroll taxes, and
corporate insurance expenses. Currently and prospectively, we
64
face the challenge of rising general and administrative expenses due to
increasing employee health care costs and business insurance costs; however, we
continue to manage aggressively our infrastructure expense and we remain focused
on maintaining affordable expense levels and eliminating unnecessary overhead
expenses.
Unallocable interest expense, net of interest income, increased $16.9
million (28%) in the first quarter of 2006, compared to the same year-earlier
period. The increase was due to both higher quarter-to-quarter average debt
levels and higher effective interest rates. The increase in our average
borrowings was due to higher capital spending--related to internal expansions
and improvements, external assets and businesses acquired since the end of the
first quarter of 2005, and a net increase of $300 million in principal amount of
long-term senior notes since the beginning of 2005. On March 15, 2005, we both
closed a public offering of $500 million in principal amount of senior notes and
retired a principal amount of $200 million. We issue senior notes in order to
refinance commercial paper borrowings used for both internal capital spending
and acquisition expenditures.
The increase in our average borrowing rates reflects a general rise in
variable interest rates since the end of the first quarter of 2005. The weighted
average interest rate on all of our borrowings increased 13% in the first
quarter of 2006, compared to the first quarter of 2005. We use interest rate
swap agreements to help manage our interest rate risk. The swaps are contractual
agreements we enter into in order to transform a portion of the underlying cash
flows related to our long-term fixed rate debt securities into variable rate
debt in order to achieve our desired mix of fixed and variable rate debt.
However, in a period of rising interest rates, these swaps will result in
period-to-period increases in our interest expense. For more information on our
interest rate swaps, see Note 10 to our consolidated financial statements,
included elsewhere in this report.
Financial Condition
Capital Structure
We attempt to maintain a conservative overall capital structure, with a
long-term target mix of approximately 60% equity and 40% debt. The following
table illustrates the sources of our invested capital (dollars in thousands). In
addition to our results of operations, these balances are affected by our
financing activities as discussed below:
March 31, December 31,
2006 2005
----------- -----------
Long-term debt, excluding market value of
interest rate swaps................................ $ 5,704,920 $ 5,220,887
Minority interest.................................. 131,087 42,331
Partners' capital, excluding accumulated other
comprehensive loss................................. 4,682,849 4,693,414
----------- -----------
Total capitalization............................. 10,518,856 9,956,632
Short-term debt, less cash and cash equivalents.... (32,636) (12,108)
----------- -----------
Total invested capital........................... $10,486,220 $ 9,944,524
=========== ===========
Capitalization:
Long-term debt, excluding market value of
interest rate swaps.............................. 54.2% 52.4%
Minority interest................................ 1.3% 0.4%
Partners' capital, excluding accumulated
other comprehensive loss........................ 44.5% 47.2%
----------- -----------
100.0% 100.0%
=========== ===========
Invested Capital:
Total debt, less cash and cash equivalents and
excluding Market value of interest rate swaps.. 54.1% 52.4%
Partners' capital and minority interest,
excluding accumulated other comprehensive loss... 45.9% 47.6%
----------- -----------
100.0% 100.0%
=========== ===========
Our primary cash requirements, in addition to normal operating expenses,
are debt service, sustaining capital expenditures, expansion capital
expenditures and quarterly distributions to our common unitholders, Class B
unitholders and general partner. In addition to utilizing cash generated from
operations, we could meet our cash requirements (other than distributions to our
common unitholders, Class B unitholders and general partner) through borrowings
under our credit facility, issuing short-term commercial paper, long-term notes
or additional common units or the proceeds from purchases of additional i-units
by KMR with the proceeds from issuances of KMR shares.
65
In general, we expect to fund:
o cash distributions and sustaining capital expenditures with existing
cash and cash flows from operating activities;
o expansion capital expenditures and working capital deficits with
retained cash (resulting from including i-units in the determination
of cash distributions per unit but paying quarterly distributions on
i-units in additional i-units rather than cash), additional
borrowings, the issuance of additional common units or the proceeds
from purchases of additional i-units by KMR;
o interest payments with cash flows from operating activities; and
o debt principal payments with additional borrowings, as such debt
principal payments become due, or by the issuance of additional common
units or the 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 part of our financial strategy, we try to maintain an investment-grade
credit rating, which involves, among other things, the issuance of additional
limited partner units in connection with our acquisitions and internal growth
activities in order to maintain acceptable financial ratios, including total
debt to total capital. On August 2, 2005, following KMI's announcement of its
proposed acquisition of Terasen Inc., Standard & Poor's Rating Services placed
our debt credit ratings, as well as KMI's ratings, on CreditWatch with negative
implications. On December 5, 2005, S&P affirmed our debt credit ratings, as well
as KMI's ratings, with a negative outlook and removed them from CreditWatch. On
February 23, 2006, Moody's Investors Service, which also publishes credit
ratings on commercial entities, affirmed our debt credit ratings and changed its
rating outlook from negative to stable.
Short-term Liquidity
Our principal sources of short-term liquidity are:
o our $1.6 billion five-year senior unsecured revolving credit facility
that matures August 18, 2010;
o our $250 million nine-month unsecured revolving credit facility that
matures November 21, 2006;
o our $1.85 billion short-term commercial paper program (which was
increased from $1.6 billion to $1.85 billion in April 2006, and which
is supported by our bank credit facilities, with the amount available
for borrowing under our credit facilities being reduced by our
outstanding commercial paper borrowings); and
o cash from operations (discussed following).
Borrowings under our two credit facilities can be used for general
corporate purposes and as a backup for our commercial paper program. There were
no borrowings under our five-year credit facility as of December 31, 2005; there
were no borrowings under either credit facility as of March 31, 2006.
We provided for additional liquidity by maintaining a sizable amount of
excess borrowing capacity related to our commercial paper program and long-term
revolving credit facility. After inclusion of our outstanding commercial paper
borrowings and letters of credit, the remaining available borrowing capacity
under our bank credit facilities was $339.5 million as of March 31, 2006.
66
As of March 31, 2006, our outstanding short-term debt was $1,060.8 million.
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. Currently, we believe our liquidity to be adequate.
Some of our customers are experiencing, or may experience in the future,
severe financial problems that have had or may have a significant impact on
their creditworthiness. We are working to implement, to the extent allowable
under applicable contracts, tariffs and regulations, prepayments and other
security requirements, such as letters of credit, to enhance our credit position
relating to amounts owed from these customers. We cannot provide assurance that
one or more of our financially distressed customers will not default on their
obligations to us or that such a default or defaults will not have a material
adverse effect on our business, financial position, future results of
operations, or future cash flows.
Long-term Financing
In addition to our principal sources of short-term liquidity listed above,
we could meet our cash requirements (other than distributions to our common
unitholders, Class B unitholders and general partner) through issuing long-term
notes or additional common units, or the proceeds from purchases of additional
i-units by KMR with the proceeds from issuances of KMR shares.
We are subject, however, to changes in the equity markets for our limited
partner units, and there can be no assurance we will be able or willing to
access the public or private markets for our limited partner units in the
future. If we were unable or unwilling to issue additional limited partner
units, we would be required to either restrict potential future acquisitions or
pursue other debt financing alternatives, some of which could involve higher
costs or negatively affect our credit ratings.
All of our long-term debt securities issued to date, other than those
issued under our revolving credit facilities or those issued by our subsidiaries
and operating partnerships, generally have the same terms except for interest
rates, maturity dates and prepayment premiums. All of our outstanding debt
securities are unsecured obligations that rank equally with all of our other
senior debt obligations; however, a modest amount of secured debt has been
incurred by some of our operating partnerships and subsidiaries. Our fixed rate
notes provide that we may redeem the notes at any time at a price equal to 100%
of the principal amount of the notes plus accrued interest to the redemption
date plus a make-whole premium.
As of March 31, 2006, our total liability balance due on the various series
of our senior notes was $4,489.8 million, and the total liability balance due on
the borrowings of our operating partnerships and subsidiaries was $163.8
million. For additional information regarding our debt and credit facilities,
see Note 9 to our consolidated financial statements included in our Form 10-K
for the year ended December 31, 2005.
Operating Activities
Net cash provided by operating activities was $176.0 million for the three
months ended March 31, 2006, versus $259.5 million in the comparable period of
2005. The period-to-period decrease of $83.5 million (32%) in cash flow from
operations consisted of:
o an $81.2 million decrease in cash inflows relative to net changes in
working capital items--mainly due to timing differences that resulted
in higher cash outflows with regard to our net accounts payables and
receivables, and to additional payments for natural gas imbalance
settlements and accrued interest;
o a $16.6 million 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 quarter of 2006 for pipeline project
costs, studies and business development charges, largely related to
our Rockies Express pipeline, and for higher payments made for natural
gas liquids inventory on our North System. In the second quarter of
2006, we will transfer accumulated project costs related to our
Rockies Express pipeline to within "Property, plant and equipment,
net" on our consolidated balance sheet;
67
o a $9.0 million increase related to higher distributions received from
equity investments--chiefly due to higher distributions received from
Red Cedar Gathering Company in the first three months of 2006,
partially offset by lower distributions from Cortez Pipeline Company.
The change reflects higher and lower year-over-year net income in the
first quarter of 2006 versus the first quarter of 2005 for Red Cedar
and Cortez, respectively; and
o a $5.3 million increase in cash from overall higher partnership
income, net of non-cash items including depreciation charges,
undistributed earnings from equity investments, and litigation and
environmental expenses that impacted earnings but not cash. The higher
partnership income reflects the increase in cash earnings from our
four reportable business segments in the first three months of 2006,
as discussed above in "-Results of Operations."
Investing Activities
Net cash used in investing activities was $479.9 million for the three
month period ended March 31, 2006, compared to $168.0 million in the comparable
2005 period. The $311.9 million increase in cash used in investing activities
was primarily attributable to:
o a $233.5 million increase due to higher expenditures made for
strategic business acquisitions. In the first quarter of 2006, we
spent $240.0 million to acquire Entrega Gas Pipeline LLC, and in the
first quarter last year, we spent $6.5 million, which primarily
related to our acquisition of a 64.5% gross working interest in the
Claytonville oil field unit located in West Texas;
o a $49.9 million (35%) increase in capital expenditures;
o a $15.0 million increase in margin deposits--associated with hedging
activities utilizing energy derivative instruments; and
o a $7.9 million increase related to additional investments in
underground natural gas storage volumes and to higher payments made
for natural gas liquids line-fill on our North System.
Including expansion and maintenance projects, our capital expenditures were
$193.7 million in the first quarter of 2006, compared to $143.8 million in the
same prior-year period. Our sustaining capital expenditures were $25.7 million
for the first three months of 2006, compared to $24.2 million for the first
three months of 2005. Sustaining capital expenditures are defined as capital
expenditures which do not increase the capacity of an asset. Based on our 2006
sustaining capital expenditure forecast, our forecasted expenditures for the
remaining nine months of 2006 for sustaining capital expenditures were
approximately $144.3 million. This amount has been committed primarily for the
purchase of plant and equipment. All of our capital expenditures, with the
exception of sustaining capital expenditures, are discretionary.
Since the beginning of 2006, we made the following announcements related to
our investing activities:
o On March 9, 2006, we announced that we have entered into a long-term
agreement with Drummond Coal Sales, Inc. that will support a $70
million expansion of our Pier IX bulk terminal located in Newport
News, Virginia. The agreement has a term that can be extended for up
to 30 years. The project includes the construction of a new ship dock
and the installation of additional equipment; it is expected to
increase throughput at the terminal by approximately 30% and will
allow the terminal to begin receiving shipments of imported coal. The
expansion is expected to be completed in the first quarter of 2008.
Upon completion, the terminal will have an import capacity of up to 9
million tons annually. Currently, our Pier IX terminal can store
approximately 1.4 million tons of coal and 30,000 tons of cement on
its 30-acre storage site; and
o On April 6, 2006, we announced the second of two investments in our
CALNEV refined petroleum products pipeline system. Combined, the $25
million in capital improvements will upgrade and expand pipeline
capacity and help provide sufficient fuel supply to the Las Vegas,
Nevada market for the next several years. The first project, estimated
to cost approximately $10 million, involves pipeline expansions that
will increase current transportation capacity by 3,200 barrels per day
(2.2%), as well as the construction of two new 80,000
68
barrel storage tanks at our Las Vegas terminal. The second project,
expected to cost approximately $15 million, includes the installation
of new and upgraded pumping equipment and piping at our Colton,
California terminal, a new booster station with two pumps at Cajon,
California, and piping upgrades at our Las Vegas terminal. In
addition, we are currently exploring a $300 to $400 million future
expansion that would increase capacity on the pipeline to
approximately 220,000 barrels per day by 2010. Currently, our CALNEV
Pipeline can transport approximately 140,000 barrels of refined
products per day;
o On April 7, 2006, Kinder Morgan Production Company L.P. purchased
various oil and gas properties from Journey Acquisition - I, L.P. and
Journey 2000, L.P. The properties are primarily located in the Permian
Basin area of West Texas, produce approximately 850 barrels of oil
equivalent per day net, and include some fields with enhanced oil
recovery development potential near our current carbon dioxide
operations. During the next several months, we will perform technical
evaluations to confirm the carbon dioxide enhanced oil recovery
potential and generate definitive plans to develop this potential if
proven to be economic. The purchase price plus the anticipated
investment to both further develop carbon dioxide enhanced oil
recovery and construct a new carbon dioxide supply pipeline on all of
the acquired properties is approximately $115 million. However, since
we intend to divest in the near future those acquired properties that
are not candidates for carbon dioxide enhanced oil recovery, our total
investment is likely to be considerably less.
o On April 19, 2006, our general partner's and KMR's board of directors
approved a $75 million expansion of our Texas intrastate natural gas
pipeline group's natural gas storage capabilities. The expansion will
include the development of a third natural gas storage cavern at our
North Dayton, Texas storage facility, which we acquired in August
2005. The expansion will more than double working capacity to over 9
billion cubic feet and is expected to be in service by April 1, 2009;
o On April 19, 2006, we announced that the pipeline portion of our $210
million Pacific operations' East Line expansion project, initially
proposed in October 2002, had been completed and the new breakout tank
farm near El Paso, Texas was scheduled to be in service around June 1,
2006. This expansion project will significantly increase pipeline
transportation capacity for refined petroleum products between El Paso
and Phoenix, Arizona; and
o On April 19, 2006, we and our partner Sempra Energy announced that we
are moving forward on the approximate $4.4 billion Rockies Express
Pipeline project after obtaining binding commitments from creditworthy
shippers for all 1.8 billion cubic feet of transportation capacity on
the 1,323-mile pipeline that will move natural gas from the Rocky
Mountain Region to the eastern United States. Service on the 710-mile
segment of the Rockies Express Pipeline that extends from Cheyenne to
eastern Missouri is expected to commence on January 1, 2008, and the
entire project is expected to be completed by June 2009, subject to
regulatory approvals.
In addition, interim service has begun on the western portion of the
Entrega Pipeline (that extends from Meeker, Colorado to Wamsutter,
Wyoming). The construction of the remainder of Entrega (that extends
from Wamsutter to Cheyenne, Wyoming) is scheduled to begin this
summer, and the entire system is expected to be in service by January
1, 2007. In April 2006, Rockies Express Pipeline LLC merged with and
into Entrega Gas Pipeline LLC, and the remaining entity was renamed
Rockies Express Pipeline LLC. Going forward, the entire pipeline
system will be known as the Rockies Express Pipeline. We have ordered
substantially all of the piping required for the Rockies Express and
the $500 million Kinder Morgan Louisiana Pipeline projects at fixed
prices consistent with project budgets.
Financing Activities
Net cash provided by financing activities amounted to $324.4 million for
the three months ended March 31, 2006; for the same quarter last year, we used
$91.5 million in financing activities. The $415.9 million overall increase in
cash inflows provided by our financing activities was primarily due to:
o a $343.0 million increase from overall debt financing activities,
which include our issuances and payments of debt and our debt issuance
costs. The increase was primarily due to a $638.6 million increase due
to higher net commercial paper borrowings in the first quarter of
2006, partly offset by a $294.4 million decrease due to
69
net changes in the principal amount of senior notes. On March 15,
2005, we closed a public offering of $500 million in principal amount
of 5.80% senior notes and repaid $200 million of 8.0% senior notes
that matured on that date. The 5.80% senior notes are due March 15,
2035. We received proceeds from the issuance of the notes, after
underwriting discounts and commissions, of approximately $494.4
million, and we used the proceeds to repay the 8.0% senior notes and
to reduce our commercial paper debt;
o a $90.6 million increase from contributions from minority interests,
principally due to Sempra Energy's $80.0 million contribution for its
33 1/3% share of the purchase price of Entrega Pipeline LLC, discussed
above in "--Investing Activities";
o a $20.3 million increase from net changes in cash book overdrafts,
which represent checks issued but not yet endorsed; and
o a $37.5 million decrease from higher partnership distributions. The
increase 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
Distributions to all partners, consisting of our common and Class B
unitholders, our general partner and minority interests, totaled $261.0 million
in the first quarter 2006, compared to $223.5 million in the first quarter of
2005. Our partnership agreement requires that we distribute 100% of "Available
Cash," as defined in our partnership agreement, to our partners within 45 days
following the end of each calendar quarter in accordance with their respective
percentage interests. Available Cash consists generally of all of our cash
receipts, including cash received by our operating partnerships and net
reductions in reserves, less cash disbursements and net additions to reserves
and amounts payable to the former general partner of SFPP, L.P. in respect of
its remaining 0.5% interest in SFPP.
Our general partner is granted discretion by our partnership agreement,
which discretion has been delegated to KMR, subject to the approval of our
general partner in certain cases, to establish, maintain and adjust reserves for
future operating expenses, debt service, maintenance capital expenditures, rate
refunds and distributions for the next four quarters. These reserves are not
restricted by magnitude, but only by type of future cash requirements with which
they can be associated. When KMR determines our quarterly distributions, it
considers current and expected reserve needs along with current and expected
cash flows to identify the appropriate sustainable distribution level.
Our general partner and owners of our common units and Class B units
receive distributions in cash, while KMR, the sole owner of our i-units,
receives distributions in additional i-units. We do not distribute cash to
i-unit owners but retain the cash for use in our business. However, the cash
equivalent of distributions of i-units is treated as if it had actually been
distributed for purposes of determining the distributions to our general
partner. Each time we make a distribution, the number of i-units owned by KMR
and the percentage of our total units owned by KMR increase automatically under
the provisions of our partnership agreement.
Available cash is initially distributed 98% to our limited partners and 2%
to our general partner. These distribution percentages are modified to provide
for incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
o first, 98% to the owners of all classes of units pro rata and 2% to
our general partner until the owners of all classes of units have
received a total of $0.15125 per unit in cash or equivalent i-units
for such quarter;
o second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the
owners of all classes of units have received a total of $0.17875 per
unit in cash or equivalent i-units for such quarter;
70
o third, 75% of any available cash then remaining to the owners of all
classes of units pro rata and 25% to our general partner until the
owners of all classes of units have received a total of $0.23375 per
unit in cash or equivalent i-units for such quarter; and
o fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units
in cash and to owners of i-units in the equivalent number of i-units,
and 50% to our general partner.
Incentive distributions are generally defined as all cash distributions
paid to our general partner that are in excess of 2% of the aggregate value of
cash and i-units being distributed. Our general partner's incentive distribution
that we declared for 2005 was $473.9 million, while the incentive distribution
paid to our general partner during 2005 was $454.3 million. The difference
between declared and paid distributions is due to the fact that our
distributions for the fourth quarter of each year are declared and paid in the
first quarter of the following year.
On February 14, 2006, we paid a quarterly distribution of $0.80 per unit
for the fourth quarter of 2005. This distribution was 8% greater than the $0.74
distribution per unit we paid for the fourth quarter of 2004 and 5% greater than
the $0.76 distribution per unit we paid for the first quarter of 2005. We paid
this distribution in cash to our common unitholders and to our Class B
unitholders. KMR, our sole i-unitholder, received additional i-units based on
the $0.80 cash distribution per common unit. We believe that future operating
results will continue to support similar levels of quarterly cash and i-unit
distributions; however, no assurance can be given that future distributions will
continue at such levels.
Incentive distributions are generally defined as all cash distributions
paid to our general partner that are in excess of 2% of the aggregate value of
cash and i-units being distributed. Our general partner's incentive distribution
for the distribution that we declared for the first quarter of 2006 was $128.3
million. Our general partner's incentive distribution for the distribution that
we declared for the first quarter of 2005 was $111.1 million. Our general
partner's incentive distribution that we paid during the first quarter of 2006
to our general partner (for the fourth quarter of 2005) was $125.6 million. Our
general partner's incentive distribution that we paid during the first quarter
of 2005 to our general partner (for the fourth quarter of 2004) was $106.0
million.
We believe that future operating results will continue to support similar
levels of quarterly cash and i-unit distributions; however, no assurance can be
given that future distributions will continue at such levels.
Litigation and Environmental
As of March 31, 2006, we have recorded a total reserve for environmental
claims, without discounting and without regard to anticipated insurance
recoveries, in the amount of $50.1 million. In addition, we have recorded a
receivable of $27.6 million for expected cost recoveries that have been deemed
probable. The reserve is primarily established to address and clean up soil and
ground water impacts from former releases to the environment at facilities we
have acquired. Reserves for each project are generally established by reviewing
existing documents, conducting interviews and performing site inspections to
determine the overall size and impact to the environment. Reviews are made on a
quarterly basis to determine the status of the cleanup and the costs associated
with the effort. In assessing environmental risks in conjunction with proposed
acquisitions, we review records relating to environmental issues, conduct site
inspections, interview employees, and, if appropriate, collect soil and
groundwater samples.
As of March 31, 2006, we have recorded a total reserve for legal fees,
transportation rate cases and other litigation liabilities in the amount of
$135.6 million. The reserve is primarily related to various claims from lawsuits
arising from our Pacific operations' pipeline transportation rates, and the
contingent amount is based on both the circumstances of probability and
reasonability of dollar estimates. We regularly assess the likelihood of adverse
outcomes resulting from these claims in order to determine the adequacy of our
liability provision. We believe we have established adequate environmental and
legal reserves such that the resolution of pending environmental matters and
litigation will not have a material adverse impact on our business, cash flows,
financial position or results of operations. However, changing circumstances
could cause these matters to have a material adverse impact.
71
Pursuant to our continuing commitment to operational excellence and our
focus on safe, reliable operations, we have implemented, and intend to implement
in the future, enhancements to certain of our operational practices in order to
strengthen our environmental and asset integrity performance. These enhancements
have resulted and may result in higher operating costs and sustaining capital
expenditures; however, we believe these enhancements will provide us the greater
long term benefits of improved environmental and asset integrity performance.
Please refer to Notes 3 and 14, respectively, to our consolidated financial
statements included elsewhere in this report for additional information
regarding pending litigation, environmental and asset integrity matters.
Certain Contractual Obligations
There have been no material changes in 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, 2005 in our 2005 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:
o price trends and overall demand for natural gas liquids, refined
petroleum products, oil, carbon dioxide, natural gas, coal and other
bulk materials and chemicals in North America;
o economic activity, weather, alternative energy sources, conservation
and technological advances that may affect price trends and demand;
o changes in our tariff rates implemented by the Federal Energy
Regulatory Commission or the California Public Utilities Commission;
o our ability to acquire new businesses and assets and integrate those
operations into our existing operations, as well as our ability to
make expansions to our facilities;
o difficulties or delays experienced by railroads, barges, trucks, ships
or pipelines in delivering products to or from our terminals or
pipelines;
o our ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
o shut-downs or cutbacks at major refineries, petrochemical or chemical
plants, ports, utilities, military bases or other businesses that use
our services or provide services or products to us;
o crude oil and natural gas production from exploration and production
areas that we serve, including, among others, the Permian Basin area
of West Texas;
o changes in laws or regulations, third-party relations and approvals,
decisions of courts, regulators and governmental bodies that may
adversely affect our business or our ability to compete;
o changes in accounting pronouncements that impact the measurement of
our results of operations, the timing of when such measurements are to
be made and recorded, and the disclosures surrounding these
activities;
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o our ability to offer and sell equity securities and debt securities or
obtain debt financing in sufficient amounts to implement that portion
of our business plan that contemplates growth through acquisitions of
operating businesses and assets and expansions of our facilities;
o our indebtedness could make us vulnerable to general adverse economic
and industry conditions, limit our ability to borrow additional funds,
and/or place us at competitive disadvantages compared to our
competitors that have less debt or have other adverse consequences;
o interruptions of electric power supply to our facilities due to
natural disasters, power shortages, strikes, riots, terrorism, war or
other causes;
o our ability to obtain insurance coverage without significant levels of
self-retention of risk;
o acts of nature, sabotage, terrorism or other similar acts causing
damage greater than our insurance coverage limits;
o capital markets conditions;
o the political and economic stability of the oil producing nations of
the world;
o national, international, regional and local economic, competitive and
regulatory conditions and developments;
o the ability to achieve cost savings and revenue growth;
o inflation;
o interest rates;
o the pace of deregulation of retail natural gas and electricity;
o foreign exchange fluctuations;
o the timing and extent of changes in commodity prices for oil, natural
gas, electricity and certain agricultural products;
o the extent of our success in discovering, developing and producing oil
and gas reserves, including the risks inherent in exploration and
development drilling, well completion and other development
activities;
o engineering and mechanical or technological difficulties with
operational equipment, in well completions and workovers, and in
drilling new wells;
o the uncertainty inherent in estimating future oil and natural gas
production or reserves;
o the timing and success of business development efforts; and
o unfavorable results of litigation and the fruition of contingencies
referred to in Note 16 to our consolidated financial statements
included elsewhere in this report.
There is no assurance that any of the actions, events or results of the
forward-looking statements will occur, or if any of them do, what impact they
will have on our results of operations or financial condition. Because of these
uncertainties, you should not put undue reliance on any forward-looking
statements.
See Item 1A "Risk Factors" of our Annual Report on Form 10-K for the year
ended December 31, 2005, for a more detailed description of these and other
factors that may affect the forward-looking statements. When considering
forward-looking statements, one should keep in mind the risk factors described
in our 2005 Form 10-K
73
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,
2005, in Item 7A of our 2005 Form 10-K report. For more information on our risk
management activities, see Note 10 to our consolidated financial statements
included elsewhere in this report.
Item 4. Controls and Procedures.
As of March 31, 2006, our management, including our Chief Executive Officer
and Chief Financial Officer, has evaluated the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to Rule 13a-15(b)
under the Securities Exchange Act of 1934. There are inherent limitations to the
effectiveness of any system of disclosure controls and procedures, including the
possibility of human error and the circumvention or overriding of the controls
and procedures. Accordingly, even effective disclosure controls and procedures
can only provide reasonable assurance of achieving their control objectives.
Based upon and as of the date of the evaluation, our Chief Executive Officer and
our Chief Financial Officer concluded that the design and operation of our
disclosure controls and procedures were effective in all material respects to
provide reasonable assurance that information required to be disclosed in the
reports we file and submit under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported as and when required, and is
accumulated and communicated to our management, including our Chief Executive
Officer and Chief Financial Officer, as appropriate, to allow timely decisions
regarding required disclosure. There has been no change in our internal control
over financial reporting during the quarter ended March 31, 2006 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, Environmental and Other Contingencies," which is
incorporated in this item by reference.
Item 1A. Risk Factors.
There have been no material changes to the risk factors disclosed in Item
1A "Risk Factors" in our Annual Report on Form 10-K for the year ended December
31, 2005.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Item 5. Other Information.
None.
Item 6. Exhibits.
4.1 -- Certain instruments with respect to long-term debt of Kinder Morgan
Energy Partners, L.P. and its consolidated subsidiaries which relate to
debt that does not exceed 10% of the total assets of Kinder Morgan Energy
Partners, L.P. and its consolidated subsidiaries are omitted pursuant to
Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601. Kinder
Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the
Securities and Exchange Commission a copy of each such instrument upon
request.
*10.1 -- Nine-Month Credit Agreement dated as of February 22, 2006 among Kinder
Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank,
National Association as Administrative Agent (filed as Exhibit 10.9 to
Kinder Morgan Energy Partners, L.P.'s Form 10-K for 2005, filed on March
16, 2006).
11 -- Statement re: computation of per share earnings.
12 -- Statement re: computation of ratio of earnings to fixed charges.
31.1 -- Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the Securities
Exchange Act of 1934, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
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31.2 -- Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the Securities
Exchange Act of 1934, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 -- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 -- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
- ----------
* Asterisk indicates exhibits incorporated by reference as indicated; all
other exhibits are filed herewith, except as noted otherwise.
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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 A. Dang
------------------------------
Kimberly A. Dang
Vice President and Chief Financial Officer
Date: May 9, 2006