F O R M 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2003
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 1-11234
KINDER MORGAN ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0380342
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
500 Dallas Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-369-9000
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No
Indicate by check mark whether the registrant is an accelerated
filer (as defined by Rule 12b-2 of the Securities Exchange Act of
1934). Yes [X] No [ ]
The Registrant had 134,703,808 common units outstanding at July 31, 2003.
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
PART I. FINANCIAL INFORMATION
Item 1: Financial Statements (Unaudited)......................... 3
Consolidated Statements of Income - Three and Six
Months Ended June 30, 2003 and 2002.................... 3
Consolidated Balance Sheets - June 30, 2003 and
December 31, 2002...................................... 4
Consolidated Statements of Cash Flows - Six Months
Ended June 30, 2003 and 2002........................... 5
Notes to Consolidated Financial Statements............. 6
Item 2: Management's Discussion and Analysis of Financial
Condition and Results of Operations...................... 48
Results of Operations.................................. 48
Financial Condition.................................... 57
Information Regarding Forward-Looking Statements....... 61
Item 3: Quantitative and Qualitative Disclosures About Market
Risk..................................................... 62
Item 4: Controls and Procedures.................................. 62
PART II. OTHER INFORMATION
Item 1: Legal Proceedings........................................ 63
Item 2: Changes in Securities and Use of Proceeds................ 63
Item 3: Defaults Upon Senior Securities.......................... 63
Item 4: Submission of Matters to a Vote of Security Holders...... 63
Item 5: Other Information........................................ 63
Item 6: Exhibits and Reports on Form 8-K......................... 63
Signatures............................................... 65
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Unit Amounts)
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
----------------------------------------------------------
2003 2002 2003 2002
------------- ------------- ------------- ---------
Revenues
Natural gas sales............................................ $ 1,239,070 $ 722,529 $ 2,617,358 $ 1,192,397
Services..................................................... 346,888 308,045 681,829 603,288
Product sales and other...................................... 78,489 60,362 154,098 98,316
--------- --------- --------- ---------
1,664,447 1,090,936 3,453,285 1,894,001
--------- --------- --------- ---------
Costs and Expenses
Gas purchases and other costs of sales....................... 1,235,375 712,476 2,610,789 1,160,569
Operations and maintenance................................... 101,775 98,464 195,674 185,755
Fuel and power............................................... 23,779 21,147 48,917 39,531
Depreciation and amortization................................ 53,758 42,623 103,563 83,949
General and administrative................................... 34,157 30,210 68,836 59,742
Taxes, other than income taxes............................... 16,041 13,669 30,792 26,252
--------- --------- --------- ---------
1,464,885 918,589 3,058,571 1,555,798
--------- --------- --------- ---------
Operating Income............................................... 199,562 172,347 394,714 338,203
Other Income (Expense)
Earnings from equity investments............................. 22,618 24,297 46,923 47,568
Amortization of excess cost of equity investments............ (1,394) (1,394) (2,788) (2,788)
Interest, net................................................ (44,896) (43,864) (89,821) (82,886)
Other, net................................................... 1,508 435 1,785 385
Minority Interest.............................................. (2,125) (2,221) (4,339) (5,048)
--------- --------- --------- ---------
Income Before Income Taxes and Cumulative Effect of a Change in
Accounting Principle........................................ 175,273 149,600 346,474 295,434
Income Taxes................................................... (6,316) (5,083) (10,504) (9,484)
---------- ---------- ---------- ----------
Income Before Cumulative Effect of a Change in Accounting 168,957 144,517 335,970 285,950
Principle.......................................................
Cumulative effect adjustment from change in accounting for asset
retirement obligations...................................... - - 3,465 -
--------- --------- --------- ---------
Net Income..................................................... $ 168,957 $ 144,517 $ 339,435 $ 285,950
========= ========= ========= =========
Calculation of Limited Partners' interest in Net Income:
Income Before Cumulative Effect of a Change in Accounting $ 168,957 $ 144,517 $ 335,970 $ 285,950
Principle.......................................................
Less: General Partner's interest............................... (80,530) (65,234) (156,955) (127,028)
---------- ---------- ---------- ----------
Limited Partners' interest..................................... 88,427 79,283 179,015 158,922
Add: Limited Partners' interest in Change in Accounting Principle - - 3,430 -
--------- --------- --------- ---------
Limited Partners' interest in Net Income....................... $ 88,427 $ 79,283 $ 182,445 $ 158,922
========= ========= ========= =========
Basic Limited Partners' Net Income per Unit:
Income Before Cumulative Effect of a Change in Accounting $ 0.48 $ 0.48 $ 0.98 $ 0.96
Principle.......................................................
Cumulative effect adjustment from change in accounting for asset
retirement obligations...................................... - - 0.02 -
--------- --------- --------- ---------
Net Income..................................................... $ 0.48 $ 0.48 $ 1.00 $ 0.96
========= ========= ========= =========
Diluted Limited Partners' Net Income per Unit:
Income Before Cumulative Effect of a Change in Accounting $ 0.48 $ 0.48 $ 0.98 $ 0.95
Principle.......................................................
Cumulative effect adjustment from change in accounting for asset
retirement obligations...................................... - - 0.02 -
--------- --------- --------- ---------
Net Income..................................................... $ 0.48 $ 0.48 $ 1.00 $ 0.95
========= ========= ========= =========
Weighted average number of units used in computation of
Limited Partners' Net Income per unit:
Basic.......................................................... 183,595 166,589 182,492 166,320
========= ========= ========= =========
Diluted........................................................ 183,706 166,761 182,614 166,505
========= ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements.
3
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
June 30, December 31,
2003 2002
---------- ----------
ASSETS
Current Assets
Cash and cash equivalents............................. $ 44,915 $ 41,088
Accounts and notes receivable
Trade............................................... 603,153 457,583
Related parties..................................... 19,988 17,907
Inventories
Products............................................ 3,740 4,722
Materials and supplies.............................. 9,935 7,094
Gas imbalances........................................ 67,943 25,488
Gas in underground storage............................ 39,697 11,029
Other current assets.................................. 67,011 104,479
---------- ----------
856,382 669,390
Property, Plant and Equipment, net....................... 6,540,310 6,244,242
Investments.............................................. 256,637 311,044
Notes receivable......................................... 2,673 3,823
Goodwill................................................. 869,840 856,940
Other intangibles, net................................... 17,305 17,324
Deferred charges and other assets........................ 316,032 250,813
---------- ----------
TOTAL ASSETS............................................. $8,859,179 $8,353,576
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Trade............................................... $ 513,557 $ 373,368
Related parties..................................... 287 43,742
Accrued interest...................................... 49,928 52,500
Deferred revenues..................................... 5,701 4,914
Gas imbalances........................................ 71,215 40,092
Accrued other current liabilities..................... 293,510 298,711
---------- ----------
934,198 813,327
Long-Term Liabilities and Deferred Credits
Long-term debt, outstanding........................... 3,787,428 3,659,533
Market value of interest rate swaps................... 238,671 166,956
---------- ----------
4,026,099 3,826,489
Deferred revenues..................................... 22,324 25,740
Deferred income taxes................................. 31,025 30,262
Other long-term liabilities and deferred credits...... 215,977 199,796
---------- ----------
4,295,425 4,082,287
Commitments and Contingencies (Note 3)
Minority Interest........................................ 43,165 42,033
---------- ----------
Partners' Capital
Common Units.......................................... 1,985,196 1,844,553
Class B Units......................................... 122,226 123,635
i-Units............................................... 1,467,392 1,420,898
General Partner....................................... 78,760 72,100
Accumulated other comprehensive loss.................. (67,183) (45,257)
----------- -----------
3,586,391 3,415,929
TOTAL LIABILITIES AND PARTNERS' CAPITAL.................. $8,859,179 $8,353,576
========== ==========
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
(In Thousands)
(Unaudited)
Six Months Ended June 30,
2003 2002
----------- ---------
Cash Flows From Operating Activities
Net income............................................... $ 339,435 $ 285,950
Adjustments to reconcile net income to net cash provided
by operating activities:
Cumulative effect adjustment from change in accounting
for asset retirement obligations................... (3,465) --
Depreciation and amortization........................ 103,563 83,949
Amortization of excess cost of equity investments.... 2,788 2,788
Earnings from equity investments..................... (46,923) (47,568)
Distributions from equity investments................ 43,696 37,259
Changes in components of working capital............. (55,600) (16,302)
FERC rate reparations and refunds.................... (44,464) --
Other, net........................................... (2,932) (22,441)
----------- ---------
Net Cash Provided by Operating Activities................ 336,098 323,635
----------- ---------
Cash Flows From Investing Activities
Acquisitions of assets............................... (33,739) (816,220)
Additions to property, plant and equipment for expansion
and maintenance projects.......................... (273,402) (187,290)
Sale of investments, property, plant and equipment, net of
removal costs..................................... 1,258 402
Contributions to equity investments.................. (11,199) (6,643)
Other................................................ 7,088 1,152
----------- ---------
Net Cash Used in Investing Activities.................... (309,994) (1,008,599)
----------- ---------
Cash Flows From Financing Activities
Issuance of debt..................................... 2,064,865 2,123,324
Payment of debt...................................... (1,937,412) (1,195,306)
Debt issue costs..................................... (1,059) (159)
Proceeds from issuance of common units............... 174,958 1,228
Contributions from General Partner................... 1,533 -
Distributions to partners:
Common units..................................... (164,454) (148,070)
Class B units.................................... (6,721) (6,057)
General Partner.................................. (150,329) (117,284)
Minority interest................................ (4,747) (4,959)
Other, net........................................... 1,089 1,486
----------- ---------
Net Cash (Used in)/Provided by Financing Activities...... (22,277) 654,203
------------ ---------
Increase/(Decrease) in Cash and Cash Equivalents......... 3,827 (30,761)
Cash and Cash Equivalents, beginning of period........... 41,088 62,802
----------- ---------
Cash and Cash Equivalents, end of period................. $ 44,915 $ 32,041
=========== =========
Noncash Investing and Financing Activities:
Assets acquired by the assumption of liabilities $ 1,905 $ 153,170
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. 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 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, 2002.
KINDER MORGAN, INC. AND KINDER MORGAN MANAGEMENT, LLC
Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of Kinder
Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware corporation,
is the sole stockholder of our general partner, Kinder Morgan G.P., Inc. Kinder
Morgan, Inc. is referred to as "KMI" in this report.
Kinder Morgan Management, LLC, a Delaware limited liability company, was
formed on February 14, 2001. Our general partner owns all of Kinder Morgan
Management, LLC's voting securities and, pursuant to a delegation of control
agreement, our general partner delegated to Kinder Morgan Management, LLC, to
the fullest extent permitted under Delaware law and our partnership agreement,
all of its power and authority to manage and control the business and affairs of
us, our operating limited partnerships and their subsidiaries. Kinder Morgan
Management, LLC cannot take certain specified actions without the approval of
our general partner and its activities are limited to being a limited partner
in, and managing and controlling the business and affairs of, us, our operating
limited partnerships and their subsidiaries. Kinder Morgan Management, LLC is
referred to as "KMR" in this report.
BASIS OF PRESENTATION
Our consolidated financial statements include our accounts and those of our
majority-owned and controlled subsidiaries and our operating partnerships. All
significant intercompany items have been eliminated in consolidation. Certain
amounts from prior periods have been reclassified to conform to the current
presentation.
NET INCOME PER UNIT
We compute Basic Limited Partners' Net Income per Unit by dividing our limited
partners' interest in net income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the potential dilution, by application of the treasury stock method,
that could occur if options to issue units were exercised, which would result in
the issuance of additional units that would then share in our net income.
ASSET RETIREMENT OBLIGATIONS
As of January 1, 2003, we account for asset retirement obligations pursuant to
Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations." For more information on our asset retirement
obligations, see Note 4.
6
2. ACQUISITIONS AND JOINT VENTURES
During the first six months of 2003, we completed or made adjustments for the
following significant acquisitions. Each of the acquisitions was accounted for
under the purchase method and the assets acquired and liabilities assumed were
recorded at their estimated fair market values as of the acquisition date. The
preliminary allocation of assets and liabilities may be adjusted if the
evaluation of the acquisition has not been completed during a short period of
time following the acquisition. The results of operations from these
acquisitions are included in our consolidated financial statements from the
acquisition date.
BULK TERMINALS FROM M.J. RUDOLPH
Effective January 1, 2003, we acquired long-term lease contracts from New
York-based M.J. Rudolph Corporation to operate four bulk facilities at major
ports along the East Coast and in the southeastern United States. The
acquisition also includes the purchase of certain assets that provide
stevedoring services at these locations. The aggregate cost of the acquisition
was approximately $31.3 million. On December 31, 2002, we paid $29.9 million for
the Rudolph acquisition and this amount was included with "Other current assets"
on our accompanying consolidated balance sheet. In the first quarter of 2003, we
paid the remaining $1.4 million and we allocated our aggregate purchase price to
the appropriate asset and liability accounts. The acquired operations serve
various terminals located at the ports of New York and Baltimore, along the
Delaware River in Camden, New Jersey, and in Tampa Bay, Florida. Combined, these
facilities transload nearly four million tons annually of products such as
fertilizer, iron ore and salt. The acquisition expanded our growing Terminals
business segment and complements certain of our existing terminal facilities. In
our final analysis, it was considered reasonable to allocate a portion of our
purchase price to goodwill given the substance of this transaction, in
particular the synergies, and we will include the acquisition in our Terminals
business segment.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs.............. $ 31,337
Liabilities assumed................................. 6
---------
Total purchase price................................ $ 31,343
=========
Allocation of purchase price:
Current assets...................................... $ 84
Property, plant and equipment....................... 18,250
Intangibles-agreements ............................. 100
Deferred charges and other assets .................. 9
Goodwill ........................................... 12,900
---------
$ 31,343
=========
MKM PARTNERS, L.P.
On June 20, 2003, we signed an agreement with subsidiaries of Marathon Oil
Corporation to dissolve MKM Partners, L.P., a joint venture we formed on January
1, 2001 with subsidiaries of Marathon Oil Company. The joint venture assets
consisted of a 12.75% interest in the SACROC oil field unit and a 49.9% interest
in the Yates Field unit, both of which are in the Permian Basin of West Texas.
The MKM joint venture was owned 85% by subsidiaries of Marathon Oil Company and
15% by Kinder Morgan CO2 Company, L.P. It was dissolved effective June 30, 2003,
and the net assets were distributed to creditors and partners in accordance with
its partnership agreement.
Effective June 1, 2003, we acquired the MKM joint venture's 12.75% ownership
interest in the SACROC unit for $23.3 million and the assumption of $1.9 million
of liabilities. The SACROC unit is one of the largest and oldest oil fields in
the United States using carbon dioxide flooding technology. This transaction
increased our ownership interest in SACROC to approximately 97%.
7
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs.......... $ 23,302
Liabilities assumed............................. 1,905
---------
Total purchase price............................ $ 25,207
=========
Allocation of purchase price:
Property, plant and equipment................... $ 25,207
---------
$ 25,207
=========
Additionally, on June 20, 2003, the MKM joint venture, Marathon and we also
signed the following agreements related to other assets in the Permian Basin of
West Texas:
- an agreement for us to purchase the Marathon Carbon Dioxide Transportation
Company, which owns 65% of the Pecos Carbon Dioxide Pipeline Company, the
owner of a 25-mile carbon dioxide pipeline. This small transaction will
increase our stake in Pecos to nearly 70% and is expected to close in the
fourth quarter of 2003; and
- an agreement under which Marathon may consider the sale of Marathon's
approximate 43% interest in the Yates Field unit to us. We currently own a
7.5% ownership interest in the Yates Field unit.
PRO FORMA INFORMATION
The following summarized unaudited Pro Forma Consolidated Income Statement
information for the six months ended June 30, 2003 and 2002, assumes all of the
acquisitions we have made since January 1, 2002, including the ones listed
above, had occurred as of January 1, 2002. 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 as of January 1, 2002 or the results that
will be attained in the future. Amounts presented below are in thousands, except
for the per unit amounts:
Pro Forma
Six Months Ended
June 30,
--------------------------
2003 2002
---- ----
(Unaudited)
Revenues................................................................... $ 3,462,019 $ 2,157,653
=========== ===========
Operating Income........................................................... $ 398,069 $ 351,306
=========== ===========
Income Before Cumulative Effect of a Change in Accounting Principle........ $ 339,164 $ 300,715
=========== ===========
Net Income................................................................. $ 342,629 $ 300,715
=========== ===========
Basic and diluted Limited Partners' Net Income per unit:
Income Before Cumulative Effect of a Change in Accounting Principle..... $ 1.00 $ 0.92
Net Income.............................................................. $ 1.02 $ 0.92
3. LITIGATION AND OTHER CONTINGENCIES
FEDERAL ENERGY REGULATORY COMMISSION PROCEEDINGS
SFPP, L.P.
SFPP, L.P., referred to herein as SFPP, is the subsidiary limited partnership
that owns our Pacific operations, excluding CALNEV Pipe Line LLC and related
terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to
certain proceedings at the FERC involving shippers' complaints regarding the
interstate rates, as well as practices and the jurisdictional nature of certain
facilities and services, on our Pacific operations' pipeline systems. Generally,
the interstate rates on our Pacific operations' pipeline systems are
"grandfathered" under the Energy Policy Act of 1992 unless "substantially
changed circumstances" are found to exist. To the extent "substantially changed
circumstances" are found to exist, our Pacific operations may be subject to
substantial exposure under these FERC complaints.
8
The complainants in the proceedings before the FERC have alleged a variety of
grounds for finding "substantially changed circumstances." Applicable rules and
regulations in this field are vague, relevant factual issues are complex, and
there is little precedent available regarding the factors to be considered or
the method of analysis to be employed in making a determination of
"substantially changed circumstances." If "substantially changed circumstances"
are found, SFPP rates previously "grandfathered" under the Energy Policy Act
will lose their "grandfathered" status. If these rates are found to be unjust
and unreasonable, shippers may be entitled to prospective rate reductions and
complainants may be entitled to reparations for periods from the date of their
respective complaint to the date of the implementation of the new rates.
On June 24, 2003, a non-binding, phase one initial decision was issued by an
administrative law judge hearing a FERC case on the rates charged by SFPP on the
interstate portion of its pipelines. In his phase one initial decision, the
administrative law judge recommended that the FERC "ungrandfather" SFPP's
interstate rates and found most of SFPP's rates at issue to be unjust and
unreasonable. The administrative law judge has indicated that a phase two
initial decision will address prospective rates and whether reparations are
necessary.
Initial decisions have no force or effect and must be reviewed by the FERC.
The FERC is not obliged to follow any of the administrative law judge's findings
and can accept or reject this initial decision in whole or in part. In addition,
as stated above, the facts are complex, the rules and regulations in this area
are vague and little precedent exists. If the FERC ultimately finds that these
rates should be "ungrandfathered" and are unjust and unreasonable, they could be
lowered prospectively and complaining shippers could be entitled to reparations
for prior periods. Resolution of this matter by the FERC is not expected before
late 2004.
We currently believe that these FERC complaints seek approximately $154
million in tariff reparations and prospective annual tariff reductions, the
aggregate average annual impact of which would be approximately $45 million. As
the length of time from the filing of the complaints increases, the amounts
sought by complainants in tariff reparations will likewise increase until a
determination of reparations owed is made by the FERC. 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
administrative law judge's initial decision does not change our estimate of what
the complainants seek. Furthermore, even if "substantially changed
circumstances" are found to exist, we believe that the resolution of these FERC
complaints will be for amounts substantially less than the amounts sought and
that the resolution of such matters will not have a material adverse effect on
our business, financial position, results of operations or cash flows.
OR92-8, et al. proceedings. In September 1992, El Paso Refinery, L.P. filed
a protest/complaint with the FERC:
- challenging SFPP's East Line rates from El Paso, Texas to Tucson and
Phoenix, Arizona;
- challenging SFPP's proration policy; and
- seeking to block the reversal of the direction of flow of SFPP's six-inch
pipeline between Phoenix and Tucson.
At various subsequent dates, the following other shippers on SFPP's South
System filed separate complaints, and/or motions to intervene in the FERC
proceeding, challenging SFPP's rates on its East and/or West Lines:
- Chevron U.S.A. Products Company;
- Navajo Refining Company;
- ARCO Products Company;
- Texaco Refining and Marketing Inc.;
- Refinery Holding Company, L.P. (a partnership formed by El Paso Refinery's
long-term secured creditors that purchased its refinery in May 1993);
9
- Mobil Oil Corporation; and
- Tosco Corporation.
Certain of these parties also claimed that a gathering enhancement fee at
SFPP's Watson Station in Carson, California was charged in violation of the
Interstate Commerce Act.
The FERC consolidated these challenges in Docket Nos. OR92-8-000, et al., and
ruled that they are complaint proceedings, with the burden of proof on the
complaining parties. These parties must show that SFPP's rates and practices at
issue violate the requirements of the Interstate Commerce Act.
A FERC administrative law judge held hearings in 1996, and issued an initial
decision on September 25, 1997. The initial decision agreed with SFPP's position
that "changed circumstances" had not been shown to exist on the West Line, and
therefore held that all West Line rates that were "grandfathered" under the
Energy Policy Act of 1992 were deemed to be just and reasonable and were not
subject to challenge, either for the past or prospectively, in the Docket No.
OR92-8 et al. proceedings. SFPP's Tariff No. 18 for movement of jet fuel from
Los Angeles to Tucson, which was initiated subsequent to the enactment of the
Energy Policy Act, was specifically excepted from that ruling.
The initial decision also included rulings generally adverse to SFPP on such
cost of service issues as:
- the capital structure to be used in computing SFPP's 1985 starting rate
base;
- the level of income tax allowance; and
- the recovery of civil and regulatory litigation expenses and certain
pipeline reconditioning costs.
The administrative law judge also ruled that SFPP's gathering enhancement
service at Watson Station was subject to FERC jurisdiction and ordered SFPP to
file a tariff for that service, with supporting cost of service documentation.
SFPP and other parties asked the FERC to modify various rulings made in the
initial decision. On January 13, 1999, the FERC issued its Opinion No. 435,
which affirmed certain of those rulings and reversed or modified others.
With respect to SFPP's West Line, the FERC affirmed that all but one of the
West Line rates are "grandfathered" as just and reasonable and that "changed
circumstances" had not been shown to satisfy the complainants' threshold burden
necessary to challenge those rates. The FERC further held that the rate stated
in Tariff No. 18 did not require rate reduction. Accordingly, the FERC dismissed
all complaints against the West Line rates without any requirement that SFPP
reduce, or pay any reparations for, any West Line rate.
With respect to the East Line rates, Opinion No. 435 made several changes in
the initial decision's methodology for calculating the rate base. It held that
the June 1985 capital structure of SFPP's parent company at that time, rather
than SFPP's 1988 partnership capital structure, should be used to calculate the
starting rate base and modified the accumulated deferred income tax and
allowable cost of equity used to calculate the rate base. It also ruled that
SFPP would not owe reparations to any complainant for any period prior to the
date on which that complainant's complaint was filed, thus reducing by two years
the potential reparations period claimed by most complainants.
SFPP and certain complainants sought rehearing of Opinion No. 435 by the FERC.
In addition, ARCO, RHC (which subsequently changed its name to Western Refining
Company, L.P.), Navajo, Chevron and SFPP filed petitions for review of Opinion
No. 435 with the U.S. Court of Appeals for the District of Columbia Circuit, all
of which were either dismissed as premature or held in abeyance pending FERC
action on the rehearing requests.
On March 15, 1999, as required by the FERC's order, SFPP submitted a
compliance filing implementing the rulings made in Opinion No. 435, establishing
the level of rates to be charged by SFPP in the future, and setting forth the
amount of reparations that would be owed by SFPP to the complainants under the
order. The complainants contested SFPP's compliance filing.
10
On May 17, 2000, the FERC issued its Opinion No. 435-A, which modified Opinion
No. 435 in certain respects. It denied requests to reverse its rulings that
SFPP's West Line rates and Watson Station gathering enhancement facilities fee
are entitled to be treated as "grandfathered" rates under the Energy Policy Act.
It suggested, however, that if SFPP had fully recovered the capital costs of the
gathering enhancement facilities, that might form the basis of an amended
"changed circumstances" complaint.
Opinion No. 435-A granted a request by Chevron and Navajo to require that
SFPP's December 1988 partnership capital structure be used to compute the
starting rate base from December 1983 forward, as well as a request by SFPP to
vacate a ruling that would have required the elimination of approximately $125
million from the rate base used to determine capital structure. It also granted
two clarifications sought by Navajo, to the effect that SFPP's return on its
starting rate base should be based on SFPP's capital structure in each given
year (rather than a single capital structure from the outset) and that the
return on deferred equity should also vary with the capital structure for each
year. Opinion No. 435-A denied the request of Chevron and Navajo that no income
tax allowance be recognized for the limited partnership interests held by SFPP's
corporate parent, as well as SFPP's request that the tax allowance should
include interests owned by certain non-corporate entities. However, it granted
Navajo's request to make the computation of interest expense for tax allowance
purposes the same as for debt return.
Opinion No. 435-A reaffirmed that SFPP may recover certain litigation costs
incurred in defense of its rates (amortized over five years), but reversed a
ruling that those expenses may include the costs of certain civil litigation
with Navajo and El Paso. It also reversed a prior decision that litigation costs
should be allocated between the East and West Lines based on throughput, and
instead adopted SFPP's position that such expenses should be split equally
between the two systems.
As to reparations, Opinion No. 435-A held that no reparations would be awarded
to West Line shippers and that only Navajo was eligible to recover reparations
on the East Line. It reaffirmed that a 1989 settlement with SFPP barred Navajo
from obtaining reparations prior to November 23, 1993, but allowed Navajo
reparations for a one-month period prior to the filing of its December 23, 1993
complaint. Opinion No. 435-A also confirmed that FERC's indexing methodology
should be used in determining rates for reparations purposes and made certain
clarifications sought by Navajo.
Opinion No. 435-A denied Chevron's request for modification of SFPP's
prorationing policy. That policy required customers to demonstrate a need for
additional capacity if a shortage of available pipeline space existed. SFPP's
prorationing policy has since been changed to eliminate the "demonstrated need"
test.
Finally, Opinion No. 435-A directed SFPP to revise its initial compliance
filings to reflect the modified rulings. It eliminated the refund obligation for
the compliance tariff containing the Watson Station gathering enhancement fee,
but required SFPP to pay refunds to the extent that the initial compliance
tariff East Line rates exceeded the rates produced under Opinion No. 435-A.
In June 2000, several parties filed requests for rehearing of rulings made in
Opinion No. 435-A. Chevron and RHC both sought reconsideration of the FERC's
ruling that only Navajo is entitled to reparations for East Line shipments. SFPP
sought rehearing of the FERC's:
- decision to require use of the December 1988 partnership capital structure
for the period 1984-88 in computing the starting rate base;
- elimination of civil litigation costs;
- refusal to allow any recovery of civil litigation settlement payments; and
- failure to provide any allowance for regulatory expenses in prospective
rates.
On July 17, 2000, SFPP submitted a compliance filing implementing the rulings
made in Opinion No. 435-A, together with a calculation of reparations due to
Navajo and refunds due to other East Line shippers. SFPP also filed a tariff
stating revised East Line rates based on those rulings.
11
ARCO, Chevron, Navajo, RHC, Texaco and SFPP sought judicial review of Opinion
No. 435-A in the U.S. Court of Appeals for the District of Columbia Circuit. All
of those petitions except Chevron's were either dismissed as premature or held
in abeyance pending action on the rehearing requests. On September 19, 2000, the
court dismissed Chevron's petition for lack of prosecution, and subsequently
denied a motion by Chevron for reconsideration of that dismissal.
On September 13, 2001, the FERC issued Opinion No. 435-B, which ruled on
requests for rehearing and comments on SFPP's compliance filing. Based on those
rulings, the FERC directed SFPP to submit a further revised compliance filing,
including revised tariffs and revised estimates of reparations and refunds.
Opinion No. 435-B denied SFPP's requests for rehearing, which involved the
capital structure to be used in computing starting rate base, SFPP's ability to
recover litigation and settlement costs incurred in connection with the Navajo
and El Paso civil litigation, and the provision for regulatory costs in
prospective rates. However, it modified the FERC's prior rulings on several
other issues. It reversed the ruling that only Navajo is eligible to seek
reparations, holding that Chevron, RHC, Tosco and Mobil are also eligible to
recover reparations for East Line shipments. It ruled, however, that Ultramar
Diamond Shamrock ("UDS") is not eligible for reparations in the Docket No.
OR92-8 et al. proceedings.
The FERC also changed prior rulings that had permitted SFPP to use certain
litigation, environmental and pipeline rehabilitation costs that were not
recovered through the prescribed rates to offset overearnings (and potential
reparations) and to recover any such costs that remained by means of a surcharge
to shippers. Opinion No. 435-B required SFPP to pay reparations to each
complainant without any offset for unrecovered costs. It required SFPP to
subtract from the total 1995-1998 supplemental costs allowed under Opinion No.
435-A any overearnings not paid out as reparations, and allowed SFPP to recover
any remaining costs from shippers by means of a five-year surcharge beginning
August 1, 2000. Opinion No. 435-B also ruled that SFPP would only be permitted
to recover certain regulatory litigation costs through the surcharge, and that
the surcharge could not include environmental or pipeline rehabilitation costs.
Opinion No. 435-B directed SFPP to make additional changes in its revised
compliance filing, including:
- using a remaining useful life of 16.8 years in amortizing its starting rate
base, instead of 20.6 years;
- removing the starting rate base component from base rates as of August 1,
2001;
- amortizing the accumulated deferred income tax balance beginning in 1992,
rather than 1988;
- listing the corporate unitholders that were the basis for the income tax
allowance in its compliance filing and certifying that those companies are
not Subchapter S corporations; and
- "clearly" excluding civil litigation costs and explaining how it limited
litigation costs to FERC-related expenses and assigned them to appropriate
periods in making reparations calculations.
On October 15, 2001, Chevron and RHC filed petitions for rehearing of Opinion
No. 435-B. Chevron asked the FERC to clarify:
- the period for which Chevron is entitled to reparations; and
- whether East Line shippers that have received the benefit of FERC-prescribed
rates for 1994 and subsequent years must show that there has been a
substantial divergence between the cost of service and the change in the
FERC's rate index in order to have standing to challenge SFPP rates for
those years in pending or subsequent proceedings.
12
RHC's petition contended that Opinion No. 435-B should be modified on
rehearing, to the extent it:
- suggested that a "substantial divergence" standard applies to complaint
proceedings challenging the total level of SFPP's East Line rates subsequent
to the Docket No. OR92-8 et al. proceedings;
- required a substantial divergence to be shown between SFPP's cost of service
and the change in the FERC oil pipeline index in such subsequent complaint
proceedings, rather than a substantial divergence between the cost of
service and SFPP's revenues; and
- permitted SFPP to recover 1993 rate case litigation expenses through a
surcharge mechanism.
ARCO, UDS and SFPP filed petitions for review of Opinion No. 435-B (and in
SFPP's case, Opinion Nos. 435 and 435-A) in the U.S. Court of Appeals for the
District of Columbia Circuit. The court consolidated the UDS and SFPP petitions
with the consolidated cases held in abeyance and ordered that the consolidated
cases be returned to its active docket.
On November 7, 2001, the FERC issued an order ruling on the petitions for
rehearing of Opinion No. 435-B. The FERC held that Chevron's eligibility for
reparations should be measured from August 3, 1993, rather than the September
23, 1992 date sought by Chevron. The FERC also clarified its prior ruling with
respect to the "substantial divergence" test, holding that in order to be
considered on the merits, complaints challenging the SFPP rates set by applying
the FERC's indexing regulations to the 1994 cost of service derived under the
Opinion No. 435 orders must demonstrate a substantial divergence between the
indexed rates and the pipeline's actual cost of service. Finally, the FERC held
that SFPP's 1993 regulatory costs should not be included in the surcharge for
the recovery of supplemental costs.
On November 20, 2001, SFPP submitted its compliance filing and tariffs
implementing Opinion No. 435-B and the FERC's November 7, 2001 Order. Motions to
intervene and protest were subsequently filed by ARCO, Mobil (which now submits
filings under the name ExxonMobil), RHC, Navajo (now Navajo Refining Company,
L.P.) and Chevron, alleging that SFPP:
- should have calculated the supplemental cost surcharge differently;
- did not provide adequate information on the taxpaying status of its
unitholders; and
- failed to estimate potential reparations for ARCO.
On December 7, 2001, Chevron filed a petition for rehearing of the FERC's
November 7, 2001 Order. The petition requested the FERC to specify whether
Chevron would be entitled to reparations for the two year period prior to the
August 3, 1993 filing of its complaint.
On December 10, 2001, SFPP filed a response to those claims. On December 14,
2001, SFPP filed a revised compliance filing and new tariff correcting an error
that had resulted in understating the proper surcharge and tariff rates.
On December 20, 2001, the FERC's Director of the Division of Tariffs and Rates
Central issued two letter orders rejecting SFPP's November 20, 2001 and December
14, 2001 tariff filings because they were not made effective retroactive to
August 1, 2000. On January 11, 2002, SFPP filed a request for rehearing of those
orders by the FERC, on the ground that the FERC has no authority to require
retroactive reductions of rates filed pursuant to its orders in complaint
proceedings.
On January 7, 2002, SFPP and RHC filed petitions for review of the FERC's
November 7, 2001 Order in the U.S. Court of Appeals for the District of Columbia
Circuit. On January 8, 2002, the court consolidated those petitions with the
petitions for review of Opinion Nos. 435, 435-A and 435-B. On January 24, 2002,
the court ordered the consolidated proceedings to be held in abeyance until FERC
action on Chevron's request for rehearing of the November 7, 2001 Order.
13
Motions to intervene and protest the December 14, 2001 corrected submissions
were filed by Navajo, ARCO and ExxonMobil. UDS requested leave to file an
out-of-time intervention and protest of both the November 20, 2001 and December
14, 2001 submissions. On January 14, 2002, SFPP responded to those filings to
the extent they were not mooted by the orders rejecting the tariffs in question.
On February 15, 2002, the FERC denied rehearing of the Director of the
Division of Tariffs and Rates Central's letter orders. On February 21, 2002,
SFPP filed a motion requesting that the FERC clarify whether it intended SFPP to
file a retroactive tariff or simply make a compliance filing calculating the
effects of Opinion No. 435-B back to August 1, 2000; in the event the order was
clarified to require a retroactive tariff filing, SFPP asked the FERC to stay
that requirement pending judicial review.
On April 8, 2002, SFPP filed a petition for review of the FERC's February 15,
2002 Order in the U.S. Court of Appeals for the District of Columbia Circuit. BP
West Coast Products, LLC (formerly ARCO), ExxonMobil, and Tosco filed motions to
intervene in that proceeding. A motion to intervene was also filed by Valero
Energy Corporation ("Valero Energy") (which had merged with UDS on December 31,
2001) and Valero Energy's newly acquired shipper subsidiary Ultramar Inc. On
April 9, 2002, the Court of Appeals consolidated SFPP's petition with the
petitions for review of the FERC's prior orders and directed the parties "to
file motions to govern future proceedings" by May 9, 2002. Motions were filed by
SFPP, RHC, Navajo, Chevron and the "Indicated Parties" (BP West Coast Products,
ExxonMobil, Ultramar Inc., UDS and Tosco). The FERC requested that the Court of
Appeals continue to hold the consolidated cases in abeyance pending the
completion of proceedings before the agency on rehearing.
On June 25, 2002, the Court of Appeals granted the ExxonMobil and Valero
Energy motions to intervene, and directed intervenors on the side of petitioners
to notify the court of that status and provide a statement of issues to be
raised. ExxonMobil filed a notice on July 2, 2002; Ultramar Inc. and Valero
Energy on July 10, 2002. On July 12, 2002, SFPP responded to the ExxonMobil
notice in order to urge the Court of Appeals not to rely on ExxonMobil's
categorization of the issues and party alignments in allocating briefing.
On May 31, 2002, SFPP filed FERC Tariff No. 70, which implemented the FERC's
annual indexing adjustment. Motions to intervene and protest were filed by
Navajo and Chevron, contesting any indexing adjustment to the litigation
surcharge permitted by Opinion No. 435-B. On June 28, 2002, the FERC's Director
of the Division of Tariffs and Rates rejected Tariff No. 70 on the ground that
the surcharge should not be indexed. On July 2, 2002, SFPP filed FERC Tariff No.
73 to replace Tariff No. 70 in compliance with that decision, which resulted in
an average reduction from Tariff No. 70 of approximately $.0002 per barrel.
On September 26, 2002, the FERC issued an order ruling on the protests against
SFPP's November 20, 2001 and December 14, 2001 compliance filings implementing
Opinion No. 435-B and the November 7, 2001 Order. The FERC held that:
- SFPP must measure supplemental costs against the total amount of reparations
for the entire reparations period (as opposed to year-by-year);
- SFPP will not be permitted to include in its supplemental costs
(a) litigation expenses incurred during 1999 and 2000 or (b) payments made
to Navajo and RHC to settle certain FERC litigation;
- the tariff surcharge collected by SFPP for all shipments between August 1,
2000 and December 1, 2001 is subject to refund; and
- in calculating its tax allowance, SFPP must exclude the ownership interest
attributable to an entity that the FERC found to be a mutual fund.
The FERC rejected the requests by Navajo, BP West Coast Products and
ExxonMobil to extend the period for which they are entitled to reparations
beyond the periods specified in prior orders.
The September 26, 2002 Order also ruled on SFPP's request for clarification of
the February 15, 2002 Order as to whether it was required to make a retroactive
tariff filing or rather a compliance filing calculating the effects of
14
Opinion No. 435-B beginning August 1, 2000. The FERC held that SFPP was required
to file a tariff retroactive to August 1, 2000. The FERC did not rule on SFPP's
alternative request for a stay. The FERC also ruled on Chevron's request for
rehearing of the November 7, 2001 Order, clarifying that Chevron was eligible
for reparations for shipments on the East Line for the two years prior to the
filing of its complaint.
On October 22, 2002, ExxonMobil filed a Request for Clarification or, in the
Alternative, Rehearing of the September 26, 2002 Order. ExxonMobil requested
that the FERC clarify that ExxonMobil was eligible for reparations for East Line
rates.
Following the September 26, 2002 Order, several parties filed motions to
govern future proceedings with the U.S. Court of Appeals for the District of
Columbia Circuit. BP West Coast Products and ExxonMobil (the "Indicated
Parties") and Valero Energy, Ultramar Inc. and Tosco (the "Joint Parties")
requested that the court return the petitions for review to its active docket
but sever the docket involving compliance filing issues. The FERC filed a motion
that did not take a definitive position on whether the petitions for review
should continue to be held in abeyance, but noted that compliance filing issues
were still pending before the FERC. SFPP, Chevron, Navajo and RHC filed
responses to the motions to govern future proceedings. On December 6, 2002, the
Court of Appeals granted the motion of the "Indicated Parties" and "Joint
Parties" to return the petitions for review to the Court's active docket. The
Court also severed the docket relating to compliance filing issues and directed
the parties to submit a proposed briefing schedule and format. On January 6,
2003, SFPP and FERC filed a joint briefing proposal, and the shipper parties
jointly filed a separate briefing proposal.
On October 18, 2002, Chevron filed a petition for review of Opinion Nos. 435,
435-A and 435-B in the U.S. Court of Appeals for the District of Columbia
Circuit. The Court of Appeals consolidated that petition with the main docket on
November 20, 2002. Tosco and BP West Coast Products moved to intervene in that
docket, and those motions were granted on December 10, 2002.
Petitions for review of the September 26, 2002 Order were filed in the U.S.
Court of Appeals for the District of Columbia Circuit by Navajo, on October 24,
2002, and by SFPP, on November 8, 2002. The Court consolidated those petitions
with the main docket on November 5, 2002 and November 12, 2002, respectively.
Valero Marketing and Supply Company ("Valero Marketing and Supply") moved to
intervene in both dockets and Tosco moved to intervene in the docket for the
SFPP petition. On January 6, 2003, Valero Marketing and Supply filed a motion to
substitute itself for UDS in the UDS petition for review of Opinion No. 435-B.
On January 21, 2003, SFPP filed a response, stating that it did not object to
the proposed substitution provided Valero Marketing and Supply was not permitted
to create or enlarge any claim for damages. On January 24, 2003, ConocoPhillips
Company filed a motion to substitute itself for Tosco in the consolidated
dockets, and on January 27, 2003, filed a similar motion in the severed docket
relating to compliance filing issues. On February 4, 2003, the Court of Appeals
granted the ConocoPhillips motion for substitution.
On October 25, 2002, SFPP filed Tariff No. 75 implementing changes required by
the September 26, 2002 Order, and on October 28, 2002, SFPP submitted a
compliance filing pursuant to that order. Valero Marketing and Supply filed a
motion to intervene and protest regarding the compliance filing and tariff, and
Tosco protested the compliance filing. Navajo moved to intervene in proceedings
relating to the tariff, and Chevron and Equilon Enterprises LLC filed comments
and related pleadings challenging the compliance filing and seeking additional
relief.
On January 29, 2003, the FERC issued an order accepting the October 28,
2002 compliance filing subject to the condition that SFPP recalculate gross
reparations in determining its per barrel surcharge and submit a revised tariff
reflecting that change within fifteen days of the order. The FERC rejected all
other challenges to that compliance filing. On February 13, 2003, SFPP filed its
revised compliance filing along with Tariff No. 81, implementing the provisions
of the January 29, 2003 Order. No party protested that filing. Valero Marketing
and Supply moved to intervene in the sub-docket related to Tariff No. 81 and
Valero Marketing and Supply and Ultramar Inc. moved to intervene in the
sub-docket related to the compliance filing.
On February 24, 2003, the FERC modified the basis on which maximum
allowable oil pipeline rates are adjusted for inflation, from the producer price
index for finished goods minus one percent to the unadjusted producer price
15
index for finished goods. On February 25, 2003, SFPP filed Tariff No. 82, which
implemented that indexing change with respect to its prospective rates. Tariff
No. 82 was protested by BP West Coast Products, Chevron, ExxonMobil, Valero
Marketing and Supply, and ConocoPhillips, in Docket No. IS03-131. On March 28,
2003, the FERC denied the protests and accepted Tariff No. 82.
On March 7, 2003, SFPP filed a revised compliance filing in Docket No. OR92-8,
which adjusted the refund calculations in SFPP's October 28, 2002 compliance
filing to account for the change in the oil pipeline pricing index as of July 1,
2001. On March 24, 2003, BP West Coast Products protested this revised
compliance filing. On March 27, 2003, Navajo filed an answer to the BP West
Coast Products protest in which it also challenged the adjustment to the refund
calculation made in the revised compliance filing. On April 14, 2003, SFPP made
reparation payments of $42.7 million and refund payments of $1.7 million as
ordered by the FERC pursuant to SFPP's March 7, 2003 revised compliance filing.
Petitions for review of the January 29, 2003 Order were filed by
ConocoPhillips on February 6, 2003, SFPP on March 10, 2003 and Chevron on March
27, 2003. SFPP moved to intervene in the ConocoPhillips docket. ExxonMobil and
BP West Coast Products moved to intervene in the SFPP docket.
On June 5, 2003 the FERC issued a letter order accepting SFPP's February 13,
2003 compliance filing and rejecting its March 7, 2003 revised compliance
filing. The FERC required SFPP to pay, within 60 days of its order, the
difference between the reparations and refunds shown in SFPP's February, 2003
compliance filing and those in its March 2003 compliance filing. The FERC
accepted Tariff No. 81, effective as of February 13, 2003. SFPP filed a Petition
for Review of the June 5 letter order on July 16, 2003.
On March 7, 2003, the United States Court of Appeals for the District of
Columbia Circuit severed from the main docket all dockets relating to petitions
for review of the February 15, 2002, September 26, 2002, and January 29, 2003
Orders. The Court of Appeals ordered those dockets to be consolidated and held
in abeyance pending resolution of the main docket. The Court of Appeals also
issued a briefing schedule for the main docket, with opening briefs due May 9,
2003 and final briefs due September 17, 2003. The Court also granted the motion
of Valero Marketing and Supply to substitute itself for UDS. On May 9, 2003,
SFPP and the Shipper Petitioners and Intervenors filed their opening briefs. On
July 8, 2003, the FERC filed its brief as Respondent.
On July 22, 2003, the Court of Appeals issued an order designating the case as
"complex" under its case management plan and setting oral argument for November
12, 2003. On July 28, 2003, SFPP and the shipper parties filed briefs regarding
rulings in the FERC orders under review that have been challenged in Court of
Appeals but that SFPP or the shipper parties, respectively, support.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC
(Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines (Line
Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject
to FERC's jurisdiction under the Interstate Commerce Act, and, if so, claimed
that the rate for that service was unlawful. Texaco sought to have its claims
addressed in the OR92-8 proceeding discussed above. Several other West Line
shippers filed similar complaints and/or motions to intervene. The FERC
consolidated all of these filings into Docket No. OR96-2 and set the claims for
a separate hearing. A hearing before an administrative law judge was held in
December 1996.
In March 1997, the judge issued an initial decision holding that the movements
on the Sepulveda pipelines were not subject to FERC jurisdiction. On August 5,
1997, the FERC reversed that decision. On October 6, 1997, SFPP filed a tariff
establishing the initial interstate rate for movements on the Sepulveda
pipelines at the preexisting rate of five cents per barrel. Several shippers
protested that rate. In December 1997, SFPP filed an application for authority
to charge a market-based rate for the Sepulveda service, which application was
protested by several parties. On September 30, 1998, the FERC issued an order
finding that SFPP lacks market power in the Watson Station destination market
and that, while SFPP appeared to lack market power in the Sepulveda origin
market, a hearing was necessary to permit the protesting parties to substantiate
allegations that SFPP possesses market power in the origin market. A hearing
before a FERC administrative law judge on this limited issue was held in
February 2000.
16
On December 21, 2000, the FERC administrative law judge issued his initial
decision finding that SFPP possesses market power over the Sepulveda origin
market. On February 28, 2003, the FERC issued an order upholding that decision.
SFPP filed a request for rehearing of that order on March 31, 2003. The FERC
denied SFPP's request for rehearing on July 9, 2003.
As part of its February 28, 2003 order denying SFPP's application for
market-based ratemaking authority, the FERC remanded to the ongoing litigation
in Docket No. OR96-2, et al. the question of whether SFPP's current rate for
service on the Sepulveda line is just and reasonable. That issue is currently
pending before the administrative law judge in the Docket No. OR96-2, et al.
proceeding.
OR97-2; OR98-1; OR96-2.. et al. proceedings. In October 1996, Ultramar filed a
complaint at FERC (Docket No. OR97-2) challenging SFPP's West Line rates,
claiming they were unjust and unreasonable and no longer subject to
grandfathering. In October 1997, ARCO, Mobil and Texaco filed a complaint at the
FERC (Docket No. OR98-1) challenging the justness and reasonableness of all of
SFPP's interstate rates, raising claims against SFPP's East and West Line rates
similar to those that have been at issue in Docket Nos. OR92-8, et al. discussed
above, but expanding them to include challenges to SFPP's grandfathered
interstate rates from the San Francisco Bay area to Reno, Nevada and from
Portland to Eugene, Oregon - the North Line and Oregon Line. In November 1997,
Ultramar Diamond Shamrock Corporation 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 the lines. SFPP answered each of these complaints. FERC issued orders
accepting the complaints and consolidating them into one proceeding (Docket No.
OR96-2, et al.), but holding 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. On May 17, 2000, the FERC issued an order
finding that the various complaining parties had alleged sufficient grounds for
their complaints to go forward to a hearing to assess whether any of the
challenged rates that are grandfathered under the Energy Policy Act will
continue to have such status and, if the grandfathered status of any rate is not
upheld, whether the existing rate is just and reasonable.
In August 2000, Navajo and RHC 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. In September 2000, the FERC accepted these
new complaints and consolidated them with the ongoing proceeding in Docket No.
OR96-2, et al.
A hearing in this consolidated proceeding was held from October 2001 to March
2002. A FERC administrative law judge issued his initial decision on June 24,
2003. The initial decision found that, for the years at issue, the complainants
had shown substantially changed circumstances for rates on SFPP's West, North
and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson
Station and thus found that those rates should not be "grandfathered" under the
Energy Policy Act of 1992. The initial decision also found that most of SFPP's
rates at issue were unjust and unreasonable. The initial decision indicated that
a phase two initial decision will address prospective rates and whether
reparations are necessary. Issuance of the phase two initial decision is
expected sometime in the latter half of 2003.
SFPP has filed a brief on exceptions to the FERC that contests the findings in
the initial decision. SFPP's opponents will file briefs responding to SFPP's
brief in September of 2003. Resolution of this matter by the FERC is not
expected before late 2004.
OR02-4 proceedings. On February 11, 2002, Chevron, an intervenor in the
OR96-2 proceeding, filed a complaint against SFPP in Docket No. OR02-4 along
with a motion to consolidate the complaint with the OR96-2 proceeding. On May
21, 2002, the FERC dismissed Chevron's complaint and motion to consolidate.
Chevron filed a request for rehearing and on September 25, 2002, the FERC
dismissed Chevron's rehearing request. In October 2002, Chevron filed a request
for rehearing of the FERC's September 25, 2002 Order. On May 23, 2003, the FERC
denied Chevron's rehearing request and on July 1, 2003, Chevron filed an appeal
of this denial at the U.S. Court of Appeals for the District of Columbia
Circuit, which appeal is currently pending. Chevron continues to participate in
the OR96-2 proceeding as an intervenor.
17
OR03-5 proceedings. On June 30, 2003, Chevron filed another complaint against
SFPP and moved to consolidate the complaint with the OR96-2 proceeding. This
complaint was docketed as Docket No. OR03-5. Chevron's complaint claims
"substantially changed circumstances" with regard to the rates SFPP charges on
its West, North, and Oregon lines as well as the Watson Station gathering
enhancement facilities fee. Chevron also attacks the justness and reasonableness
of these rates and fees as well as of the East Line rates. SFPP answered
Chevron's complaint on July 22, 2003. The matter is currently pending before the
Commission.
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 a
decision addressing the submitted matters is expected within three to four
months.
The CPUC has recently 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 requires SFPP to submit cost data for
2001, 2002, and 2003 to assist the CPUC in determining whether SFPP's overall
rates for California intrastate transportation services are reasonable. The
resolution reserves the right to require refunds, from the date of issuance of
the resolution, to the extent the CPUC's analysis of cost data to be submitted
by SFPP demonstrates that SFPP's California jurisdictional rates are
unreasonable in any fashion. On February 21, 2003, SFPP submitted the cost data
required by the CPUC, which submittal was protested by Valero Marketing and
Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil
Corporation, and Chevron Products Company. Issues raised by the protest,
including the reasonableness of SFPP's existing intrastate transportation rates,
will be the subject of evidentiary hearings and are expected to be resolved by
the CPUC by the first quarter of 2004.
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 or estimate 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. SFPP believes that
submission of the required, representative cost data required by the CPUC will
indicate that SFPP's existing rates for California intrastate services remain
reasonable and that no refunds are justified.
18
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.
TRAILBLAZER PIPELINE COMPANY
As required by its last rate case settlement, Trailblazer Pipeline Company
made a general rate case filing at the FERC on November 29, 2002. The filing
provides for a small rate decrease and also includes a number of non-rate tariff
changes. By an order issued December 31, 2002, FERC effectively bifurcated the
proceeding. The rate change was accepted to be effective on January 1, 2003,
subject to refund and a hearing. Most of the non-rate tariff changes were
suspended until June 1, 2003, subject to refund and a technical conference
procedure.
Trailblazer sought rehearing of the FERC order with respect to the refund
condition on the rate decrease. On April 15, 2003, the FERC granted
Trailblazer's rehearing request to remove the refund condition that had been
imposed in the December 31, 2002 Order. Certain intervenors have sought
rehearing as to the FERC's acceptance of certain non-rate tariff provisions. A
prehearing conference on the rate issues was held on January 16, 2003. A
procedural schedule was established under which the hearing will commence on
October 8, 2003, if the case is not settled. Discovery has commenced as to rate
issues.
The technical conference on non-rate issues was held on February 6, 2003.
Those issues include:
- capacity award procedures;
- credit procedures;
- imbalance penalties; and
- the maximum length of bid terms considered for evaluation in the right of
first refusal process.
Comments on these issues as discussed at the technical conference were filed
by parties in March 2003. On May 23, 2003, FERC issued an order deciding
non-rate tariff issues and denying rehearing of its prior order. In the May 23,
2003 order, FERC:
- accepted Trailblazer's proposed capacity award procedures with very limited
changes;
- accepted Trailblazer's credit procedures subject to very extensive changes,
consistent with numerous recent orders involving other pipelines;
- accepted a compromise agreed to by Trailblazer and the active parties under
which existing shippers must match competing bids in the right of first
refusal process for up to 10 years (in lieu of the current 5 years); and
- accepted Trailblazer's withdrawal of daily imbalance charges.
The referenced order did the following:
- allowed shortened notice periods for suspension of service, but required at
least 30 days notice for service termination;
- limited prepayments and any other assurance of future performance, such as a
letter of credit, to three months of service charges except for new
facilities;
- required the pipeline to pay interest on prepayments or allow those funds to
go into an interest-bearing escrow account; and
- required much more specificity about credit criteria and procedures in
tariff provisions.
19
Certain shippers have sought rehearing of the May 23, 2003 order. Trailblazer
made its compliance filing on June 20, 2003. Under the May 23, 2003 order, these
tariff changes are effective as of May 23, 2003, except that Trailblazer has
filed to make the revised credit procedures effective August 15, 2003.
With respect to the on-going rate review phase of the case, direct testimony
was filed by FERC Staff and Indicated Shippers on May 22, 2003 and
cross-answering testimony was filed by Indicated Shippers on June 19, 2003.
Trailblazer's answering testimony was filed on July 29, 2003.
FERC ORDER 637
KINDER MORGAN INTERSTATE GAS TRANSMISSION LLC
On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its
filing to comply with FERC's Orders 637 and 637-A. That filing contained KMIGT's
compliance plan to implement the changes required by the FERC dealing with the
way business is conducted on interstate natural gas pipelines. All interstate
natural gas pipelines were required to make such compliance filings, according
to a schedule established by the FERC. From October 2000 through June 2001,
KMIGT held a series of technical and phone conferences to identify issues,
obtain input, and modify its Order 637 compliance plan, based on comments
received from FERC staff and other interested parties and shippers. On June 19,
2001, KMIGT received a letter from the FERC encouraging it to file revised
pro-forma tariff sheets, which reflected the latest discussions and input from
parties into its Order 637 compliance plan. KMIGT made such a revised Order 637
compliance filing on July 13, 2001. The July 13, 2001 filing contained little
substantive change from the original pro-forma tariff sheets that KMIGT
originally proposed on June 15, 2000. On October 19, 2001, KMIGT received an
order from the FERC, addressing its July 13, 2001 Order 637 compliance plan. In
the Order addressing the July 13, 2001 compliance plan, KMIGT's plan was
accepted, but KMIGT was directed to make several changes to its tariff, and in
doing so, was directed that it could not place the revised tariff into effect
until further order of the FERC. KMIGT filed its compliance filing with the
October 19, 2001 Order on November 19, 2001 and also filed a request for
rehearing/clarification of the FERC's October 19, 2001 Order on November 19,
2001. Several parties protested the November 19, 2001 compliance filing. KMIGT
filed responses to those protests on December 14, 2001.
On May 22, 2003, KMIGT received an Order on Rehearing and Compliance Filing
(May 2003 Order) from the FERC, addressing KMIGT's November 19, 2001 filed
request for rehearing and filing to comply with the directives of the October
19, 2001 Order. The May 2003 Order granted in part and denied in part KMIGT's
request for rehearing, and directed KMIGT to file certain revised tariff sheets
consistent with the May 2003 Order's directives. On June 20, 2003, KMIGT
submitted its compliance filing reflecting revised tariff sheets in accordance
with the FERC's directives. Consistent with the May 2003 Order, KMIGT's
compliance filing reflected tariff sheets with proposed effective dates of June
1, 2003 and December 1, 2003. Those sheets with a proposed effective date of
December 1, 2003 concern tariff provisions necessitating computer system
modifications. The June 20, 2003 compliance filing is pending FERC action. KMIGT
is preparing for full implementation of Order 637 on December 1, 2003. The
evaluation of the full impact of implementation of Order 637 on the KMIGT system
is ongoing. We believe that these matters will not have a material adverse
effect on our business, financial position, results of operations or cash flows.
Separately, numerous petitioners, including KMIGT, have filed appeals in
respect of Order 637 in the D.C. Circuit, potentially raising a wide array of
issues related to Order 637 compliance. Initial briefs were filed on April 6,
2001, addressing issues contested by industry participants. Oral arguments on
the appeals were held before the court in December 2001. On April 5, 2002, the
D.C. Circuit issued an order largely affirming Order Nos. 637, et seq. The D.C.
Circuit remanded the FERC's decision to impose a 5-year cap on bids that an
existing shipper would have to match in the right of first refusal process. The
D.C. Circuit also remanded the FERC's decision to allow forward-hauls and
backhauls to the same point. Finally, the D.C. Circuit held that several aspects
of the FERC's segmentation policy and its policy on discounting at alternate
points were not ripe for review. The FERC requested comments from the industry
with respect to the issues remanded by the D.C. Circuit. They were due July 30,
2002.
On October 31, 2002, the FERC issued an order in response to the D.C.
Circuit's remand of certain Order 637 issues. The order:
20
- eliminated the requirement of a 5-year cap on bid terms that an existing
shipper would have to match in the right of first refusal process, and found
that no term matching cap is necessary given existing regulatory controls;
- affirmed FERC's policy that a segmented transaction consisting of both a
forwardhaul up to contract demand and a backhaul up to contract demand to
the same point is permissible; and
- accordingly required, under Section 5 of the Natural Gas Act, pipelines that
the FERC had previously found must permit segmentation on their systems to
file tariff revisions within 30 days to permit such segmented forwardhaul
and backhaul transactions to the same point.
On December 23, 2002, KMIGT filed revised tariff provisions (in a separate
docket) in compliance with the October 31, 2002 Order concerning the elimination
of the right of first refusal five-year term matching cap. In an order issued
January 22, 2003, the FERC approved such revised tariff provisions to be
effective January 23, 2003.
TRAILBLAZER PIPELINE COMPANY
On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with
the FERC's Order Nos. 637 and 637-A. Trailblazer's compliance filing reflected
changes in:
- segmentation;
- scheduling for capacity release transactions;
- receipt and delivery point rights;
- treatment of system imbalances;
- operational flow orders;
- penalty revenue crediting; and
- right of first refusal language.
On October 15, 2001, the FERC issued its order on Trailblazer's Order No. 637
compliance filing. The FERC approved Trailblazer's proposed language regarding
operational flow orders and rights of first refusal, but required Trailblazer
to make changes to its tariff related to the other issues listed above.
On November 14, 2001, Trailblazer made its compliance filing pursuant to the
FERC order of October 15, 2001 and also filed for rehearing of the October 15,
2001 order. On April 16, 2003, the FERC issued its order on Trailblazer's
compliance filing and rehearing order. The FERC denied Trailblazer's requests
for rehearing and approved the compliance filing subject to modifications that
must be made within 30 days of the order.
Trailblazer made those modifications in a further compliance filing on May 16,
2003. Certain shippers have filed a limited protest regarding that compliance
filing. That filing is pending FERC action. Under the FERC orders, limited
aspects of Trailblazer's plan (revenue crediting) were effective as of May 1,
2003, and the entire plan is expected to be effective as of December 1, 2003.
Trailblazer anticipates no adverse impact on its business as a result of the
implementation of Order No. 637.
STANDARDS OF CONDUCT RULEMAKING
On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking in
Docket No. RM01-10 in which it proposed new rules governing the interaction
between an interstate natural gas pipeline and its affiliates. If adopted as
proposed, the Notice of Proposed Rulemaking could be read to limit
communications between KMIGT, Trailblazer and their respective affiliates. In
addition, the Notice could be read to require separate staffing of
21
KMIGT and its affiliates, and Trailblazer and its affiliates. Comments on the
Notice of Proposed Rulemaking were due December 20, 2001. Numerous parties,
including KMIGT, have filed comment on the Proposed Standards of Conduct
Rulemaking. On May 21, 2002, the FERC held a technical conference dealing with
the FERC's proposed changes in the Standard of Conduct Rulemaking. On June 28,
2002, KMIGT and numerous other parties filed additional written comments under a
procedure adopted at the technical conference. The Proposed Rulemaking is
awaiting further FERC action. We believe that these matters, as finally adopted,
will not have a material adverse effect on our business, financial position,
results of operations or cash flows.
The FERC also issued a Notice of Proposed Rulemaking in Docket No. RM02-14-000
in which it proposed new regulations for cash management practices, including
establishing limits on the amount of funds that can be swept from a regulated
subsidiary to a non-regulated parent company. Kinder Morgan Interstate Gas
Transmission LLC filed comments on August 28, 2002. On June 26, 2003, FERC
issued an interim rule to be effective August 7, 2003, under which regulated
companies are required to document cash management arrangements and
transactions. The interim rule does not include a proposed rule that would have
required regulated companies, as a prerequisite to participation in cash
management programs, to maintain a proprietary capital ratio of 30% and an
investment grade credit rating. FERC is seeking additional comment on whether it
should require the filing of cash management agreements and notification if a
regulated company's proprietary capital ratio falls below (or goes back above)
30%. We believe that these matters, as finally adopted, will not have a material
adverse effect on our business, financial position, results of operations or
cash flows.
OTHER FERC ORDERS
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. Price indexed contracts currently constitute an
insignificant portion of our negotiated contracts on our FERC regulated natural
gas pipelines; consequently, we do not believe that this Modification to Policy
Statement will have a material impact on our business, financial position,
results of operations or cash flows.
SOUTHERN PACIFIC TRANSPORTATION COMPANY EASEMENTS
SFPP, L.P. and Southern Pacific Transportation Company are engaged in a
judicial reference 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 SPTC
should be adjusted pursuant to existing contractual arrangements (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).
Although SFPP received a favorable ruling from the trial court in May 1997, in
September 1999, the California Court of Appeals remanded the case back to the
trial court for further proceeding. SFPP claims that the rent payable for each
of the years 1994 through 2004 should be approximately $4.4 million and SPTC
claims it should be approximately $15.0 million. We believe SPTC's position in
this case is without merit and we have set aside reserves that we believe are
adequate to address any reasonably foreseeable outcome of this matter. The trial
of this matter ended in early March 2003. In the second quarter of 2003, SFPP
received a favorable ruling from the trial court, setting rent at approximately
$5.0 million per year as of January 1, 1994. We expect SPTC to appeal the matter
to the California Court of Appeals.
CARBON DIOXIDE LITIGATION
Kinder Morgan CO2 Company, L.P. directly or indirectly through its ownership
interest in the Cortez Pipeline Company, along with other entities, has been
named as a defendant with several others in a series of lawsuits in the United
States District Court in Denver, Colorado and certain state courts in Colorado
and Texas. The plaintiffs include several private royalty, overriding royalty
and working interest owners at the McElmo Dome (Leadville) Unit in southwestern
Colorado. Plaintiffs in the Colorado state court action also are overriding
royalty interest owners in the Doe Canyon Unit. Plaintiffs seek to also
represent classes of claimants composed of all private and
22
governmental royalty, overriding royalty and working interest owners, and
governmental taxing authorities who have an interest in the carbon dioxide
produced at the McElmo Dome Unit. Plaintiffs claim they and the members of any
classes that might be certified have been damaged because the defendants have
maintained a low price for carbon dioxide in the enhanced oil recovery market in
the Permian Basin and maintained a high cost of pipeline transportation from the
McElmo Dome Unit to the Permian Basin. Plaintiffs claim breaches of contractual
and potential fiduciary duties owed by defendants and also allege other theories
of liability including:
- common law fraud;
- fraudulent concealment; and
- negligent misrepresentation.
In addition to actual or compensatory damages, certain plaintiffs are seeking
punitive or trebled damages as well as declaratory judgment for various forms of
relief, including the imposition of a constructive trust over the defendants'
interests in the Cortez Pipeline and the Partnership. These cases are: CO2
Claims Coalition, LLC v. Shell Oil Co., et al., No. 96-Z-2451 (U.S.D.C. Colo.
filed 8/22/96); Rutter & Wilbanks et al. v. Shell Oil Co., et al., No. 00-Z-1854
(U.S.D.C. Colo. filed 9/22/00); Watson v. Shell Oil Co., et al., No. 00-Z-1855
(U.S.D.C. Colo. filed 9/22/00); Ainsworth et al. v. Shell Oil Co., et al., No.
00-Z-1856 (U.S.D.C. Colo. filed 9/22/00); Shell Western E&P Inc. v. Bailey, et
al., No 98-28630 (215th Dist. Ct. Harris County, Tex. filed 6/17/98); Shores, et
al. v. Mobil Oil Corporation, et al., No. GC-99-01184 (Texas Probate Court,
Denton County filed 12/22/99); First State Bank of Denton v. Mobil Oil
Corporation, et al., No. PR-8552-01 (Texas Probate Court, Denton County filed
3/29/01); and Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43
(Colo. Dist. Ct. Montezuma County filed 3/21/98).
At a hearing conducted in the United States District Court for the District of
Colorado on April 8, 2002, the Court orally announced that it had approved the
certification of proposed plaintiff classes and approved a proposed settlement
in the CO2 Claims Coalition, LLC, Rutter & Wilbanks, Watson, and Ainsworth
cases. The Court entered a written order approving the Settlement on May 6,
2002. Plaintiffs counsel representing Shores, et al. appealed the court's
decision to the 10th Circuit Court of Appeals. On December 26, 2002, the 10th
Circuit Court of Appeals affirmed in all respects the District Court's Order
approving settlement. On March 24, 2003, the plaintiffs' counsel in the Shores
matter filed a Petition for Writ of Certiorari in the United States Supreme
Court seeking to have the Court review and overturn the decision of the 10th
Circuit Court of Appeals. On June 9, 2003, the United States Supreme Court
denied the Writ of Certiorari. On July 16, 2003, the settlement in the CO2
Claims Coalition, LLC, Rutter & Wilbanks, Watson, and Ainsworth cases became
final. Following the decision of the 10th Circuit, the plaintiffs and defendants
jointly filed motions to abate the Shell Western E&P Inc., Shores and First
State Bank of Denton cases in order to afford the parties time to discuss
potential settlement of those matters. These Motions were granted on February 6,
2003. In the Celeste C. Grynberg case, the parties are currently engaged in
discovery.
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.
23
WILL PRICE, ET AL. V. GAS PIPELINES, ET AL., (F/K/A QUINQUE OPERATING COMPANY
ET AL. V. GAS PIPELINES, ET AL.)
Stevens County, Kansas District Court, Case No. 99 C 30. In May, 1999, three
plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto, filed a
purported nationwide class action in the Stevens County, Kansas District Court
against some 250 natural gas pipelines and many of their affiliates. The
District Court is located in Hugoton, Kansas. Certain entities we acquired in
the Kinder Morgan Tejas acquisition are also defendants in this matter. The
Petition (recently amended) alleges a conspiracy to underpay royalties, taxes
and producer payments by the defendants' undermeasurement of the volume and
heating content of natural gas produced from nonfederal lands for more than
twenty-five years. The named plaintiffs purport to adequately represent the
interests of unnamed plaintiffs in this action who are comprised of the nation's
gas producers, State taxing agencies and royalty, working and overriding owners.
The plaintiffs seek compensatory damages, along with statutory penalties, treble
damages, interest, costs and fees from the defendants, jointly and severally.
This action was originally filed on May 28, 1999 in Kansas State Court in
Stevens County, Kansas as a class action against approximately 245 pipeline
companies and their affiliates, including certain Kinder Morgan entities.
Subsequently, one of the defendants removed the action to Kansas Federal
District Court and the case was styled as Quinque Operating Company, et al. v.
Gas Pipelines, et al., Case No. 99-1390-CM, United States District Court for the
District of Kansas. Thereafter, we filed a motion with the Judicial Panel for
Multidistrict Litigation to consolidate this action for pretrial purposes with
the Grynberg False Claim Act cases referred to below, because of common factual
questions. On April 10, 2000, the MDL Panel ordered that this case be
consolidated with the Grynberg federal False Claims Act cases discussed below.
On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling
remanding the case back to the State Court in Stevens County, Kansas. The Court
in Kansas has issued a case management order addressing the initial phasing of
the case. In this initial phase, the court will rule on motions to dismiss
(jurisdiction and sufficiency of pleadings), and if the action is not dismissed,
on class certification. Merits discovery has been stayed. The defendants filed a
motion to dismiss on grounds other than personal jurisdiction, which was denied
by the Court in August, 2002. The Motion to Dismiss for lack of Personal
Jurisdiction of the nonresident defendants has been briefed and is pending. The
current named plaintiffs are Will Price, Tom Boles, Cooper Clark Foundation and
Stixon Petroleum, Inc. Quinque Operating Company has been dropped from the
action as a named plaintiff. On April 10, 2003, the court issued its decision
denying plaintiffs' motion for class certification. On July 8, 2003, a hearing
was held on the motion to amend the complaint. On July 28, 2003, the Court
granted leave to amend the complaint. The amended complaint does not list us or
any of our affiliates as defendants. Additionally, a new complaint was filed and
that complaint does not list us or any of our affiliates as defendants. We will
continue to monitor these matters.
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
Claim 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. Discovery is now underway to
determine issues related to the Court's subject matter jurisdiction arising out
of the False Claim Act.
24
MEL R. SWEATMAN AND PAZ GAS CORPORATION V. GULF ENERGY MARKETING, LLC, ET AL.
On July 25, 2002, we were served with this suit for breach of contract,
tortious interference with existing contractual relationships, conspiracy to
commit tortuous interference and interference with prospective business
relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection
with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to be
shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder Morgan
Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this action
eliminated profit on Kinder Morgan Tejas, a portion of which Mr. Sweatman and
Paz Gas Corporation claim they are entitled to receive under an agreement with a
subsidiary of ours acquired in the Tejas Gas acquisition. We have filed a motion
to remove the case from venue in Dewitt County, Texas to Harris County, Texas,
and our motion was denied in a venue hearing in November 2002.
In a Second Amended Original Petition, Sweatman and Paz assert new and
distinct allegations against us, principally that we were a party to an alleged
commercial bribery committed by us, Gulf Energy Marketing, and Intergen inasmuch
as we, in our role as acquirer of Kinder Morgan Tejas, allegedly paid Intergen
to not renew the underlying Entex contracts belonging to the Tejas/Paz joint
venture. Moreover, new and distinct allegations of breach of fiduciary and
bribery of a fiduciary are also raised in this amended petition for the first
time.
The parties have engaged in some discovery and depositions. Based on the
information available to date and our preliminary investigation, we believe this
suit is without merit and we intend to defend it vigorously.
MAHER ET UX. V. CENTERPOINT ENERGY, INC. D/B/A RELIANT ENERGY, INCORPORATED,
RELIANT ENERGY RESOURCES CORP., ENTEX GAS MARKETING COMPANY, KINDER MORGAN TEXAS
PIPELINE, L.P., KINDER MORGAN ENERGY PARTNERS, L.P., HOUSTON PIPELINE COMPANY,
L.P. AND AEP GAS MARKETING, L.L.C., NO. 30875 (DISTRICT COURT, WHARTON COUNTY
TEXAS).
On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan
Energy Partners, L.P. were served with the above-entitled Complaint. A First
Amended Complaint was served on October 23, 2002, adding additional defendants
Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc., Kinder Morgan
Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. The First Amended
Complaint purports to bring a class action on behalf of those Texas residents
who purchased natural gas for residential purposes from the so-called "Reliant
Defendants" in Texas at any time during the period encompassing "at least the
last ten years."
The Complaint alleges that Reliant Energy Resources Corp., by and through its
affiliates, has artificially inflated the price charged to residential consumers
for natural gas that it allegedly purchased from the non-Reliant defendants,
including the above-listed Kinder Morgan entities. The Complaint further alleges
that in exchange for Reliant Energy Resources Corp.'s purchase of natural gas at
above market prices, the non-Reliant defendants, including the above-listed
Kinder Morgan entities, sell natural gas to Entex Gas Marketing Company 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, violations of the Texas Deceptive
Trade Practices Act, and violations of the Texas Utility Code against some or
all of the Defendants, and civil conspiracy against all of the defendants, and
seeks relief in the form of, inter alia, actual, exemplary and statutory
damages, civil penalties, interest, attorneys' fees and a constructive trust ab
initio on any and all sums which allegedly represent overcharges by Reliant and
Reliant Energy Resources Corp.
On November 18, 2002, the Kinder Morgan defendants filed a Motion to Transfer
Venue and, Subject Thereto, Original Answer to the First Amended Complaint. The
parties are currently engaged in preliminary discovery. Based on the information
available to date and our preliminary investigation, the Kinder Morgan
defendants believe that the claims against them are without merit and intend to
defend against them vigorously.
MARIE SNYDER, ET AL V. CITY OF FALLON, UNITED STATES DEPARTMENT OF THE NAVY,
EXXON MOBIL CORPORATION, KINDER MORGAN ENERGY PARTNERS, L.P., SPEEDWAY GAS
STATION AND JOHN DOES I-X, NO. CV-N-02-0251-ECR-RAM (UNITED STATES DISTRICT
COURT, DISTRICT OF NEVADA)("SNYDER"); FRANKIE SUE GALAZ, ET AL V. UNITED STATES
OF AMERICA, CITY OF FALLON, EXXON MOBIL CORPORATION, KINDER MORGAN ENERGY
PARTNERS, L.P., BERRY HINCKLEY, INC., AND JOHN DOES I-X, NO.
CV-N-02-0630-DWH-RAM (UNITED STATES DISTRICT COURT, DISTRICT OF NEVADA)("GALAZ
I"); FRANKIE SUE GALAZ, ET AL V. CITY OF FALLON, EXXON MOBIL CORPORATION,;
KINDER MORGAN ENERGY PARTNERS, L.P.,
25
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); RICHARD JERNEE, ET AL V. KINDER MORGAN ENERGY PARTNERS, ET
AL, NO. CV03-03482 03613 (SECOND JUDICIAL DISTRICT COURT, STATE OF NEVADA,
COUNTY OF WASHOE) ("JERNEE").
On July 9, 2002, we were served with a purported Complaint for Class Action in
the Snyder case, in which the plaintiffs, on behalf of themselves and others
similarly situated, assert that a leukemia cluster has developed in the City of
Fallon, Nevada. The Complaint alleges that the plaintiffs have been exposed to
unspecified "environmental carcinogens" at unspecified times in an unspecified
manner and are therefore "suffering a significantly increased fear of serious
disease." The plaintiffs seek a certification of a class of all persons in
Nevada who have lived for at least three months of their first ten years of life
in the City of Fallon between the years 1992 and the present who have not been
diagnosed with leukemia.
The Complaint purports to assert causes of action for nuisance and "knowing
concealment, suppression, or omission of material facts" against all defendants,
and seeks relief in the form of "a court-supervised trust fund, paid for by
defendants, jointly and severally, to finance a medical monitoring program to
deliver services to members of the purported class that include, but are not
limited to, testing, preventative screening and surveillance for conditions
resulting from, or which can potentially result from exposure to environmental
carcinogens," incidental damages, and attorneys' fees and costs.
The defendants responded to the Complaint by filing Motions to Dismiss on the
grounds that it fails to state a claim upon which relief can be granted. On
November 7, 2002, the United States District Court granted the Motion to Dismiss
filed by the United States, and further dismissed all claims against the
remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs
filed a Motion for Reconsideration and Leave to Amend, which was denied by the
Court on December 30, 2002. Plaintiffs have filed a Notice of Appeal to the
United States Court of Appeals for the 9th Circuit, which appeal is currently
pending.
On December 3, 2002, plaintiffs filed an additional Complaint for Class Action
in the Galaz I matter asserting the same claims in the same Court on behalf of
the same purported class against virtually the same defendants, including us. On
February 10, 2003, the defendants filed Motions to Dismiss the Galaz I Complaint
on the grounds that it also fails to state a claim upon which relief can be
granted. This motion to dismiss was granted as to all defendants on April 3,
2003. Plaintiffs have filed a Notice of Appeal to the United States Court of
Appeals for the 9th Circuit, which appeal is currently pending.
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). Also on
June 20, 2003, the plaintiffs 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.
In addition, 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 Kinder Morgan Energy Partners, L.P. and several Kinder Morgan related
entities and individuals and additional unrelated defendants ("Jernee").
Plaintiffs in the Jernee matter claim that defendants negligently and
intentionally failed to inspect, repair and replace unidentified segments of
their pipeline and facilities, allowing "harmful substances and emissions and
gases" to damage "the environment and health of human beings." Plaintiffs claim
that "Adam Jernee's death was caused by leukemia that, in turn, is believed to
be due to exposure to industrial chemicals and toxins." Plaintiffs purport to
assert claims for wrongful death, premises liability, negligence, negligence per
se, intentional infliction of emotional distress, negligent infliction of
emotional distress, assault and battery, nuisance, fraud, strict liability, and
aiding and abetting, and seek unspecified special, general and punitive damages.
The Kinder Morgan defendants have not yet been formally served with a copy of
the complaint.
26
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 the Snyder matter, the three
Galaz matters and the Jernee matter are without merit and intend to defend
against them vigorously.
MARION COUNTY, MISSISSIPPI LITIGATION
In 1968, Plantation discovered a release from its 12-inch pipeline in Marion
County, Mississippi. The pipeline was immediately repaired. In 1998 and 1999, 62
lawsuits were filed on behalf of 263 plaintiffs in the Circuit Court of Marion
County, Mississippi. The majority of the claims are based on alleged exposure
from the 1968 release, including claims for property damage and personal injury.
Plantation has resolved some of the lawsuits but lawsuits by 236 of the
plaintiffs are still pending. A trial date has been set for September 2003 for
14 of the plaintiffs. Plantation believes that the ultimate resolution of these
Marion County, Mississippi cases will not have a material effect on its
business, financial position, results of operations or cash flows.
EXXON MOBIL CORPORATION V. GATX CORPORATION, KINDER MORGAN LIQUIDS TERMINALS,
INC. AND ST SERVICES, INC.
On April 23, 2003, Exxon Mobil Corporation filed the Complaint in the Superior
Court of New Jersey, Gloucester County. We filed our answer to the Complaint on
June 27, 2003, in which we denied ExxonMobil's claims and allegations as well as
included counterclaims against ExxonMobil. The lawsuit relates to environmental
remediation obligations at a Paulsboro, New Jersey liquids terminal owned by
ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp.
from 1989 through September 2000, and owned currently by ST Services, Inc. Prior
to selling the terminal to GATX Terminals, ExxonMobil performed an environmental
site assessment of the terminal required prior to sale pursuant to state law.
During the site assessment, ExxonMobil discovered items that required
remediation and the New Jersey Department of Environmental Protection issued an
order that required ExxonMobil to perform various remediation activities to
remove hydrocarbon contamination at the terminal. ExxonMobil, we understand, is
still remediating the site and has not been removed as a responsible party from
the state's cleanup order; however, ExxonMobil claims that the remediation
continues because of GATX Terminals' storage of a fuel additive, MTBE, at the
terminal during GATX Terminals' ownership of the terminal. When GATX Terminals
sold the terminal to ST Services, the parties indemnified one another for
certain environmental matters. When GATX Terminals was sold to us, GATX
Terminals' indemnification obligations, if any, to ST Services may have passed
to us. Consequently, at issue is any indemnification obligations we may owe to
ST Services in respect to environmental remediation of MTBE at the terminal. The
Complaint seeks any and all damages related to remediating MTBE at the terminal,
and, according to the New Jersey Spill Compensation and Control Act, treble
damages may be available for actual dollars incorrectly spent by the successful
party in the lawsuit for remediating MTBE at the terminal.
EXXON MOBIL CORPORATION V. ENRON GAS PROCESSING CO., ENRON CORP., AS PARTY
IN INTEREST FOR ENRON HELIUM COMPANY, A DIVISION OF ENRON CORP., ENRON
LIQUIDS PIPELINE CO., ENRON LIQUIDS PIPELINE OPERATING LIMITED PARTNERSHIP,
KINDER MORGAN OPERATING L.P. "A," AND KINDER MORGAN, INC., NO. 2000-45252
(189TH JUDICIAL DISTRICT COURT, HARRIS COUNTY, TEXAS)
On September 1, 2000, Plaintiff Exxon Mobil Corporation filed its Original
Petition and Application for Declaratory Relief against Kinder Morgan Operating
L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder
Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P.,
Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron
Helium Company. Plaintiff added Enron Corp. as party in interest for Enron
Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a
Defendant. The claims against Enron Corp. were severed into a separate cause of
action. Plaintiff's claims are based on a Gas Processing Agreement entered into
on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company
relating to gas produced in the Hugoton Field in Kansas and processed at the
Bushton Plant, a natural gas processing facility located in Kansas. Plaintiff
also asserts claims relating to the Helium Extraction Agreement entered between
Enron Helium Company (a division of Enron Corp.) and Mobil Oil Corporation dated
March 14, 1988. Plaintiff alleges that Defendants failed to deliver propane and
to allocate plant products to Plaintiff as required by the Gas Processing
Agreement and originally sought damages of approximately $5.9 million.
27
Plaintiff filed its Third Amended Petition on February 25, 2003. In its Third
Amended Petition, Plaintiff alleges claims for breach of the Gas Processing
Agreement and the Helium Extraction Agreement, requests a declaratory judgment
and asserts claims for fraud by silence/bad faith, fraudulent inducement of the
1997 Amendment to the Gas Processing Agreement, civil conspiracy, fraud, breach
of a duty of good faith and fair dealing, negligent misrepresentation and
conversion. As of April 7, 2003, Plaintiff alleged damages for the period
November 1987 through March 1997 in the amount of $30.7 million. On May 2, 2003,
Plaintiff added claims for the period April 1997 through February 2003 in the
amount of $12.9 million. The parties are currently engaged in discovery. Based
on the information available to date in our investigation, the Kinder Morgan
Defendants believe that the claims against them are without merit and intend to
defend against them vigorously.
Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions, that, to the extent an assessment of the
matter is possible, we have established an adequate reserve to cover potential
liability, and that these matters will not have a material adverse effect on our
business, financial position, results of operations or cash flows.
ENVIRONMENTAL MATTERS
We are subject to environmental cleanup and enforcement actions from time to
time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) generally imposes joint and several
liability for cleanup and enforcement costs on current or predecessor owners and
operators of a site, 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
regulations, risks of additional costs and liabilities are inherent in pipeline,
terminal and carbon dioxide field and oil field operations, and there can be no
assurance that we will not incur significant costs and liabilities. Moreover, it
is possible that other developments, such as increasingly stringent
environmental laws, regulations and enforcement policies thereunder, and claims
for damages to property or persons resulting from our operations, could result
in substantial costs and liabilities to us.
We are currently involved in the following governmental proceedings related to
compliance with environmental regulations associated with our assets and have
established a reserve to address the costs associated with the cleanup:
- one cleanup ordered by the United States Environmental Protection Agency
related to ground water contamination in the vicinity of SFPP's storage
facilities and truck loading terminal at Sparks, Nevada;
- several ground water hydrocarbon remediation efforts under administrative
orders issued by the California Regional Water Quality Control Board and two
other state agencies;
- groundwater and soil remediation efforts under administrative orders issued
by various regulatory agencies on those assets purchased from GATX
Corporation, comprising Kinder Morgan Liquids Terminals LLC, CALNEV Pipe
Line LLC and Central Florida Pipeline LLC; and
- a ground water remediation effort taking place between Chevron, Plantation
Pipe Line Company and the Alabama Department of Environmental Management.
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.
Furthermore, 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 indicates possible
environmental impacts from petroleum releases into the soil and groundwater at
six sites. Further delineation and remediation of any environmental impacts from
these matters will be conducted. Reserves have been established to address the
closure of these issues.
28
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. As of June 30, 2003, we have recorded a total reserve for
environmental claims in the amount of $39.5 million. However, we were not able
to reasonably estimate when the eventual settlements of these claims will occur.
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.
In addition to the matters described above, we may face additional challenges
to our rates in the future. Shippers on our pipelines do have rights to
challenge the rates we charge under certain circumstances prescribed by
applicable regulations. There can be no assurance that we will not face
challenges to the rates we receive for services on our pipeline systems in the
future. In addition, since many of our assets are subject to regulation, we are
subject to potential future changes in applicable rules and regulations that may
have an adverse effect on our business, financial position, results of
operations or cash flows.
4. CHANGE IN ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
In August 2001, the Financial Accounting Standards Board issued 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. The
provisions of this Statement are effective for fiscal years beginning after June
15, 2002. We adopted SFAS No. 143 on January 1, 2003.
SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. Its primary impact on
us will be to change the method of accruing for oil production site restoration
costs related to our CO2 Pipelines business segment. Prior to January 1, 2003,
we accounted for asset retirement obligations in accordance with SFAS No. 19,
"Financial Accounting and Reporting by Oil and Gas Producing Companies." 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. Specifically, upon adoption of this Statement, an entity
must recognize the following items in its balance sheet:
- a liability for any existing asset retirement obligations adjusted for
cumulative accretion to the date of adoption;
- an asset retirement cost capitalized as an increase to the
carrying amount of the associated long-lived asset; and
- accumulated depreciation on that capitalized cost.
Amounts resulting from initial application of this Statement shall be measured
using current information, current assumptions and current interest rates. The
amount recognized as an asset retirement cost shall be measured as of the date
the asset retirement obligation was incurred. Cumulative accretion and
accumulated depreciation shall be measured for the time period from the date the
liability would have been recognized had the provisions of this Statement been
in effect to the date of adoption of this Statement.
The cumulative-effect adjustment for this change in accounting principle
resulted in income of $3.5 million in the first quarter of 2003. Furthermore, as
required by SFAS No. 143, we recognized the cumulative-effect of initially
applying SFAS No. 143 as a change in accounting principle as described in
Accounting Principles Board
29
Opinion 20, "Accounting Changes." The cumulative-effect adjustment results from
the difference between the amounts recognized in our consolidated balance sheet
prior to the application of SFAS No. 143 and the net amount recognized in our
consolidated balance sheet pursuant to SFAS No. 143.
In our CO2 Pipelines business segment, we are required to plug and abandon oil
wells that have been removed from service and to remove our surface wellhead
equipment and compressors. As of June 30, 2003, we have recognized asset
retirement obligations in the aggregate amount of $13.7 million relating to
these requirements at existing sites within our CO2 Pipelines segment.
In our Natural Gas Pipelines business segment, if we were to cease providing
utility services, we would be required to remove surface facilities from land
belonging to our customers and others. Our Texas intrastate natural gas pipeline
group has various condensate drip tanks and separators located throughout its
natural gas pipeline systems, as well as inactive gas processing plants,
laterals and gathering systems which are no longer integral to the overall
mainline transmission systems, and asbestos-coated underground pipe which is
being abandoned and retired. Our Kinder Morgan Interstate Gas Transmission
system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of June 30, 2003, we have recognized asset
retirement obligations in the aggregate amount of $2.9 million relating to the
businesses within our Natural Gas Pipelines segment.
We have included $0.8 million of our total $16.6 million asset retirement
obligations as of June 30, 2003 with "Accrued other current liabilities" in the
accompanying consolidated balance sheet and the remaining $15.8 million with
"Other long-term liabilities and deferred credits." 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 the six months ended June 30, 2003 is as
follows (in thousands):
Balance at Dec. 31, 2002................... $ -
Cumulative effect transition adjustment.... 14,125
Liabilities incurred....................... 2,208
Liabilities settled........................ (318)
Accretion expense.......................... 420
Revisions in estimated cash flows.......... 208
------------
Balance at June 30, 2003................... $ 16,643
===========
PRO FORMA INFORMATION
Had the provisions of SFAS No. 143 been in effect prior to January 1, 2003,
our net income and associated per unit amounts, and the amount of our liability
for asset retirement obligations, would have been as follows (in thousands,
except per unit amounts):
Pro Forma Pro Forma
Three Months Ended Six Months Ended
-------------------- -------------------
June 30, June 30, June 30, June 30,
2003 2002 2003 2002
---- ---- ---- ----
Reported income before cumulative effect of a change in
accounting principle.................................. $168,957 $144,517 $335,970 $285,950
Adjustments from change in accounting for asset
retirement obligations................................ -- (291) -- (586)
-------- -------- -------- --------
Adjusted income before cumulative effect of a change in
accounting principle..................................... $168,957 $144,226 $335,970 $285,364
======== ======== ======== ========
Reported income before cumulative effect of a change in
accounting principle per unit (fully diluted)............ $ 0.48 $ 0.48 $ 0.98 $ 0.95
======== ======== ======== ========
Adjusted income before cumulative effect of a change in
accounting principle per unit (fully diluted)............ $ 0.48 $ 0.47 $ 0.98 $ 0.95
======== ======== ======== ========
30
Dec. 31, June 30, Dec. 31,
2002 2002 2001
---- ---- ----
Liability for asset retirement obligations............. $14,125 $14,064 $14,345
5. DISTRIBUTIONS
On May 15, 2003, we paid a cash distribution for the quarterly period ended
March 31, 2003, of $0.64 per unit to our common unitholders and to our class B
unitholders. KMR, our sole i-unitholder, received 859,933 additional i-units
based on the $0.64 cash distribution per common unit. The distributions were
declared on April 16, 2003, payable to unitholders of record as of April 30,
2003.
On July 16, 2003, we declared a cash distribution for the quarterly period
ended June 30, 2003, of $0.65 per unit. The distribution will be paid on or
before August 14, 2003, to unitholders of record as of July 31, 2003. Our common
unitholders and class B unitholders will receive cash. KMR will receive a
distribution in the form of additional i-units based on the $0.65 distribution
per common unit. The number of i-units distributed will be 811,878. For each
outstanding i-unit that KMR holds, a fraction of an i-unit (0.017138) will be
issued. The fraction was determined by dividing:
- $0.65, the cash amount distributed per common unit
by
- $37.927, the average of KMR's limited liability shares' closing market
prices from July 15-28, 2003, 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
Effective January 1, 2002, we adopted Statement of Financial Accounting
Standards No. 141 "Business Combinations" and Statement of Financial Accounting
Standards No. 142 "Goodwill and Other Intangible Assets." These accounting
pronouncements require that we prospectively cease amortization of all
intangible assets having indefinite useful economic lives. Such assets,
including goodwill, are not to be amortized until their lives are determined to
be finite. A recognized intangible asset with an indefinite useful life should
be tested for impairment annually or on an interim basis if events or
circumstances indicate that the fair value of the asset has decreased below its
carrying value. We completed this initial transition impairment test in June
2002 and determined that our goodwill was not impaired as of January 1, 2002. We
have selected an impairment measurement test date of January 1 of each year and
we have determined that our goodwill was not impaired as of January 1, 2003.
Our intangible assets include goodwill, lease value, contracts and agreements.
All of our intangible assets having definite lives are being amortized on a
straight-line basis over their estimated useful lives. SFAS Nos. 141 and 142
also require that we disclose the following information related to our
intangible assets still subject to amortization and our goodwill (in thousands):
June 30, Dec. 31,
2003 2002
--------- ---------
Goodwill....................... $ 869,840 $ 856,940
Lease value.................... 6,124 6,124
Contracts and other............ 11,662 11,580
Accumulated amortization....... (481) (380)
--------- ---------
Other intangibles, net......... 17,305 17,324
--------- ---------
Total intangibles, net......... $ 887,145 $ 874,264
========= =========
31
Changes in the carrying amount of goodwill for the six months ended June 30,
2003 are summarized as follows (in thousands):
Products Natural Gas CO2
Pipelines Pipelines Pipelines Terminals Total
----------- ----------- --------- ----------- ----------
Balance at Dec. 31, 2002...... $ 349,458 $ 307,412 $ 46,101 $ 153,969 $ 856,940
Goodwill acquired............. -- -- -- 12,900 12,900
Goodwill dispositions, net.... -- -- -- -- --
Impairment losses............. -- -- -- -- --
----------- ----------- --------- ----------- ----------
Balance at June 30, 2003...... $ 349,458 $ 307,412 $ 46,101 $ 166,869 $ 869,840
=========== =========== ========= =========== ==========
Amortization expense on intangibles consists of the following (in thousands):
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2003 2002 2003 2002
----------- ------------ ----------- ----------
Lease value............ $ 35 $ 35 $ 70 $ 70
Contracts and other.... 16 10 31 20
----------- ------------ ----------- ----------
$ 51 $ 45 $ 101 $ 90
=========== ============ =========== ==========
Our weighted average amortization period for our intangible assets is
approximately 41 years. Our estimated amortization expense for these assets for
each of the next five fiscal years is $206 thousand.
7. DEBT
Our debt as of June 30, 2003, consisted primarily of:
- a $570 million unsecured 364-day credit facility due October 14, 2003;
- a $480 million unsecured three-year credit facility due October 15, 2005;
- $37.1 million of Series F First Mortgage Notes due December 2004 (our
subsidiary, SFPP, L.P. is the obligor on the notes);
- $200 million of 8.00% Senior Notes due March 15, 2005;
- $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal District
Revenue Bonds due March 15, 2006 (our 66 2/3% owned subsidiary,
International Marine Terminals, is the obligor on the bonds);
- $250 million of 5.35% Senior Notes due August 15, 2007;
- $30 million of 7.84% Senior Notes, with a final maturity of July 2008 (our
subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes);
- $250 million of 6.30% Senior Notes due February 1, 2009;
- $250 million of 7.50% Senior Notes due November 1, 2010;
- $700 million of 6.75% Senior Notes due March 15, 2011;
- $450 million of 7.125% Senior Notes due March 15, 2012;
- $25 million of New Jersey Economic Development Revenue Refunding Bonds due
January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals LLC, is
the obligor on the bonds);
- $87.9 million of Industrial Revenue Bonds with final maturities ranging
from September 2019 to December 2024 (our subsidiary, Kinder Morgan Liquids
Terminals LLC, is the obligor on the bonds);
32
- $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan
Operating L.P. "B," is the obligor on the bonds);
- $300 million of 7.40% Senior Notes due March 15, 2031;
- $300 million of 7.75% Senior Notes due March 15, 2032;
- $500 million of 7.30% Senior Notes due August 15, 2033; and
- a $1.05 billion short-term commercial paper program (supported by our
credit facilities, the amount available for borrowing under our credit
facilities is reduced by our outstanding commercial paper borrowings).
None of our debt or credit facilities are subject to payment acceleration as a
result of any change to our credit ratings. However, the margin that we pay with
respect to LIBOR based borrowings under our credit facilities is tied to our
credit ratings.
Our outstanding short-term debt as of June 30, 2003 was $354.4 million. The
balance consisted of:
- $347.5 million of commercial paper borrowings;
- $5 million under the Central Florida Pipeline LLC Notes; and
- $1.9 million in other borrowings.
We intend and have 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 do not anticipate any liquidity problems. The
weighted average interest rate on all of our borrowings was approximately 4.523%
during the second quarter of 2003 and 5.06% during the second quarter of 2002.
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, 2002.
CREDIT FACILITIES
As of June 30, 2003, we had two credit facilities:
- a $570 million unsecured 364-day credit facility due October 14, 2003; and
- a $480 million unsecured three-year credit facility due October 15, 2005.
On May 5, 2003, we increased the borrowings available under our two credit
facilities by $75 million as follows:
- our $530 million unsecured 364-day credit facility was increased to $570
million; and
- our $445 million unsecured three-year credit facility was increased to $480
million.
Our credit facilities are with a syndicate of financial institutions. Wachovia
Bank, National Association is the administrative agent under both credit
facilities. Interest on the two credit facilities accrues at our option at a
floating rate equal to either:
- the administrative agent's base rate (but not less than the Federal Funds
Rate, plus 0.5%); or
- LIBOR, plus a margin, which varies depending upon the credit rating of our
long-term senior unsecured debt.
33
There were no borrowings under either credit facility at December 31, 2002 or
at June 30, 2003. The amount available for borrowing under our credit facilities
is reduced by:
- a $23.7 million letter of credit that supports Kinder Morgan
Operating L.P. "B"'s tax-exempt bonds;
- a $28 million letter of credit entered into on December 23, 2002 that
supports Nassau County, Florida Ocean Highway and Port Authority tax exempt
bonds (associated with the operations of our bulk terminal facility located
at Fernandina Beach, Florida);
- a $0.2 million letter of credit entered into on June 4, 2002 that supports a
workers' compensation insurance policy;
- a $0.5 million letter of credit entered into on March 31, 2003 that supports
an engineering contract; and
- our outstanding commercial paper borrowings.
Our three-year credit facility also permits us to obtain bids for fixed rate
loans from members of the lending syndicate.
SENIOR NOTES
As of June 30, 2003, our unamortized liability balance due on the various
series of our senior notes was as follows (in millions):
8.0% senior notes due March 15, 2005 ....... $ 199.8
5.35% senior notes due August 15, 2007...... 249.9
6.3% senior notes due February 1, 2009...... 249.5
7.5% senior notes due November 1, 2010...... 248.8
6.75% senior notes due March 15, 2011....... 698.4
7.125% senior notes due March 15, 2012...... 448.1
7.4% senior notes due March 15, 2031........ 299.4
7.75% senior notes due March 15, 2032....... 298.6
7.3% senior notes due August 15, 2033....... 499.0
--------
Total.................................... $3,191.5
========
INTEREST RATE SWAPS
In order to maintain a cost effective capital structure, it is our policy to
borrow funds using a mix of fixed rate debt and variable rate debt. As of June
30, 2003, we have entered into interest rate swap agreements with a notional
principal amount of $1.95 billion for the purpose of hedging the interest rate
risk associated with our fixed and variable rate debt obligations. The $1.95
billion notional principal amount of our interest rate swap agreements has not
changed since December 31, 2002.
These swaps meet the conditions required to assume no ineffectiveness under
SFAS No. 133 and, therefore, we have accounted for them using the "shortcut"
method prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust
the carrying value of each swap to its fair value each quarter, with an
offsetting entry to adjust the carrying value of the debt securities whose fair
value is being hedged. For more information on our risk management activities,
see Note 10.
COMMERCIAL PAPER PROGRAM
As of December 31, 2002 and March 31, 2003, our commercial paper program
provided for the issuance of up to $975 million of commercial paper. On May 5,
2003, we increased the program to allow for the borrowing of up to $1.05 billion
of commercial paper. As of June 30, 2003, we had $347.5 million of commercial
paper outstanding with
34
an average interest rate of 1.22%. Borrowings under our commercial paper program
reduce the borrowings allowed under our credit facilities.
In June 2003, we issued in a public offering, an additional 4,600,000 of our
common units, including 600,000 units upon exercise by the underwriters of an
over-allotment option, at a price of $39.35 per share, less commissions and
underwriting expenses. After commissions and underwriting expenses, we received
net proceeds of $173.3 million for the issuance of these common units. We used
the proceeds to reduce the borrowings under our commercial paper program.
KINDER MORGAN OPERATING L.P. "B" DEBT
The $23.7 million principal amount of tax-exempt bonds due 2024 were issued by
the Jackson-Union Counties Regional Port District. These bonds bear interest at
a weekly floating market rate. During the second quarter of 2003, the
weighted-average interest rate on these bonds was 1.17%, and as of June 30,
2003, the interest rate was 1.03%. We have an outstanding letter of credit
issued under our credit facilities that supports our tax-exempt bonds. The
letter of credit reduces the amount available for borrowing under our credit
facilities.
INTERNATIONAL MARINE TERMINALS DEBT
We own a 66 2/3% interest in International Marine Terminals partnership. The
principal assets owned by IMT are dock and wharf facilities financed by the
Plaquemines Port, Harbor and Terminal District (Louisiana) $40,000,000
Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds
(International Marine Terminals Project) Series 1984A and 1984B. The bonds
mature on March 15, 2006 and are backed by two letters of credit issued by KBC
Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit
Reimbursement Agreement relating to the letters of credit in the amount of $45.5
million was entered into by IMT and KBC Bank. In connection with that agreement,
we agreed to guarantee the obligations of IMT in proportion to our ownership
interest. Our obligation is approximately $30.3 million for principal, plus
interest and other fees.
CONTINGENT DEBT
CORTEZ PIPELINE COMPANY DEBT
Pursuant to a certain Throughput and Deficiency Agreement, the owners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a
subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers Pipeline
Company - 13% owner) are required, on a 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 owners 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 owners
further severally guarantee, on a percentage basis, the obligations of the
Cortez Pipeline Company owners 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 guaranty obligations jointly and
severally through December 31, 2006 for Cortez Capital Corporation's debt
programs in place as of April 1, 2000.
As of June 30, 2003, the debt facilities of Cortez Capital Corporation
consisted of:
- $95 million of Series D notes due May 15, 2013;
- a $175 million short-term commercial paper program; and
- a $175 million committed revolving credit facility due December 26, 2003 (to
support the above-mentioned $175 million commercial paper program).
35
As of June 30, 2003, Cortez Capital Corporation had $151.2 million of
commercial paper outstanding with an interest rate of 1.16%, the average
interest rate on the Series D notes was 7.0389% and there were no borrowings
under the credit facility.
PLANTATION PIPELINE COMPANY DEBT
On April 30, 1997, Plantation Pipeline Company entered into a $10 million,
ten-year floating-rate term credit agreement. We, as an owner of Plantation
Pipeline Company, severally guarantee this debt on a pro rata basis equivalent
to our respective 51% ownership interest. During 1999, this agreement was
amended to reduce the maturity date by three years. The $10 million is
outstanding as of June 30, 2003.
RED CEDAR GAS GATHERING COMPANY DEBT
In October 1998, Red Cedar Gas Gathering Company sold $55 million in aggregate
principal amount of Senior Notes due October 31, 2010. The $55 million was sold
in 10 different notes in varying amounts with identical terms.
The Senior Notes are collateralized by a first priority lien on the ownership
interests, including our 49% ownership interest, in Red Cedar Gas Gathering
Company. The Senior Notes are also guaranteed by us and the other owner of Red
Cedar Gas Gathering Company under joint and several liability. The principal is
to be repaid in seven equal installments beginning on October 31, 2004 and
ending on October 31, 2009, with any remainder due October 31, 2010. The $55
million is outstanding as of June 30, 2003.
NASSAU COUNTY, FLORIDA OCEAN HIGHWAY AND PORT AUTHORITY DEBT
Nassau County, Florida Ocean Highway and Port Authority is a political
subdivision of the State of Florida. During 1990, Ocean Highway and Port
Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal
amount of $38.5 million for the purpose of constructing certain port
improvements located in Fernandino Beach, Nassau County, Florida. A letter of
credit was issued as security for the Adjustable Demand Revenue Bonds and was
guaranteed by the parent company of Nassau Terminals LLC, the operator of the
port facilities. In July 2002, we acquired Nassau Terminals LLC and became
guarantor under the letter of credit agreement. In December 2002, we issued a
$28 million letter of credit under our credit facilities and the former letter
of credit guarantee was terminated.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
RETENTION AGREEMENT
Effective January 17, 2002, KMI entered into a retention agreement with C.
Park Shaper, an officer of KMI, Kinder Morgan G.P., Inc. (our general partner)
and its delegate, KMR. Pursuant to the terms of the agreement, Mr. Shaper
obtained a $5 million personal loan guaranteed by KMI and us. Mr. Shaper was
required to purchase and did purchase KMI common stock and our common units in
the open market with the loan proceeds.
The Sarbanes-Oxley Act of 2002 does not allow companies to issue or guarantee
new loans to executives, but it "grandfathers" loans that were in existence
prior to the act. Regardless, Mr. Shaper and KMI have agreed that in today's
business environment it would be prudent for him to repay the loan. In
conjunction with this decision, Mr. Shaper has sold 37,000 of KMI shares and
82,000 of our common units. He used the proceeds to repay the $5 million
personal loan guaranteed by KMI and us. KMI's and our guarantee of this loan has
been removed. Mr. Shaper will instead participate in KMI's restricted stock plan
with other senior executives.
EXECUTIVE COMPENSATION POLICIES
As is commonly the case for publicly traded limited partnerships, we have no
officers. The executive officers and directors of our general partner serve in
the same capacities for KMR. Certain of those executive officers also
36
serve as executive officers of KMI. All information in this report with respect
to compensation of executive officers describes the total compensation received
by those persons in all capacities for our general partner, KMR, KMI and their
respective affiliates.
On July 16, 2003, KMI announced a change to its compensation policies.
Chairman and Chief Executive Officer Richard D. Kinder will continue to receive
$1 per year in salary with no bonuses, stock options, grants of restricted stock
or other compensation. The ten most senior executives (excluding Mr. Kinder)
will continue to have their base salaries capped at $200,000 per year and will
continue to be eligible for annual bonuses when KMI and we meet annual earnings
per share and distributions per unit targets. In addition, these senior
executives will no longer be eligible for stock options and have received grants
of restricted stock which will vest 25% after three years and the remaining 75%
after five years. It is expected these executives will receive no further equity
compensation during the five-year life of these restrictions. In total, 575,000
restricted shares of KMI common stock have been issued under a shareholder
approved plan. As a result, KMI and we will each expense approximately $3.5
million annually related to the grants of restricted stock. Other than
restricted stock, executives will continue to have only those benefits which are
available to every other employee. All other employees will be eligible for
annual grants of stock options which will vest after three years. On July 16,
2003, KMI issued 656,450 options to purchase common shares for $53.80 (the
closing price of KMI's common shares on that date) to eligible employees.
LINES OF CREDIT
We have agreed to guarantee potential borrowings under lines of credit
available from Wachovia Bank, National Association, formerly known as First
Union National Bank, to Messrs. Thomas Bannigan, C. Park Shaper and James Street
and Ms. Deborah Macdonald. Each of these KMI officers is primarily liable for
any borrowing on his or her line of credit, and if we make any payment with
respect to an outstanding loan, the officer on behalf of whom payment is made
must surrender a percentage of his or her options to purchase KMI common stock.
Our current obligations under the guaranties, on an individual basis, generally
do not exceed $1.0 million and such obligations, in the aggregate, do not exceed
$1.9 million. To date, we have made no payment with respect to these lines of
credit. Further, our involvement in these lines of credit will expire in October
2003.
KMI ASSET CONTRIBUTIONS
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. This amount has not changed as of December 31, 2002 and
June 30, 2003. KMI would be obligated to perform under this guarantee only if we
and/or our assets were unable to satisfy our obligations.
8. PARTNERS' CAPITAL
As of June 30, 2003, our partners' capital consisted of:
- 134,691,308 common units;
- 5,313,400 Class B units; and
- 47,372,962 i-units.
Together, these 187,377,670 units represent the limited partners' interest and
an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights. As of June 30, 2003, our
common unit total consisted of 121,735,573 units held by third parties,
11,231,735 units held by KMI and its consolidated affiliates (excluding our
general partner); and 1,724,000 units held by our general partner. Our Class B
units were held entirely by KMI and our i-units were held entirely by KMR.
37
As of December 31, 2002, our Partners' capital consisted of:
- 129,943,218 common units;
- 5,313,400 Class B units; and
- 45,654,048 i-units.
Our total common units outstanding at December 31, 2002, consisted of
116,987,483 units held by third parties, 11,231,735 units held by KMI and its
consolidated affiliates (excluding our general partner) and 1,724,000 units held
by our general partner. Our Class B units were held entirely by KMI and our
i-units were held entirely by KMR.
In June 2003, we issued in a public offering, an additional 4,600,000 of our
common units, including 600,000 units upon exercise by the underwriters of an
over-allotment option, at a price of $39.35 per share, less commissions and
underwriting expenses. After commissions and underwriting expenses, we received
net proceeds of $173.3 million for the issuance of these common units. We used
the proceeds to reduce the borrowings under our commercial paper program.
All of our Class B units were issued 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. We initially issued i-units in May 2001. The 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, and controlling and managing the business and affairs of, the
Partnership, our operating partnerships and our subsidiaries.
Through the combined effect of the provisions in our partnership agreement and
the provisions of KMR's limited liability company agreement, the number of
outstanding KMR shares and the number of i-units will at all times be equal.
Furthermore, under the terms of our partnership agreement, we agreed that we
will not, except in liquidation, make a distribution on an i-unit other than in
additional i-units or a security that has in all material respects the same
rights and privileges as our i-units. The number of i-units we distribute to KMR
is based upon the amount of cash we distribute to the owners of our common
units. When cash is paid to the holders of our common units, we will issue
additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by
KMR will have the same value as 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 related cash but will retain the
cash and use the cash 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 859,933 i-units on May 15, 2003. These additional
i-units distributed were based on the $0.64 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 that quarterly distributions to unitholders exceed certain specified
target levels. Our distribution of $0.64 per unit paid on May 15, 2003 for the
first quarter of 2003 required an incentive distribution to our general partner
of $75.5 million. Our distribution of $0.59 per unit paid on May 15, 2002 for
the first quarter of 2002 required an incentive distribution to our general
partner of $61.0 million. The increased incentive distribution to our general
partner paid for the first quarter of 2003
38
over the distribution paid for the first quarter of 2002 reflects the increase
in the amount distributed per unit as well as the issuance of additional units.
Our declared distribution for the second quarter of 2003 of $0.65 per unit
will result in an incentive distribution to our general partner of approximately
$79.6 million. This compares to our distribution of $0.61 per unit and incentive
distribution to our general partner of approximately $64.4 million for the
second quarter of 2002.
9. COMPREHENSIVE INCOME
Statement of Financial Accounting Standards No. 130, "Accounting for
Comprehensive Income," requires that enterprises report a total for
comprehensive income. For each of the six months ended June 30, 2003 and 2002,
the only difference between our net income and our comprehensive income was the
unrealized gain or loss on derivatives utilized for hedging purposes. For more
information on our hedging activities, see Note 10. Our total comprehensive
income is as follows (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ----------------------
2003 2002 2003 2002
--------- --------- --------- ---------
Net income.......................................................... $ 168,957 $ 144,517 $339,435 $ 285,950
Change in fair value of derivatives used for hedging purposes....... (19,304) (14,920) (73,174) (81,856)
Reclassification of change in fair value of derivatives to net income 817 11,531 51,248 (12,828)
--------- --------- --------- ---------
Comprehensive income................................................ $ 150,470 $ 141,128 $ 317,509 $ 191,266
========= ========= ========= =========
10. RISK MANAGEMENT
HEDGING ACTIVITIES
Certain of our business activities expose us to risks associated with changes
in the market price of natural gas, natural gas liquids, crude oil and carbon
dioxide. Through KMI, we use energy financial instruments to reduce our risk of
changes in the prices of natural gas, natural gas liquids and crude oil markets
(and carbon dioxide to the extent contracts are tied to crude oil prices) as
discussed below. The fair value of these 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.
The energy risk management products that we use include:
- commodity futures and options contracts;
- fixed-price swaps; and
- basis swaps.
Pursuant to our management's approved policy, we are to engage in these
activities only as a hedging mechanism against price volatility associated with:
- pre-existing or anticipated physical natural gas, natural gas liquids and
crude oil sales;
- pre-existing or anticipated physical carbon dioxide sales that have pricing
tied to crude oil prices;
- natural gas purchases; and
- system use and storage.
39
Our risk management activities are only 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.
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 137, "Accounting for
Derivative Instruments and Hedging Activities - Deferral of the Effective Date
of FASB Statement No.133" and No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities." SFAS No. 133 established accounting
and reporting standards requiring that every derivative financial instrument
(including certain derivative instruments embedded in other contracts) be
recorded in the balance sheet as either an asset or liability measured at its
fair value. However, if the derivative transaction qualifies for and is
designated as a normal purchase and sale, it is exempted from the fair value
accounting requirements of SFAS No. 133 and is accounted for using traditional
accrual accounting.
SFAS No. 133 requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. If the derivatives meet those criteria, SFAS No. 133 allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company formally designate a derivative as a
hedge and document and assess the effectiveness of derivatives associated with
transactions that receive hedge accounting.
Our derivatives that hedge our commodity price risks involve our normal
business activities, which include the sale of natural gas, natural gas liquids,
oil and carbon dioxide, and these derivatives have been designated as cash flow
hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that
hedge exposure to variable cash flows of forecasted transactions as cash flow
hedges and the effective portion of the derivative's gain or loss is initially
reported as a component of other comprehensive income (outside earnings) and
subsequently reclassified into earnings when the forecasted transaction affects
earnings. To be effective, changes in the value of the derivative or its
resulting cash flows must substantially offset changes in the value or cash
flows of the item being hedged. The ineffective portion of the gain or loss is
reported in earnings immediately.
The gains and losses included in Accumulated other comprehensive income are
reclassified into earnings as the hedged sales and purchases take place.
Approximately $41.4 million of the Accumulated other comprehensive loss balance
of $67.2 million representing unrecognized net losses on derivative activities
as of June 30, 2003 is expected to be reclassified into earnings during the next
twelve months. During the six months ended June 30, 2003, we reclassified $51.2
million of accumulated other comprehensive income into earnings. This amount
includes the balance of $45.3 million representing unrecognized net losses on
derivative activities at December 31, 2002. During the quarter ended June 30,
2003, there were no forecasted transactions determined to no longer occur by the
end of the originally specified time period, therefore, we did not reclassify
any gains or losses into earnings as a result of the discontinuance of cash flow
hedges.
We recognized a gain of $0.2 million during the second quarter of 2003 and a
loss of $0.3 million during the second quarter of 2002 as a result of hedge
ineffectiveness. We recognized a gain of $0.4 million during the first six
months of 2003 and a gain of $0.5 million during the first six months of 2002 as
a result of hedge ineffectiveness. All of these amounts are reported within the
captions "Gas purchases and other costs of sales" and "Operations and
maintenance" in the accompanying Consolidated Statements of Income. For each of
the six months ended June 30, 2003 and 2002, we did not exclude any component of
the derivative instruments' gain or loss from the assessment of hedge
effectiveness.
The differences between the current market value and the original physical
contracts value associated with our hedging activities are primarily reflected
as "Other current assets" and "Accrued other current liabilities" in the
accompanying consolidated balance sheets.
As of June 30, 2003, the balance in "Other current assets" on our consolidated
balance sheet included $58.8 million related to risk management hedging
activities, and the balance in "Accrued other current liabilities" included
$100.7 million related to risk management hedging activities. As of December 31,
2002, the balance in "Other current assets" on our consolidated balance sheet
included $57.9 million related to risk management hedging activities, and the
balance in "Accrued other current liabilities" included $101.3 million related
to risk management
40
hedging activities.
The remaining differences between the current market value and the original
physical contracts value associated with our hedging activities are reflected as
deferred charges or deferred credits in the accompanying consolidated balance
sheets. As of June 30, 2003, the balance in "Deferred charges and other assets"
included $3.7 million related to risk management hedging activities, and the
balance in "Other long-term liabilities and deferred credits" included $29.8
million related to risk management hedging activities. As of December 31, 2002,
the balance in "Deferred charges and other assets" included $5.7 million related
to risk management hedging activities, and the balance in "Other long-term
liabilities and deferred credits" included $8.5 million related to risk
management hedging activities.
Our over-the-counter swaps and options are with a number of parties, who
principally have investment grade credit ratings. We both owe money and are owed
money under these financial instruments. 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.
INTEREST RATE SWAPS
In order to maintain a cost effective capital structure, it is our policy to
borrow funds using a mix of fixed rate debt and variable rate debt. As of June
30, 2003 and as of December 31, 2002, we were a party to interest rate swap
agreements with a notional principal amount of $1.95 billion for the purpose of
hedging the interest rate risk associated with our fixed and variable rate debt
obligations.
As of June 30, 2003, a notional principal amount of $1.75 billion of these
agreements effectively converts the interest expense associated with the
following series of our senior notes from fixed rates to variable rates based on
an interest rate of LIBOR plus a spread:
- $200 million principal amount of our 8.0% senior notes due March 15, 2005;
- $200 million principal amount of our 5.35% senior notes due August 15, 2007;
- $250 million principal amount of our 6.30% senior notes due February 1,
2009;
- $200 million principal amount of our 7.125% senior notes due March 15, 2012;
- $300 million principal amount of our 7.40% senior notes due March 15, 2031;
- $200 million principal amount of our 7.75% senior notes due March 15, 2032;
and
- $400 million principal amount of our 7.30% senior notes due August 15, 2033.
These swap agreements have termination dates that correspond to the maturity
dates of the related series of senior notes, therefore, as of June 30, 2003, the
maximum length of time over which we have hedged our exposure to the variability
in future cash flows associated with interest rate risk is through August 2033.
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 at March 15, 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 years.
41
These interest rate swaps have been designated as fair value hedges as
defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge a
recognized asset or liability's exposure to changes in their fair value as fair
value hedges and the gain or loss on fair value hedges are to be recognized in
earnings in the period of change together with the offsetting loss or gain on
the hedged item attributable to the risk being hedged. The effect of that
accounting is to reflect in earnings the extent to which the hedge is not
effective in achieving offsetting changes in fair value.
As of June 30, 2003, we also had swap agreements that effectively convert the
interest expense associated with $200 million of our variable rate debt to fixed
rate. The maturity dates of these swap agreements range from September 2, 2003
to September 1, 2005. Prior to March 2002, this swap was designated a hedge of
our $200 million Floating Rate Senior Notes, which were retired (repaid) in
March 2002. Subsequent to the repayment of our Floating Rate Senior Notes, the
swaps were designated as a cash flow hedge of the risk associated with changes
in the designated benchmark interest rate (in this case, one-month LIBOR)
related to forecasted payments associated with interest on an aggregate of $200
million of our portfolio of commercial paper.
Our interest rate swaps meet the conditions required to assume no
ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed for fair value hedges by SFAS No. 133.
Accordingly, we adjust the carrying value of each swap to its fair value each
quarter, with an offsetting entry to adjust the carrying value of the debt
securities whose fair value is being hedged. We record interest expense equal to
the variable rate payments or fixed rate payments under the swaps. Interest
expense is accrued monthly and paid semi-annually. As of June 30, 2003, we
recognized an asset of $249.0 million and a liability of $10.4 million for the
$238.7 million net fair value of our swap agreements, and we included these
amounts with "Deferred charges and other assets" and "Other long-term
liabilities and deferred credits" on the accompanying balance sheet. The
offsetting entry to adjust the carrying value of the debt securities whose fair
value was being hedged was recognized as "Market value of interest rate swaps"
on the accompanying balance sheet. As of December 31, 2002, we recognized an
asset of $179.1 million and a liability of $12.1 million for the $167.0 million
net fair value of our swap agreements, and we included these amounts with
"Deferred charges and other assets" and "Other long-term liabilities and
deferred credits" on the accompanying balance sheet and again, the offsetting
entry to adjust the carrying value of the debt securities whose fair value was
being hedged was recognized as "Market value of interest rate swaps" on the
accompanying balance sheet.
We are exposed to credit related losses in the event of nonperformance by
counterparties to these interest rate swap agreements. While we enter into
derivative transactions primarily with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that from
time to time losses will result from counterparty credit risk.
11. REPORTABLE SEGMENTS
We divide our operations into four reportable business segments:
- Products Pipelines;
- Natural Gas Pipelines;
- CO2 Pipelines; and
- Terminals.
We evaluate performance based on each segments' earnings, which exclude
general and administrative expenses, third-party debt costs, interest income and
expense 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.
42
Our Products Pipelines segment derives its revenues primarily from the
transportation and terminaling of refined petroleum products, including
gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas
Pipelines segment derives its revenues primarily from the transmission, storage,
gathering and sale of natural gas. Our CO2 Pipelines segment derives its
revenues primarily from the transportation and marketing of carbon dioxide used
as a flooding medium for recovering crude oil from mature oil fields, and from
the production and sale of crude oil from fields in the Permian Basin of West
Texas. Our Terminals segment derives its revenues primarily from the
transloading and storing of refined petroleum products and dry and liquid bulk
products, including coal, petroleum coke, cement, alumina, salt, and chemicals.
Financial information by segment follows (in thousands):
Three Months Ended June 30, Six Months Ended June 30,
------------------------------ ------------------------------
2003 2002 2003 2002
------------- ------------- ------------- -------------
Revenues
Products Pipelines................................. $ 145,284 $ 145,641 $ 289,701 $ 280,459
Natural Gas Pipelines.............................. 1,341,160 800,946 2,822,114 1,338,503
CO2 Pipelines...................................... 54,631 34,416 103,087 66,540
Terminals.......................................... 123,372 109,933 238,383 208,499
------------- ------------- ------------- -------------
Total consolidated revenues........................ $ 1,664,447 $ 1,090,936 $ 3,453,285 $ 1,894,001
============= ============= ============= =============
Operating expenses (a)
Products Pipelines................................. $ 40,480 $ 41,526 $ 81,666 $ 81,775
Natural Gas Pipelines.............................. 1,258,224 733,068 2,653,756 1,197,693
CO2 Pipelines...................................... 16,290 13,671 32,803 26,172
Terminals.......................................... 62,147 57,491 117,947 106,467
------------- ------------- ------------- -------------
Total consolidated operating expenses.............. $ 1,377,141 $ 845,756 $ 2,886,172 $ 1,412,107
============= ============= ============= =============
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes. Second quarter 2003 amounts include an additional $171 of non-cash
asset retirement obligation accretion expense that was included within
"Operations and maintenance" expense in our first quarter 2003 consolidated
statement of income, but reported within segmental "Depreciation and
amortization." Accretion expense of $169 is included in CO2 Pipelines'
depreciation and amortization total and $2 is included in Natural Gas
Pipelines' depreciation and amortization total.
Depreciation and amortization (a)
Products Pipelines................................. $ 16,723 $ 16,048 $ 33,283 $ 32,044
Natural Gas Pipelines.............................. 13,603 12,479 26,229 23,904
CO2 Pipelines...................................... 14,281 6,893 26,043 13,882
Terminals.......................................... 8,980 7,203 18,008 14,119
------------- ------------- ------------- -------------
Total consolidated depreciation and amortization... $ 53,587 $ 42,623 $ 103,563 $ 83,949
============= ============= ============= =============
(a) Second quarter 2003 amounts include a reduction of $171 of non-cash asset
retirement obligation accretion expense that was included within
"Operations and maintenance" expense in our first quarter 2003 consolidated
statement of income, but reported within segmental "Depreciation and
amortization." CO2 Pipelines' depreciation and amortization total is
reduced by $169 of accretion expense and Natural Gas Pipelines'
depreciation and amortization total is reduced by $2.
Earnings from equity investments
Products Pipelines................................. $ 7,587 $ 9,107 $ 15,630 $ 17,108
Natural Gas Pipelines.............................. 6,159 5,972 12,383 12,097
CO2 Pipelines...................................... 8,864 9,265 18,870 18,410
Terminals.......................................... 8 (47) 40 (47)
------------- -------------- ------------- --------------
Total consolidated equity earnings................. $ 22,618 $ 24,297 $ 46,923 $ 47,568
============= ============= ============= =============
Amortization of excess cost of equity investments
Products Pipelines................................. $ 821 $ 821 $ 1,642 $ 1,642
Natural Gas Pipelines.............................. 69 69 138 138
CO2 Pipelines...................................... 504 504 1,008 1,008
Terminals.......................................... -- -- -- --
------------- ------------- ------------- -------------
Total consol. amortization of excess cost of invests $ 1,394 $ 1,394 $ 2,788 $ 2,788
============= ============= ============= =============
43
Three Months Ended June 30, Six Months Ended June 30,
------------------------------ -------------------------------
2003 2002 2003 2002
-------------- -------------- -------------- --------------
Income taxes and Other, net - income (expense)
Products Pipelines................................. $ (1,856) $ (2,980) $ (4,456) $ (5,755)
Natural Gas Pipelines.............................. (223) 14 (308) 19
CO2 Pipelines...................................... (32) (4) (15) 90
Terminals.......................................... (2,697) (1,678) (3,940) (3,453)
-------------- -------------- -------------- --------------
Total consolidated income taxes and other, net..... $ (4,808) $ (4,648) $ (8,719) $ (9,099)
============== ============== ============== ==============
Operating income
Products Pipelines................................. $ 88,081 $ 88,067 $ 174,752 $ 166,640
Natural Gas Pipelines.............................. 69,333 55,399 142,129 116,906
CO2 Pipelines...................................... 24,060 13,852 44,241 26,486
Terminals.......................................... 52,245 45,239 102,428 87,913
------------- ------------- ------------- -------------
Total segment operating income (a) ................ 233,719 202,557 463,550 397,945
Corporate administrative expenses.................. (34,157) (30,210) (68,836) (59,742)
-------------- -------------- -------------- --------------
Total consolidated operating income................ $ 199,562 $ 172,347 $ 394,714 $ 338,203
============== ============== ============== ==============
(a) Represents amounts reported above as revenues, less operating expenses and
depreciation and amortization.
Segment earnings before depreciation and amortization and amortization of excess cost of equity investments
Products Pipelines................................. $ 110,535 $ 110,242 $ 219,209 $ 210,037
Natural Gas Pipelines.............................. 88,872 73,864 180,433 152,926
CO2 Pipelines...................................... 47,173 30,006 89,139 58,868
Terminals.......................................... 58,536 50,717 116,536 98,532
------------- ------------- ------------- -------------
Total segment earnings before DD&A (a)............. 305,116 264,829 605,317 520,363
Total consolidated depreciation and amortization (b) (53,587) (42,623) (103,563) (83,949)
Total consol. amortization of excess cost of invests (1,394) (1,394) (2,788) (2,788)
Interest and corporate administrative expenses (c). (81,178) (76,295) (159,531) (147,676)
-------------- -------------- -------------- --------------
Total consolidated net income ..................... $ 168,957 $ 144,517 $ 339,435 $ 285,950
============= ============= ============= =============
(a) Represents amounts reported above as revenues, earnings from equity
investments and income taxes and other, net, less operating expenses.
(b) Second quarter 2003 amounts include a reduction of $171 of non-cash asset
retirement obligation accretion expense that was included within
"Operations and maintenance" expense in our first quarter 2003 consolidated
statement of income, but reported within segmental "Depreciation and
amortization." CO2 Pipelines' depreciation and amortization total is
reduced by $169 of accretion expense and Natural Gas Pipelines'
depreciation and amortization total is reduced by $2. (c) Includes interest
and debt expense, general and administrative expenses, minority interest
expense, cumulative effect adjustment from a change in accounting principle
(2003 only) and other insignificant items.
Segment earnings
Products Pipelines................................. $ 92,991 $ 93,373 $ 184,284 $ 176,351
Natural Gas Pipelines.............................. 75,200 61,316 154,066 128,884
CO2 Pipelines...................................... 32,388 22,609 62,088 43,978
Terminals.......................................... 49,556 43,514 98,528 84,413
------------- ------------- ------------- -------------
Total segment earnings (a)......................... 250,135 220,812 498,966 433,626
Interest and corporate administrative expenses (b). (81,178) (76,295) (159,531) (147,676)
-------------- -------------- -------------- --------------
Total consolidated net income...................... $ 168,957 $ 144,517 $ 339,435 $ 285,950
============= ============= ============= =============
(a) Represents amounts reported above as revenues, earnings from equity
investments and income taxes and other, net, less operating expenses,
depreciation and amortization and amortization of excess cost of equity
investments.
(b) Includes interest and debt expense, general and administrative expenses,
minority interest expense, cumulative effect adjustment from a change in
accounting principle (2003 only) and other insignificant items.
44
June 30, Dec. 31,
2003 2002
-------------- ----------
Assets
Products Pipelines..................... $ 3,126,876 $ 3,088,799
Natural Gas Pipelines.................. 3,329,924 3,121,674
CO2 Pipelines.......................... 782,192 613,980
Terminals.............................. 1,305,233 1,165,096
------------- -------------
Total segment assets................... 8,544,225 7,989,549
Corporate assets (a)................... 314,954 364,027
------------- -------------
Total consolidated assets.............. $ 8,859,179 $ 8,353,576
============= =============
(a) Includes cash, cash equivalents and certain unallocable deferred charges.
12. NEW ACCOUNTING PRONOUNCEMENTS
In April 2003, the Financial Accounting Standards Board issued SFAS No. 149,
"Amendment of Statement 133 on Derivative Instruments and Hedging Activities."
This Statement amends and clarifies accounting for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities under SFAS No. 133.
The new guidance amends SFAS No. 133 for decisions made:
- as part of the Derivatives Implementation Group process that
effectively required amendments to SFAS No. 133;
- in connection with other Board projects dealing with
financial instruments; and
- regarding implementation issues raised in relation to the application of the
definition of a derivative, particularly regarding the meaning of an
"underlying" and the characteristics of a derivative that contains financing
components.
The amendments set forth in SFAS No. 149 are intended to improve financial
reporting by requiring that contracts with comparable characteristics be
accounted for similarly. In particular, this Statement clarifies under what
circumstances a contract with an initial net investment meets the
characteristics of a derivative as discussed in SFAS No. 133. In addition, it
clarifies when a derivative contains a financing component that warrants special
reporting in the statement of cash flows. SFAS No. 149 amends certain other
existing pronouncements. These changes are intended to result in more consistent
reporting of contracts that are derivatives in their entirety or that contain
embedded derivatives that warrant separate accounting.
This Statement is effective for contracts entered into or modified after June
30, 2003, except as stated below and for hedging relationships designated after
June 30, 2003. We will apply this guidance prospectively. We have not yet
quantified the impacts of adopting this Statement on our financial position,
results of operations or cash flows.
We will continue to apply the provisions of this Statement that relate to SFAS
No. 133 Implementation Issues that have been effective for fiscal quarters that
began prior to June 15, 2003, in accordance with their respective effective
dates. In addition, certain provisions relating to forward purchases or sales of
"when-issued" securities or other securities that do not yet exist, will be
applied to existing contracts as well as new contracts entered into after June
30, 2003.
In May 2003, the Financial Accounting Standards Board issued SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity." This Statement establishes standards for how an issuer
classifies and measures certain financial instruments with characteristics of
both liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances). Many of those instruments were previously classified as equity.
SFAS No. 150 requires an issuer to classify the following instruments as
liabilities (or assets in some circumstances):
45
- a financial instrument issued in the form of shares that is mandatorily
redeemable - that embodies an unconditional obligation requiring the issuer
to redeem it by transferring its assets at a specified or determinable date
(or dates) or upon an event that is certain to occur;
- a financial instrument, other than an outstanding share, that, at inception,
embodies an obligation to repurchase the issuer's equity shares, or is
indexed to such an obligation, and that requires or may require the issuer
to settle the obligation by transferring assets (for example, a forward
purchase contract or written put option on the issuer's equity shares that
is to be physically settled or net cash settled); and
- a financial instrument that embodies an unconditional obligation, or a
financial instrument other than an outstanding share that embodies a
conditional obligation, that the issuer must or may settle by issuing a
variable number of its equity shares, if, at inception, the monetary value
of the obligation is based solely or predominantly on any of the following:
- a fixed monetary amount known at inception, for example, a payable
settleable with a variable number of the issuer's equity shares;
- variations in something other than the fair value of the issuer's equity
shares, for example, a financial instrument indexed to the Standard &
Poor 500 and settleable with a variable number of the issuer's equity
shares; or
- variations inversely related to changes in the fair value of the issuer's
equity shares, for example, a written put option that could be net share
settled.
The requirements of this Statement apply to issuers' classification and
measurement of freestanding financial instruments, including those that comprise
more than one option or forward contract. This Statement does not apply to
features that are embedded in a financial instrument that is not a derivative in
its entirety. It also does not affect the classification or measurement of
convertible bonds, puttable stock, or other outstanding shares that are
conditionally redeemable. This Statement also does not address certain financial
instruments indexed partly to the issuer's equity shares and partly, but not
predominantly, to something else.
This Statement is effective for financial instruments entered into or modified
after May 31, 2003, and otherwise is effective at the beginning of the first
interim period beginning after June 15, 2003, except for mandatorily redeemable
financial instruments of nonpublic entities. It is to be implemented by
reporting the cumulative effect of a change in accounting principle for
financial instruments created before the issuance date of the Statement and
still existing at the beginning of the interim period of adoption. Restatement
is not permitted. We will apply this guidance prospectively. We do not expect
the adoption of this Statement to have any immediate effect on our consolidated
financial statements.
In January 2003, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 46, "Consolidation of Variable Interest Entities". This
interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial
Statements", provides guidance on the identification of, and financial reporting
for, entities over which control is achieved through means other than voting
rights; such entities are known as variable interest entities (VIE). FIN No. 46
is the guidance that determines:
- whether consolidation is required under the "controlling
financial interest" model of ARB No. 51 or other existing
authoritative guidance; or
- whether the variable-interest model under FIN No. 46 should be
used to account for existing and new entities.
All entities, other than those excluded from the scope of FIN No. 46, must
first decide whether an entity is a VIE. If an entity meets FIN No. 46's
criteria for VIE status, FIN No. 46 is applicable. Otherwise, existing
authoritative guidance for consolidation should be applied. FIN No. 46 also
provides guidance for identifying the enterprise that will consolidate a VIE,
which is the enterprise that is exposed to the majority of an entity's risks
(defined as expected losses) or receives the majority of the benefits from an
entity's activities (defined as expected residual
46
returns). That enterprise is referred to as the "primary beneficiary" of the
VIE, and FIN No. 46 requires that the primary beneficiary and all other
enterprises that hold a significant variable interest in a VIE make new
disclosure in their financial statements.
Pursuant to FIN No. 46, an entity is considered a VIE if any of the following
factors are present:
- the equity investment in the entity is insufficient to finance the
operations of that entity without additional subordinated financial support
from other parties;
- the equity investors of the entity lack decision-making rights;
- an equity investor holds voting rights that are disproportionately low in
relation to the actual economics of the investor's relationship with the
entity, and substantially all of the entity's activities involve or are
conducted on behalf of that investor;
- other parties protect the equity investors from expected losses;
- parties, other than the equity holders, hold the right to receive the
entity's expected residual returns, or the equity investors' rights to
expected residual returns is capped.
Therefore, some common structures, such as limited partnerships, joint
venture, trusts, and vendor-financing arrangements, may, in certain instances,
qualify as VIEs under FIN No. 46's criteria. In addition, FIN No. 46 requires
that, upon meeting certain criteria, portions of a legal entity must be
evaluated as separate VIEs, apart from the larger entity. FIN No. 46 is
effective no later than the beginning of the first interim or annual reporting
period that starts after June 15, 2003. We do not expect the adoption of this
Statement to have any immediate effect on our consolidated financial statements.
47
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
RESULTS OF OPERATIONS
Throughout the following discussion and analysis, we refer to (i) revenues,
(ii) costs and expenses, (iii) operating income, (iv) earnings from equity
investments, net of amortization of excess cost, and (v) earnings.
Costs and expenses include (i) natural gas purchases and other costs of sales,
(ii) operations and maintenance expenses, (iii) fuel and power expenses, (iv)
depreciation, depletion and amortization (v) general and administrative
expenses, and (vi) taxes, other than income taxes.
Our operating income represents revenues less costs and expenses. Our segment
earnings represent (i) operating income, (ii) earnings from equity investments,
net of amortization of excess cost, (iii) interest income and expense, (iv)
other income and expense items, net, (v) minority interest, and (vi) income
taxes. We do not attribute general and administrative expenses, interest income
and expense or minority interest to any of our reportable business segments. For
more detailed segment information, please refer to Note 11 to our Consolidated
Financial Statements, entitled "Reportable Segments" included elsewhere in this
report.
SECOND QUARTER 2003 COMPARED WITH SECOND QUARTER 2002
Our earnings for the second quarter of 2003 were the highest level ever
achieved in the history of the Partnership in a quarter not impacted by a change
in accounting principle. The results reflect our continued focus on increasing
the utilization of our existing assets and investing in capital expansion
projects necessary to meet the energy demands of our customers. Total
consolidated net income for the quarter was $169.0 million ($0.48 per diluted
unit), a 17% increase from the $144.5 million ($0.48 per diluted unit) in net
income reported for the second quarter of 2002. Revenues for the second quarter
of 2003 totaled $1,664.4 million, compared with revenues of $1,090.9 million in
the same period last year.
Costs and expenses were $1,464.8 million in the second quarter of 2003,
compared with $918.6 million in the same period a year ago. Our second quarter
2003 operating income was $199.6 million, the highest level ever attained and
16% over the $172.3 million in operating income earned during the second quarter
of 2002.
Earnings and revenues grew in each of our four reportable business segments
except Products Pipelines, where both earnings and revenues were essentially
stable. The increase in our overall earnings was primarily driven by higher
earnings from our Natural Gas Pipelines and CO2 Pipelines business segments. The
increase was driven by internal growth of operations since the start of the
second quarter of 2002, primarily related to increased natural gas
transportation, storage and sales activity and to higher oil sales volumes and
realized average hedged oil prices.
Second quarter earnings from our investments accounted for under the equity
method of accounting, which include our investments in Plantation Pipe Line
Company, Cortez Pipeline Company and the Red Cedar Gathering Company, were $21.2
million in the second quarter of 2003, compared with $22.9 million in the second
quarter of 2002. The $1.7 million (7%) decrease in equity earnings, net of
amortization of excess costs was primarily due to lower returns from our 51%
ownership interest in Plantation Pipe Line Company, partially offset by higher
returns from our 49% ownership interest in the Red Cedar Gathering Company.
In addition, on July 16, 2003, we declared a record quarterly cash
distribution of $0.65 per unit (an annualized rate of $2.60). This second
quarter 2003 distribution will be paid on August 14, 2003, and is 7% higher than
the $0.61 per unit distribution we made for the second quarter of 2002.
PRODUCTS PIPELINES
Our Products Pipelines segment reported earnings of $93.0 million on revenues
of $145.3 million in the second quarter of 2003. In the second quarter of 2002,
the segment reported earnings of $93.4 million on revenues of $145.6 million.
Operating income for each of the quarters ended June 30, 2003 and 2002 was a
steady $88.1 million.
48
Both the $0.4 million (0%) decrease in quarter-to-quarter segment earnings and
the $0.3 million (0%) decrease in quarter-to-quarter segment revenues were
mainly due to lower revenues from our 44.8% ownership interest in the Cochin
pipeline system. Cochin reported a $3.4 million (37%) decrease in revenues in
the second quarter of 2003 compared to the second quarter of 2002, primarily as
a result of lower delivery volumes associated with decreased propane production
in western Canada. The drop in propane production was due to lower profit
margins from the extraction and sale of natural gas liquids caused by the rise
in natural gas prices since the end of the second quarter of 2002. In addition,
revenues from our Cypress pipeline were down a slight $0.4 million (22%) as a
result of lower average tariff rates; however, the revenue decreases from both
Cochin and Cypress were almost entirely offset by higher revenues from all other
segment assets, including our Pacific operations, which reported a $1.8 million
(2%) increase in quarterly revenues, primarily due to higher terminal revenue.
Revenues from our CALNEV and Central Florida pipelines increased $0.5 million
(4%) and $0.4 million (5%), respectively, in the second quarter of 2003 compared
with the second quarter of 2002. On both pipeline systems, the increase in
quarterly revenues was mainly the result of higher average tariff rates.
Overall, total segment delivery volumes decreased 3% in the second quarter of
2003 compared to the same quarter of 2002. A decline in jet fuel volumes was
more than offset by an increase in delivered diesel volumes. Gasoline delivery
volumes were down almost 5% due to refinery problems in the Southeast and the
continuing process of converting from methyl tertiary-butyl ether (MTBE) to
ethanol in the State of California. California has mandated the elimination of
MTBE from gasoline by January 1, 2004. MTBE-blended gasoline is being replaced
by an ethanol blend and since ethanol is not shipped in our pipelines, we
realized a small reduction in California gasoline volumes. We believe, however,
that the fees we will earn for new ethanol-related services at our terminals
will more than offset the expected reduction in our pipeline transportation
fees.
The segment's costs and expenses totaled $57.2 million in the second quarter
of 2003 and $57.5 million in the second quarter of 2002. The $0.3 million (1%)
decrease in segment expenses was mainly due to lower fuel and power expenses on
our Pacific and CALNEV pipelines, favorable adjustments to operating expenses on
our Central Florida pipeline, and lower operating and maintenance expenses on
the Cochin pipeline as a result of the decrease in its throughput volumes.
Earnings from our Products Pipelines' equity investments, net of amortization
of excess costs, were $6.8 million in the second quarter of 2003 and $8.3
million in the second quarter of 2002. The $1.5 million (18%) decrease was due
to lower earnings from our investment in Plantation Pipe Line Company.
Plantation's earnings were impacted by higher oil losses, resulting mainly from
unfavorable variances in inventory costs, and by lower delivery volumes compared
to the second quarter of 2002, when Plantation reported an all-time record
throughput.
NATURAL GAS PIPELINES
Our Natural Gas Pipelines segment reported earnings of $75.2 million on
revenues of $1,341.2 million in the second quarter of 2003. In the second
quarter of 2002, the segment reported earnings of $61.3 million on revenues of
$800.9 million. The segment's costs and expenses were $1,271.9 million in the
second quarter of 2003 and $745.5 million in the second quarter of 2002.
Operating income for each of the two quarters ended June 30, 2003 and 2002 was
$69.3 million and $55.4 million, respectively.
Increases in the price of natural gas since the end of the second quarter of
2002 have driven the quarter-to-quarter increase in segment revenues, but the
higher revenues have likewise been offset by similar increases in natural gas
purchase costs. The segment's $13.9 million (23%) increase in earnings in the
second quarter of 2003 compared to the second quarter of 2002 was primarily
attributable to increased natural gas transportation, storage and sales activity
on our Texas intrastate natural gas pipeline group, which includes the following
four operations:
- our Kinder Morgan Texas Pipeline system, acquired effective December 31,
2000;
- our Kinder Morgan Tejas system, acquired effective January 31, 2002;
- our Kinder Morgan North Texas Pipeline system, completed in August 2002; and
- our Mier-Monterrey Mexico Pipeline, completed in March 2003.
49
The combination of these pipeline systems has produced a complementary
intrastate pipeline business that purchases, sells and transports significant
volumes of natural gas. Together, our Texas intrastate group accounted for
approximately $12.0 million and $524.6 million of the total quarter-to-quarter
increases in segment earnings and revenues, respectively. By entering into new
long-term transportation, storage and sales contracts with customers like BP and
Pemex, and by extending existing contracts with other customers, our Texas
intrastate group increased total transport volumes by 28% and sales volumes by
11% in the second quarter of 2003, compared to the same quarter last year. Our
North Texas and Mier-Monterrey pipeline systems, both placed in service and
included as part of our Texas intrastate natural gas pipeline group since the
end of the second quarter of 2002, reported combined earnings of $3.7 million on
revenues of $5.4 million in the second quarter of 2003.
The segment also benefited from higher earnings from our Kinder Morgan
Interstate Gas Transmission and Trailblazer Pipeline Company natural gas
pipeline systems. Together, these two Rocky Mountain natural gas pipeline
systems accounted for $2.2 million of the quarter-to-quarter increase in segment
earnings. KMIGT's earnings increase was primarily the result of increased
transport services and higher operational sales of natural gas at higher
margins. Trailblazer's increase was driven by a 16% increase in natural gas
transport volumes in the second quarter of 2003 compared to the second quarter
of 2002. In May 2002, we completed a fully-subscribed, $59 million expansion
project on our Trailblazer system that increased transportation capacity on the
pipeline by approximately 60%.
Earnings from our Natural Gas Pipelines' equity investments, net of
amortization of excess costs, were essentially flat for the second quarter of
2003 compared to the second quarter of 2002. The segment's equity investments,
which include investments in Red Cedar, Thunder Creek Gas Services, LLC and
Coyote Gas Treating, LLC, reported $6.1 million in net equity earnings for the
second quarter of 2003 versus $5.9 million for the same prior year period. The
$0.2 million (3%) increase in equity earnings was mainly due to higher earnings
from the segment's 49% ownership interest in Red Cedar, primarily due to lower
right-of-way expenses as a result of certain capital investments made in the
fourth quarter of 2002.
CO2 PIPELINES
Our CO2 Pipelines segment reported earnings of $32.4 million on revenues of
$54.6 million in the second quarter of 2003. The segment reported earnings of
$22.6 million on revenues of $34.4 million in the same period of 2002. Costs and
expenses totaled $30.5 million in the second quarter of 2003 and $20.5 million
in the same quarter last year. Operating income for each of the quarters ended
June 30, 2003 and 2002 was $24.1 million and $13.9 million, respectively.
The $9.8 million (43%) increase in period-to-period segment earnings was
primarily attributable to the $20.2 million (59%) increase in revenues,
partially offset by higher depreciation and depletion expenses and by higher
taxes, other than income taxes. Similar to last quarter, the segment's increase
in revenues was mainly due to higher oil production volumes and higher realized
average hedged oil prices. Oil production at the SACROC unit in the Permian
Basin of West Texas averaged 19,600 barrels per day in the second quarter of
2003, a 63% increase in production over the same period last year. In addition,
the segment benefited from an approximate 8% increase in its realized weighted
average price of oil per barrel (from $22.38 per barrel in second quarter 2002
to $24.21 per barrel in second quarter 2003). The general increase in segment
revenues was partially offset by lower overall carbon dioxide delivery volumes.
Our second quarter 2003 carbon dioxide delivery volumes increased 28% compared
to second quarter 2002, but other owners at McElmo Dome reduced deliveries to
their customers, resulting in a total decrease of about 5% in the segment's
overall carbon dioxide pipeline delivery volumes. Reduced deliveries by other
owners at McElmo Dome affect our revenues based on our relative ownership
interest.
The overall increase in segment earnings was partially offset by higher
depreciation, depletion and amortization charges and by slightly higher taxes,
other than income taxes. Non-cash depletion and depreciation-related charges
were up $7.6 million (110%), mainly as a result of the higher production volumes
(as depletion expense is calculated on a per unit production basis) and
additional capital investments made since the end of the second quarter of 2002.
Taxes, other than income taxes, increased $1.4 million (83%), mainly due to
higher property and production taxes, the result of increases in invested
capital balances and oil production volumes.
50
Additionally, in May 2003, our Centerline Pipeline began operations. The
Centerline Pipeline consists of approximately 113 miles of 16-inch pipe located
in the Permian Basin between Denver City, Texas and Snyder, Texas. It has the
capacity to deliver 250 million cubic feet of carbon dioxide per day. The
project was completed three months ahead of schedule and under budget. The
pipeline primarily transports carbon dioxide to the SACROC oil field unit.
In the second quarter of 2003, our CO2 Pipelines segment reported $8.4 million
in equity earnings, net of amortization of excess costs. The amount is $0.4
million (5%) below the $8.8 million in equity earnings reported in the second
quarter of 2002. The overall decrease reflects lower earnings from the segment's
15% ownership interest in MKM Partners, L.P. and its 50% ownership interest in
Cortez Pipeline Company. MKM Partners, L.P. had lower overall earnings primarily
as a result of the disposition of its investment in the SACROC oil field unit,
effective June 1, 2003. We acquired MKM Partners' 12.75% ownership interest in
the SACROC unit for $23.3 million and the assumption of $1.9 million of
liabilities. Effective June 30, 2003, MKM Partners, L.P. was dissolved. Cortez
had lower earnings primarily due to lower carbon dioxide delivery volumes.
TERMINALS
Our Terminals segment, including both our bulk and liquids terminal
businesses, reported earnings of $49.6 million on revenues of $123.4 million in
the second quarter of 2003. In the second quarter of 2002, the segment earned
$43.5 million on revenues of $109.9 million. Costs and expenses for each of the
quarters ended June 30, 2003 and 2002 were $71.2 million and $64.7 million,
respectively. Operating income for each of the quarters ended June 30, 2003 and
2002 was $52.2 million and $45.2 million, respectively.
Excluding acquisitions, earnings increased $1.2 million in the second quarter
of 2003, compared to the second quarter of 2002. The increase was primarily due
to an increase in refined petroleum imports to the United States and to
expansion projects that have increased the leaseable capacity at some of our
largest liquids terminals. Our Houston terminal complex, located in Pasadena and
Galena Park, Texas along the Houston Ship Channel, along with our Carteret, New
Jersey terminal on the New York Harbor and our Argo terminal near Chicago all
reported strong second quarter results.
Expansion projects undertaken since the end of the second quarter of 2002,
including the work done at our Carteret and Perth Amboy, New Jersey terminals,
have increased our liquids terminals' leaseable capacity by 4%, contributing to
a higher utilization of storage room at our liquids terminal facilities. Second
quarter earnings from all liquids terminals owned during both years increased
$3.5 million (12%) in 2003 compared to 2002.
The quarter-to-quarter increase in segment earnings attributable to the
factors described above was partially offset by a $2.3 million (15%) decrease in
earnings from all bulk terminal operations owned during each year, primarily due
to lower revenues as a result of an almost 3% decrease in overall bulk transload
tonnage, most notably fertilizer and coal. The decrease in fertilizer revenues
was linked to the rise in natural gas prices since the end of the second quarter
of 2002. Higher natural gas prices led to higher ammonia and related phosphate
prices, thereby weakening demand for products. The decrease in coal revenues was
primarily related to a decrease in coal tonnage handled at our Cora terminal in
Cora, Illinois. As we anticipated and discussed in our Annual Report on Form
10-K for the year ended December 31, 2002, the terminal experienced a drop in
contract volumes handled for the Tennessee Valley Authority due to the fact that
the TVA has diverted some of its business to new competing coal terminals that
have come on-line since the end of the second quarter of 2002.
Key acquisitions of terminal businesses since the end of the second quarter of
2002 accounted for $4.9 million of the $6.1 million increase in segment
earnings.
These acquisitions included:
- the Owensboro Gateway Terminal, acquired effective September 1, 2002;
- the St. Gabriel Terminal, acquired effective September 1, 2002;
- the purchase of four floating cranes at our bulk terminal facility in Port
Sulphur, Louisiana in December 2002; and
51
- the bulk terminal businesses acquired from M.J. Rudolph Corporation,
effective January 1, 2003.
The above acquisitions reported revenues of $11.1 million and costs and
expenses of $6.2 million in the second quarter of 2003.
SEGMENT OPERATING STATISTICS
Operating statistics for the second quarter of 2003 and 2002 are as follows
(historical pro forma for acquired assets):
Three Months Ended
-----------------------------
June 30, 2003 June 30, 2002
------------- -------------
Products Pipelines
Gasoline (MMBbl)............................... 116.0 121.7
Diesel (MMBbl)................................. 41.1 39.0
Jet Fuel (MMBbl)............................... 27.0 28.9
------ ------
Total Refined Product Volumes (MMBbl).......... 184.1 189.6
Natural Gas Liquids (MMBbl).................... 8.4 8.7
------ ------
Total Delivery Volumes (MMBbl) (1)............. 192.5 198.3
Natural Gas Pipelines (2)
Transport Volumes (Bcf) ....................... 342.2 287.5
Sales Volumes (Bcf) (3)........................ 227.7 204.5
CO2 Pipelines
Delivery Volumes (Bcf) (4)..................... 104.6 109.5
SACROC Oil Production (MBbl/d) ................ 19.6 12.0
Realized Weighted Average Oil
Price per Bbl (5)............................ $ 24.21 $ 22.38
Terminals
Bulk Terminals
Transload Tonnage (MMtons) (6).............. 15.1 15.5
Liquids Terminals
Leaseable Capacity (MMBbl).................. 35.9 34.5
Liquids Utilization %....................... 96% 97%
Note: Historical pro forma for acquired assets.
(1) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
(2) Includes Kinder Morgan Interstate Gas Transmission, Texas Intrastate
group and Trailblazer pipeline volumes.
(3) First quarter 2002 includes sales volumes under prior management, which
may not be comparable. (4) Includes Cortez, Central Basin, Canyon Reef
Carriers and Centerline pipeline volumes. (5) Includes values realized
(net of hedges) on SACROC and Sharon Ridge Unit equity production, plus
the hedge gain/loss on our share of MKM Partners, L.P.'s interest in Yates
Field Unit production.
(6) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs; excludes operatorship of LAXT bulk terminal.
OTHER
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. Together, these
items totaled $81.2 million in the second quarter of 2003 and $76.3 million in
the second quarter of 2002.
Our general and administrative expenses totaled $34.2 million in the second
quarter of 2003 compared with $30.2 million in the second quarter of 2002. The
$4.0 million (13%) quarter-to-quarter increase in general and administrative
expenses was primarily due to higher legal expenses, employee benefit costs and
overall corporate and worker-related insurance expenses.
Total interest expense, net of interest income, was $44.9 million in the
second quarter of 2003 and $43.9 million in the second quarter of 2002. The
small $1.0 million (2%) increase in net interest charges was due to slightly
higher average borrowings during the second quarter of 2003 compared with the
same period last year.
52
Minority interest remained relatively flat in the second quarter of each
year, totaling $2.1 million in the second quarter of 2003 versus $2.2 million in
the second quarter of 2002. Higher overall Partnership net income in the second
quarter of 2003 was offset by lower minority interest in Trailblazer Pipeline
Company. In May 2002, we acquired the remaining 33 1/3% ownership interest in
Trailblazer that we did not already own, thereby eliminating the minority
interest relating to Trailblazer Pipeline Company.
SIX MONTHS ENDED JUNE 30, 2003 COMPARED WITH SIX MONTHS ENDED JUNE 30, 2002
For the six months ended June 30, 2003, our earnings before a change in
accounting principal was $336.0 million ($0.98 per diluted unit), a 17% increase
over our $286.0 million ($0.95 per diluted unit) in net income for the first six
months of 2002. Our earnings in 2003 benefited from a cumulative-effect
adjustment of $3.4 million related to a change in accounting for asset
retirement obligations pursuant to our adoption of Statement of Financial
Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" on
January 1, 2003. After the cumulative-effect adjustment, our net income for the
six-month period ended June 30, 2003 totaled $339.4 million ($1.00 per diluted
unit). For more information on this cumulative-effect adjustment from a change
in accounting principle, see Note 4 to our Consolidated Financial Statements,
included elsewhere in this report.
We reported total revenues of $3,453.3 million for the first six months of
2003, compared with $1,894.0 million in revenues for the first six months of
2002. Our costs and expenses were $3,058.6 million for the six-month period
ended June 30, 2003, and $1,555.8 million for the six-month period ended June
30, 2002. Operating income for the six months ended June 30, 2003, was $394.7
million, a 17% increase over the $338.2 million in operating income for the six
months ended June 30, 2002. Equity earnings from investments, less amortization
of excess costs, were $44.1 million in the first six months of 2003 versus $44.8
million in the same period last year.
Our operating results for the first half of 2003 demonstrated balanced
growth across our business portfolio as all four of our business segments
reported increases in earnings, operating income and revenues when compared to
the first half of 2002. The increases were driven primarily by internal growth,
mainly resulting from our ongoing expansion and capital improvement projects
within our Natural Gas Pipelines and CO2 Pipelines business segments, but also
by the acquisitions of pipeline and terminal businesses that we have made since
the beginning of 2002. The largest of these was the January 31, 2002 purchase of
Kinder Morgan Tejas. Kinder Morgan Tejas' operations include a 3,400-mile Texas
intrastate natural gas pipeline system that has good access to natural gas
supply basins and provides a strategic, complementary fit with our other natural
gas pipeline assets in Texas, particularly Kinder Morgan Texas Pipeline.
PRODUCTS PIPELINES
Our Products Pipelines segment reported earnings of $184.3 million on
revenues of $289.7 million in the first six months of 2003. In the same period
of 2002, the segment reported earnings of $176.4 million on revenues of $280.5
million. Operating income for each of the six-month periods ended June 30, 2003
and 2002 was $174.8 million and $166.6 million, respectively.
The $7.9 million (4%) increase in period-to-period segment earnings resulted
from internal growth, primarily driven by record earnings from our North System
liquids pipeline and higher returns from our Pacific operations' terminaling
services and our CALNEV pipeline's products delivery services. The $9.2 million
(3%) period-to-period increase in overall segment revenues reflects a $3.9
million (3%) increase from our Pacific operations, a $3.7 million (22%) increase
from our North System and a $2.1 million (9%) increase from our CALNEV pipeline
operations. For both our Pacific and CALNEV pipelines, mainline delivery volumes
were relatively flat in the first half of 2003 compared to last year; however,
we benefited from higher terminal revenues, as a result of increased ethanol
blending operations, and higher average tariff rates. The increase in revenues
from our North System was primarily due to an over 5% increase in throughput
volume and higher average tariff rates in the first half of 2003 compared to the
same period last year. The increase in throughput volumes was due to cold
weather in the Midwest during the first quarter of 2003 and to strong propane
demand. The segment's overall increase in revenues was partially offset by a
$3.2 million (19%) decrease in revenues from the Cochin pipeline system. The
decrease was due to the lower delivery volumes in the second quarter of 2003,
referred to above in our quarterly discussion and analysis.
53
The segment's costs and expenses were essentially unchanged in the first
half of 2003, compared to the first half of last year. Costs and expenses
totaled $114.9 million in the first six months of 2003 and $113.9 million in the
first six months of 2002. The $1.0 million (1%) increase in the segment's costs
and expenses was primarily due to higher depreciation charges related to capital
investments made since the end of the second quarter of 2002.
Earnings from our Products Pipelines' equity investments, net of
amortization of excess costs, were $14.0 million in the first half of 2003
versus $15.5 million in the first half of 2002. The $1.5 million (10%) decrease
in equity earnings related to lower returns from our investment in Plantation
Pipe Line Company, as described above in our quarterly discussion and analysis.
NATURAL GAS PIPELINES
Our Natural Gas Pipelines segment reported earnings of $154.1 million on
revenues of $2,822.1 million in the first six months of 2003. In the first six
months of 2002, the segment reported earnings of $128.9 million on revenues of
$1,338.5 million. The segment's costs and expenses were $2,680.0 million in the
first half of 2003 and $1,221.6 million in the first half of 2002. Operating
income for each of the six months ended June 30, 2003 and 2002 was $142.1
million and $116.9 million, respectively.
The segment's $25.2 million (20%) increase in earnings in the first half of
2003 compared to the first half of 2002 was primarily attributable to internal
growth from our Texas intrastate natural gas pipeline group and our Trailblazer
Pipeline Company. Our Texas intrastate pipeline group accounted for
approximately $12.9 million of the total period-to-period increase in segment
earnings. Our North Texas and Mier-Monterrey pipeline systems, both placed in
service since the end of the second quarter of 2002 and included as part of our
Texas intrastate natural gas pipeline group, reported earnings of $4.9 million
on revenues of $7.0 million in the first six months of 2003. We also received a
full six-month benefit from the expansion of our Trailblazer pipeline system.
Our expansion project was completed in May 2002, and in the first half of 2003,
Trailblazer reported a $7.6 million (64%) increase in period-to-period earnings,
the result of a 29% increase in transport volumes and higher average tariff
rates over the same six-month period last year.
Overall, the segment's significant increases in period-to-period revenues
and costs and expenses related primarily to higher natural gas prices since the
end of the second quarter of 2002, our January 31, 2002 acquisition and
integration of Kinder Morgan Tejas, and the inclusion of our North Texas and
Mier-Monterrey pipeline systems into our Texas intrastate natural gas pipeline
group. The acquisition, construction and subsequent integration of all of our
natural gas pipeline assets in and around the State of Texas has produced a very
strategic intrastate pipeline business combination. Both Kinder Morgan Tejas and
KMTP purchase and sell significant volumes of natural gas, which is transported
through their pipeline systems. Our objective is to match purchases and sales in
the aggregate, thus locking-in the equivalent of a transportation fee. The
purchase and sale activity results in considerably higher revenues and operating
expenses compared to the interstate natural gas pipeline systems of Kinder
Morgan Interstate Gas Transmission and Trailblazer Pipeline Company. Both KMIGT
and Trailblazer charge a transportation fee for gas transmission service but
neither system has significant gas purchases and resales.
The overall increase in segment earnings attributable to the factors
discussed above was partially offset by higher depreciation and amortization
charges. Depreciation expenses totaled $26.2 million, up 10% from the $23.9
million reported in the first half of 2002. The increase was due to the
additional capital investments we have made since the end of the second quarter
of 2002 and an additional month of depreciation for Kinder Morgan Tejas.
Earnings from our Natural Gas Pipelines' equity investments, net of
amortization of excess costs, were relatively level across both years. The
segment earned $12.2 million from its equity investments during the first six
months of 2003, compared to $12.0 million during the first six months of 2002.
The $0.2 million (2%) increase was primarily due to higher earnings from the
segment's 25% ownership interest in Thunder Creek Gas Services, LLC.
CO2 PIPELINES
Our CO2 Pipelines segment reported earnings of $62.1 million on revenues of
$103.1 million in the first six months of 2003. In the same 2002 period, the
segment reported earnings of $44.0 million on revenues of $66.5
54
million. Costs and expenses totaled $58.9 million in the first six-month period
of 2003 versus $40.0 million in the same period of 2002. Operating income for
each of the six months ended June 30, 2003 and 2002 was $44.2 million and $26.5
million, respectively.
The $18.1 million (41%) increase in period-to-period segment earnings was
primarily attributable to the $36.6 million (55%) increase in revenues,
partially offset by higher depreciation, depletion and operating expenses. The
increase in revenues was driven by both higher oil production volumes and higher
average hedged oil prices. The segment benefited from a 56% increase in oil
production volumes from the SACROC unit and from a 9% increase in the average
hedged price of oil per barrel since June 30, 2002. The increase in segment
revenues was partially offset by lower carbon dioxide delivery volumes,
primarily due to reduced deliveries from the McElmo Dome carbon dioxide unit.
The $18.9 million (47%) increase in the segment's costs and expenses
primarily related to higher depreciation, depletion and amortization charges and
higher fuel and power expenses. Non-cash depletion and depreciation-related
charges were up $12.2 million (88%), mainly as a result of the higher production
volumes and additional capital investments made since the end of the second
quarter of 2002. Fuel and power expenses were up $2.7 million (33%), primarily
as a result of the higher production volumes associated with our increased
ownership interest in the SACROC unit.
During the first half of 2003, our CO2 Pipelines segment reported $17.9
million in equity earnings, net of amortization of excess costs. This compares
to $17.4 million during the same period of 2002. The $0.5 million (3%) increase
was due to higher returns from the segment's 15% equity interest in MKM
Partners, L.P., partly offset by lower returns from its equity investment in
Cortez Pipeline Company. In addition, effective June 1, 2003, we acquired MKM
Partners, L.P.'s 12.75% ownership interest in the SACROC unit for $23.3 million
and the assumption of $1.9 million of liabilities, thereby lowering equity
earnings from MKM Partners in June 2003.
TERMINALS
Our Terminals segment reported earnings of $98.5 million on revenues of
$238.4 million in the first six months of 2003. In the same period last year,
the segment earned $84.4 million on revenues of $208.5 million. Costs and
expenses for each of the six months ended June 30, 2003 and 2002 were $136.0
million and $120.6 million, respectively. Operating income for each of the six
months ended June 30, 2003 and 2002 was $102.4 million and $87.9 million,
respectively.
The increases in segment operating results were mainly driven by the
terminal acquisitions we have made since the beginning of 2002 and by internal
growth at certain existing terminals. Our terminal acquisitions include the
businesses described above in our quarterly discussion and analysis as well as
the purchase of our Milwaukee bagging operations, effective May 1, 2002. These
terminal acquisitions accounted for $9.0 million of the $14.1 million
period-to-period increase in segment earnings. Combined, the acquired terminal
operations reported earnings of $9.3 million, revenues of $21.5 million and
costs and expenses of $12.2 million for the first six months of 2003. We earned
$0.3 million on revenues of $0.6 million less costs and expenses of $0.3 million
from our ownership of the Milwaukee Bagging Operations during the two months
ended June 30, 2002.
Work completed on expansion projects since the end of the second quarter of
2002 has increased the leaseable capacity of our liquids terminals operations.
We have utilized this extra capacity by transporting and storing a higher volume
of liquid products, demonstrating our country's continued strong demand for
petroleum liquid products. As a result, earnings from all liquids terminals
owned during the first half of each year increased $7.8 million (14%) in 2003
compared to last year.
Partly offsetting the segment's overall period-to-period earnings increase
attributable to the factors described above was a drop of $2.7 million (9%) in
earnings from all bulk terminal facilities owned during the first half of each
year. The decrease was mainly due to lower cement, fertilizer and coal revenues,
all primarily as a result of decreased volumes. In total, our Terminals segment
reported a 2% decrease in bulk transload tonnage in the first half of 2003,
compared to the first half of last year. The decrease was primarily due to the
same factors referred to above in our quarterly discussion and analysis.
55
The overall increase in segment earnings was also partially offset by higher
depreciation and amortization charges and higher taxes, other than income taxes.
Depreciation expenses totaled $18.0 million for the first six months of 2003
versus $14.1 million for the first six months of 2002. The $3.9 million (28%)
increase was due to the additional capital investments we have made since the
end of the second quarter of 2002.
SEGMENT OPERATING STATISTICS
Operating statistics for the first six months of 2003 and 2002 are as follows
(historical pro forma for acquired assets):
Six Months Ended
-------------------------------
June 30, 2003 June 30, 2002
------------- -------------
Products Pipelines
Gasoline (MMBbl)............................ 220.0 229.9
Diesel (MMBbl).............................. 77.1 74.5
Jet Fuel (MMBbl)............................ 53.6 56.2
----- -----
Total Refined Product Volumes (MMBbl)....... 350.7 360.6
Natural Gas Liquids (MMBbl)................. 21.2 19.8
----- -----
Total Delivery Volumes (MMBbl) (1).......... 371.9 380.4
Natural Gas Pipelines (2)
Transport Volumes (Bcf) .................... 602.6 529.9
Sales Volumes (Bcf) (3)..................... 454.3 450.8
CO2 Pipeline
Delivery Volumes (Bcf) (4).................. 206.9 222.6
SACROC Oil Production (MBbl/d) ............. 18.3 11.7
Realized Weighted Average Oil
Price per Bbl (5)......................... $ 24.50 $ 22.41
Terminals
Bulk Terminals
Transload Tonnage (MMtons) (6)............ 29.1 29.7
Liquids Terminals
Leaseable Capacity (MMBbl)................ 35.9 34.5
Liquids Utilization %..................... 96% 97%
Note: Historical pro forma for acquired assets.
(1) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
(2) Includes Kinder Morgan Interstate Gas Transmission, Texas Intrastate group
and Trailblazer pipeline volumes.
(3) First quarter 2002 includes sales volumes under prior management, which
may not be comparable.
(4) Includes Cortez, Central Basin, Canyon Reef Carriers and Centerline
pipeline volumes.
(5) Includes values realized (net of hedges) on SACROC and Sharon Ridge Unit
equity production, plus the hedge gain/loss on our share of MKM Partners,
L.P.'s interest in Yates Field Unit production.
(6) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs; excludes operatorship of LAXT bulk terminal.
OTHER
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. For the first six
months of 2003, these items were partially offset by a $3.5 million
cumulative-effect adjustment related to our change in accounting for asset
retirement obligations. Together, these items (including the cumulative-effect
adjustment) totaled $159.5 million in the first half of 2003 and $147.7 million
in the first half of 2002.
Our general and administrative expenses totaled $68.8 million in the first six
months of 2003 compared with $59.7 million in the same period last year. The
$9.1 million (15%) year-over-year increase in general and administrative
expenses primarily related to timing differences in the accrual of general
services, including legal fees, higher employee benefit costs, and higher labor
and payroll tax expenses.
Our total interest expense, net of interest income, was $89.8 million in the
first half of 2003 versus $82.9 million in the same year-ago period. The $6.9
million (8%) increase in net interest charges was due to higher average
56
borrowings during the first half of 2003, partially offset by slightly lower
average interest rates in the first six months of 2003 compared with the same
period last year.
Minority interest totaled $4.3 million in the first six months of 2003,
compared to $5.0 million in the first six months of 2002. The $0.7 million (14%)
decrease resulted primarily from our May 2002 acquisition of the remaining 33
1/3% ownership interest in Trailblazer Pipeline Company that we did not already
own, thereby eliminating the minority interest relating to Trailblazer.
FINANCIAL CONDITION
The following table illustrates the sources of our invested capital. In
addition to our results of operations, these balances are affected by our
financing activities as discussed below (dollars in thousands):
June 30, 2003 Dec. 31, 2002
------------- -------------
Long-term debt, excluding market value of interest rate swaps...... $ 3,787,428 $ 3,659,533
Minority interest.................................................. 43,165 42,033
Partners' capital.................................................. 3,586,391 3,415,929
------------- -------------
Total capitalization............................................ 7,416,984 7,117,495
Short-term debt, less cash and cash equivalents.................... (44,915) (41,088)
------------- -------------
Total invested capital.......................................... $ 7,372,069 $ 7,076,407
============= =============
Capitalization:
- --------------
Long-term debt, excluding market value of interest rate swaps.. 51.1% 51.4%
Minority interest.............................................. 0.6% 0.6%
Partners' capital.............................................. 48.3% 48.0%
------ ------
100.0% 100.0%
====== ======
Invested Capital:
- ----------------
Total debt, less cash and cash equivalents and excluding market
value of interest rate swaps.............................. 50.8% 51.1%
Partners' capital and minority interest........................ 49.2% 48.9%
------ ------
100.0% 100.0%
====== ======
Our primary cash requirements, in addition to normal operating expenses, are
debt service, sustaining capital expenditures, expansion capital expenditures
and quarterly distributions to our common unitholders, Class B unitholders and
general partner. In addition to utilizing cash generated from operations, we
could meet our cash requirements (other than distributions to our common
unitholders, Class B unitholders and general partner) through borrowings under
our credit facilities, issuing short-term commercial paper, long-term notes or
additional common units or issuing additional i-units to KMR. In general, we
expect to fund:
- cash distributions and sustaining capital expenditures with existing cash
and cash flows from operating activities;
- expansion capital expenditures and working capital deficits with cash
retained as a result of paying quarterly distributions on i-units in
additional i-units, additional borrowings, the issuance of additional common
units or the issuance of additional i-units to KMR;
- interest payments from cash flows from operating activities; and
- debt principal payments with additional borrowings as such debt principal
payments become due or by the issuance of additional common units or the
issuance of additional i-units to KMR.
As a publicly traded limited partnership, our common units are attractive
primarily to individual investors. Individual investors represent a small
segment of the total equity capital market. We believe institutional investors
prefer shares of KMR over our common units due to tax and other regulatory
considerations. Thus, KMR makes
57
purchases of i-units issued by us with the proceeds from the sale of KMR shares
to institutional investors.
As of June 30, 2003, our current commitments for sustaining capital
expenditures were approximately $54.7 million. This amount has been committed
primarily for the purchase of plant and equipment and is based on the payments
we expect to make for our 2003 sustaining capital expenditure plan. All of our
capital expenditures, with the exception of sustaining capital expenditures, are
discretionary.
Some of our customers are experiencing severe financial problems that have had
a significant impact on their creditworthiness. We are working to implement, to
the extent allowable under applicable contracts, tariffs and regulations,
prepayments and other security requirements, such as letters of credit, to
enhance our credit position relating to amounts owed from these customers. We
cannot provide assurance that one or more of our financially distressed
customers will not default on their obligations to us or that such a default or
defaults will not have a material adverse effect on our business, financial
position, future results of operations or future cash flows.
OPERATING ACTIVITIES
Net cash provided by operating activities was $336.1 million for the six
months ended June 30, 2003, versus $323.6 million in the comparable period of
2002. The period-to-period increase of $12.5 million (4%) in cash flow from
operations was primarily driven by a $69.9 million increase in cash earnings
from across our business portfolio. We also benefited from a $19.9 million
increase in funds related to changes in non-current assets and liabilities and a
$6.5 million increase in funds related to higher distributions received from our
equity investments. The increase from non-current items was primarily related to
higher spending on environmental and rate case litigation matters during the
first half of 2002. The increase in equity investment distributions related to
higher distributions from our 15% equity interest in MKM Partners, L.P. and from
our 49% equity interest in the Red Cedar Gathering Company.
The overall increase in cash provided by operating activities attributable to
the factors discussed above was partially offset by a $44.5 million payment made
in April 2003 under order from the Federal Energy Regulatory Commission, and by
a $39.3 million decrease in funds relative to changes in working capital items.
The reparation and refund payment was mandated by the FERC as part of an East
Line settlement reached in 1999 between shippers and our Pacific operations
pursuant to rates charged by our Pacific operations on the interstate portion of
their products pipelines. The decrease in funds generated by working capital was
mainly due to higher settlements of related party payables during the first half
of 2003, primarily associated with reimbursements to KMI for general and
administrative services and for costs related to the construction of our
Mier-Monterrey natural gas pipeline. For more information on our Pacific
operations' regulatory proceedings, see Note 3 to the Consolidated Financial
Statements included elsewhere in this report.
INVESTING ACTIVITIES
Net cash used in investing activities was $310.0 million for the six month
period ended June 30, 2003, compared to $1,008.6 million in the comparable 2002
period. The $698.6 million (69%) decrease in cash used in investing activities
was primarily attributable to higher expenditures made for strategic
acquisitions in the first half of 2002. For the six months ended June 30, 2002,
our acquisition outlays totaled $816.2 million, including $682.7 million for
Kinder Morgan Tejas. For the six months ended June 30, 2003, our acquisition
payments totaled $33.7 million, including $23.3 million used to acquire an
additional 12.75% ownership interest in the SACROC oil field unit in West Texas.
On June 20, 2003, we signed an agreement with subsidiaries of Marathon Oil
Corporation to dissolve MKM Partners, L.P., a joint venture we formed on January
1, 2001 with subsidiaries of Marathon Oil Company. The joint venture assets
consisted of a 12.75% interest in the SACROC oil field unit and a 49.9% interest
in the Yates Field unit, both of which are in the Permian Basin of West Texas.
The joint venture was owned 85% by subsidiaries of Marathon Oil Company and 15%
by Kinder Morgan CO2 Company, L.P. The dissolution was effective on June 30,
2003. Effective June 1, 2003, we acquired the MKM joint venture's 12.75%
ownership interest in the SACROC unit for $23.3 million and the assumption of
$1.9 million of liabilities. This transaction increased our ownership interest
in SACROC to approximately 97%. For more information on this acquisition, see
Note 2 to the Consolidated Financial Statements included elsewhere in this
report.
58
Offsetting the overall period-to-period decrease in funds used in investing
activities was an $86.1 million increase in funds used for capital expenditures.
Including expansion and maintenance projects, our capital expenditures were
$273.4 million in the first six months of 2003 versus $187.3 million in the same
year-ago period. The increase was mainly due to higher capital investment in our
CO2 Pipelines and Products Pipelines business segments. We continue to expand
and grow our existing businesses and have current projects in place that will
significantly add storage and throughput capacity to our carbon dioxide flooding
and terminaling operations. Our sustaining capital expenditures were $40.1
million for the first six months of 2003 compared to $30.3 million for the first
six months of 2002.
FINANCING ACTIVITIES
Net cash used in financing activities amounted to $22.3 million for the six
months ended June 30, 2003. In the same period last year, our financing
activities provided $654.2 million. The $676.5 million decrease from the
comparable 2002 period was mainly the result of an $800.6 million decrease in
cash flows from overall debt financing activities. The period-to-period decrease
reflects significantly higher pay-downs on our outstanding commercial paper
borrowings and lower debt issuances during the first six months of 2003 as
compared to the same year-ago period.
Net borrowings under our commercial paper program were higher during the first
half of 2002 compared to the first half of 2003, primarily due to higher
acquisition expenditures in 2002. Furthermore, in June 2003, we issued in a
public offering, an additional 4,600,000 of our common units, including 600,000
units upon exercise by the underwriters of an over-allotment option, at a price
of $39.35 per share, less commissions and underwriting expenses. After
commissions and underwriting expenses, we received net proceeds of $173.3
million for the issuance of these common units. We used the proceeds to reduce
the borrowings under our commercial paper program. In March 2002, we completed a
public offering of $750 million in principal amount of senior notes, resulting
in a net cash inflow of approximately $740.8 million net of discounts and
issuing costs. The increase in debt from this senior note offering was partially
offset by the payment of our maturing $200 million in principal amount of
Floating Rate senior notes in March 2002.
The overall decrease in funds provided by our financing activities also
resulted from a $49.9 million increase in distributions to our partners.
Distribution to all partners increased to $326.3 million in the first half of
2003 compared to $276.4 million in the same year-earlier period. The increase in
distributions was due to:
- an increase in the per unit cash distributions paid;
- an increase in the number of units outstanding; and
- an increase in the general partner incentive distributions, which resulted
from both increased cash distributions per unit and an increase in the
number of common units and i-units outstanding.
On May 15, 2003, we paid a quarterly distribution of $0.64 per unit for the
first quarter of 2003, 8% greater than the $0.59 per unit distribution paid for
the first quarter of 2002. We paid this distribution in cash to our common
unitholders and to our class B unitholders. KMR, our sole i-unitholder, received
859,933 additional i-units based on the $0.64 cash distribution per common unit.
For each outstanding i-unit that KMR held, a fraction (0.018488) of an i-unit
was issued. The fraction was determined by dividing:
- $0.64, the cash amount distributed per common unit
by
- $34.617, the average of KMR's shares' closing market prices for 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.
On July 16, 2003, we declared a cash distribution for the quarterly period
ended June 30, 2003, of $0.65 per unit. The distribution will be paid on or
before August 14, 2003, to unitholders of record as of July 31, 2003. Our
59
common unitholders and Class B unitholders will receive cash. KMR, our sole
i-unitholder, will receive a distribution of 0.017138 i-units for each
outstanding i-unit held based on the $0.65 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.
PARTNERSHIP DISTRIBUTIONS
Our partnership agreement requires that we distribute 100% of available cash,
as defined in our partnership agreement, to our partners within 45 days
following the end of each calendar quarter in accordance with their respective
percentage interests. Available cash consists generally of all of our cash
receipts, including cash received by our operating partnerships, less cash
disbursements and net additions to reserves (including any reserves required
under debt instruments for future principal and interest payments) 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.
Typically, 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. For each outstanding i-unit, a
fraction of an i-unit will be issued. The fraction is calculated by dividing the
amount of cash being distributed per common unit by the average closing price of
KMR's shares over the ten consecutive trading days preceding the date on which
the shares begin to trade ex-dividend under the rules of the New York Stock
Exchange. 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 do not distribute cash to i-unit owners but retain
the cash for use in our business.
Available cash is initially distributed 98% to our limited partners and 2% to
our general partner. These distribution percentages are modified to provide for
incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
- first, 98% to the owners of all classes of units pro rata and 2% to our
general partner until the owners of all classes of units have received a
total of $0.15125 per unit in cash or equivalent i-units for such quarter;
- second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the owners of
all classes of units have received a total of $0.17875 per unit in cash or
equivalent i-units for such quarter;
- third, 75% of any available cash then remaining to the owners of all classes
of units pro rata and 25% to our general partner until the owners of all
classes of units have received a total of $0.23375 per unit in cash or
equivalent i-units for such quarter; and
- fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units in
cash and to owners of i-units in the equivalent number of i-units, and 50%
to our general partner.
Incentive distributions are generally defined as all cash distributions paid
to our general partner that are in excess of 2% of the aggregate value of cash
and i-units being distributed. The general partner's incentive distribution for
the distribution that we declared for the second quarter of 2003 was $79.6
million. The general partner's incentive distribution for the distribution that
we declared for the second quarter of 2002 was $64.4 million. The general
partner's incentive distribution that we paid during the second quarter of 2003
to our general partner (for the first
60
quarter of 2003) was $75.5 million. The general partner's incentive distribution
that we paid during the second quarter of 2002 to our general partner (for the
first quarter of 2002) was $61.0 million. All partnership distributions we
declare for the fourth quarter of each year are declared and paid in the first
quarter of the following year.
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," "will," or the negative of those terms or other
variations of them or comparable terminology. In particular, statements, express
or implied, concerning future actions, conditions or events, future operating
results or the ability to generate sales, income or cash flow or to make
distributions are forward-looking statements. Forward-looking statements are not
guarantees of performance. They involve risks, uncertainties and assumptions.
Future actions, conditions or events and future results of operations may differ
materially from those expressed in these forward-looking statements. Many of the
factors that will determine these results are beyond our ability to control or
predict. Specific factors which could cause actual results to differ from those
in the forward-looking statements include:
- price trends and overall demand for natural gas liquids, refined petroleum
products, oil, carbon dioxide, natural gas, coal and other bulk materials
and chemicals in the United States;
- economic activity, weather, alternative energy sources, conservation and
technological advances that may affect price trends and demand;
- changes in our tariff rates implemented by the Federal Energy Regulatory
Commission or the California Public Utilities Commission;
- our ability to integrate any acquired operations into our existing
operations;
- our ability to acquire new businesses and assets and to make expansions to
our facilities;
- difficulties or delays experienced by railroads, barges, trucks, ships or
pipelines in delivering products to our terminals or pipelines;
- our ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
- shut-downs or cutbacks at major refineries, petrochemical or chemical
plants, ports, utilities, military bases or other businesses that use or
supply our services;
- changes in laws or regulations, third party relations and approvals,
decisions of courts, regulators and governmental bodies may adversely affect
our business or our ability to compete;
- our ability to offer and sell equity securities and debt securities or
obtain debt financing in sufficient amounts to implement that portion of our
business plan that contemplates growth through acquisitions of operating
businesses and assets and expansions of our facilities;
- our indebtedness could make us vulnerable to general adverse economic and
industry conditions, limit our ability to borrow additional funds and/or
place us at competitive disadvantages compared to our competitors that have
less debt or have other adverse consequences;
- interruptions of electric power supply to our facilities due to natural
disasters, power shortages, strikes, riots, terrorism, war or other causes;
- acts of nature, sabotage, terrorism or other similar acts causing damage
greater than our insurance coverage limits;
- the condition of the capital markets and equity markets in the United
States;
61
- the political and economic stability of the oil producing nations of the
world;
- national, international, regional and local economic, competitive and
regulatory conditions and developments;
- the ability to achieve cost savings and revenue growth;
- rates of inflation;
- interest rates;
- the pace of deregulation of retail natural gas and electricity;
- the timing and extent of changes in commodity prices for oil, natural gas,
electricity and certain agricultural products; and
- the timing and success of business development efforts.
You should not put undue reliance on any forward-looking statements.
See Items 1 and 2 "Business and Properties - Risk Factors" of our annual
report filed on Form 10-K for the year ended December 31, 2002, 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 2002 Form 10-K report. The
risk factors could cause our actual results to differ materially from those
contained in any forward-looking statement. We disclaim any obligation to update
the above list or to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments. Our future
results also could be adversely impacted by unfavorable results of litigation
and the coming to fruition of contingencies referred to in Note 3 to our
consolidated financial statements included elsewhere in this report.
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, 2002,
in Item 7A of our 2002 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 the end of the quarter ended June 30, 2003, 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.
Based upon that evaluation, our Chief Executive Officer and Chief Financial
Officer concluded that the design and operation of our disclosure controls and
procedures were effective. There has been no change in our internal control over
financial reporting during the quarter ended June 30, 2003 that has materially
affected, or is reasonably likely to materially affect, our internal control
over financial reporting.
62
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
See Part I, Item 1, Note 3 to our consolidated financial statements entitled
"Litigation and Other Contingencies," which is incorporated herein by reference.
ITEM 2. CHANGES IN 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 AND REPORTS ON FORM 8-K.
(a) Exhibits
4.1 -- Certain instruments with respect to long-term debt of the Partnership
and its consolidated subsidiaries which relate to debt that does not
exceed 10% of the total assets of the Partnership and its consolidated
subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of
Regulation S-K, 17 C.F.R. ss.229.601.
11 -- Statement re: computation of per share earnings.
31.1 -- Section 13a-14(a)/15d-14(a) Certification of Chairman and Chief
Excecutive Officer.
31.2 -- Section 13a-14(a)/15d-14(a) Certification of Vice President, Treasurer
and Chief Financial Officer.
32.1 -- Section 1350 Certification of Chairman and Chief Excecutive Officer.
32.2 -- Section 1350 Certification of Vice President, Treasurer
and Chief Financial Officer.
========================
(b) Reports on Form 8-K
Current report dated April 1, 2003 on Form 8-K was furnished on April 1,
2003, pursuant to Item 9 of that form. We provided notice that we, along with
Kinder Morgan, Inc., a subsidiary of which serves as our general partner, and
Kinder Morgan Management, LLC, a subsidiary of our general partner that manages
and controls our business and affairs, intended to make presentations on April
1, 2003 at the 31st Annual Howard Weil Energy Conference to address company
strategy and philosophy, the fiscal year 2003 budget, and other business
information about us, Kinder Morgan, Inc. and Kinder Morgan Management, LLC.
Notice was also given that prior to the meeting, interested parties would be
able to view the materials presented at the meetings by visiting Kinder Morgan,
Inc.'s website at: http://www.kindermorgan.com/investor/presentations.
63
Current report dated April 16, 2003 on Form 8-K was furnished on April 23,
2003, pursuant to Items 7 and 9 of that form. In Item 9, we provided notice that
on April 16, 2003, we issued a press release regarding our financial results for
the quarter ended March 31, 2003 and held a webcast conference call discussing
those results. A copy of the earnings press release and an unedited transcript
of the webcast conference call, prepared by an outside vendor, were filed in
Item 7 as exhibits pursuant to Item 9. Notice was also given that interested
parties would be able to replay the webcast conference call by visiting Kinder
Morgan, Inc.'s website at: http://www.kindermorgan.com by clicking "Webcast
Conference Calls" and the "Audio Webcast" button. The webcast was archived on
the website under "Investors - KMP - Conference Call." We also provided
disclosure of how to reconcile segment earnings before depreciation, depletion
and amortization and distributable cash per unit to their closest GAAP financial
measures.
Current Report dated May 5, 2003 on Form 8-K was filed on May 6, 2003,
pursuant to Item 5 of that form. We reported that on May 2, 2003 we were
notified by the staff of the SEC that the staff is conducting an informal
investigation concerning our public disclosures regarding the allocation of
purchase price between assets and goodwill in connection with our acquisition of
the assets of Tejas Gas, LLC.
Current report dated May 23, 2003 on Form 8-K was filed on May 23, 2003,
pursuant to Item 7 of that form. We filed the Consolidated Balance Sheet at
December 31, 2002, of Kinder Morgan G.P., Inc., our general partner and a
wholly-owned subsidiary of Kinder Morgan, Inc. as an exhibit pursuant to Item 7
of that form.
Current report dated May 27, 2003 on Form 8-K was furnished on May 27, 2003,
pursuant to Item 9 of that form. We provided notice that we were actively
considering an underwritten public offering of between four and five million of
our common units representing limited partner interests.
Current report dated June 9, 2003 on Form 8-K was furnished on June 6, 2003,
pursuant to Item 9 of that form. We provided notice that we, along with Kinder
Morgan, Inc., a subsidiary of which serves as our general partner, and Kinder
Morgan Management, LLC, a subsidiary of our general partner that manages and
controls our business and affairs, intended to make presentations on June 9,
2003 at the Deutsche Bank Conference to address various strategic and financial
issues relating to the business plans and objectives of us, Kinder Morgan, Inc.
and Kinder Morgan Management, LLC. Notice was also given that prior to the
meeting, interested parties would be able to view the materials presented at the
meetings by visiting Kinder Morgan, Inc.'s website at:
http://www.kindermorgan.com/ investor/presentations.
Current report dated June 20, 2003 on Form 8-K was filed on June 20, 2003,
pursuant to Items 5 and 7 of that form. In Item 5, we provided notice that on
June 20, 2003, we issued a press release regarding our signed agreement with
subsidiaries of Marathon Oil Corporation to dissolve MKM Partners L.P., among
other agreements. A copy of the press release was filed in Item 7 as an exhibit.
Current report dated June 27, 2003 on Form 8-K was filed on June 27, 2003,
pursuant to Item 5 of that form. We provided notice that on June 24, 2003, a
non-binding, phase one initial decision was issued by the administrative law
judge hearing the Federal Energy Regulatory Commission case on the rates charged
by SFPP, L.P. on the interstate portion of its pipelines.
64
SIGNATURES
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 General Partner
By: KINDER MORGAN MANAGEMENT, LLC,
its Delegate
/s/ C. Park Shaper
------------------------------
C. Park Shaper
Vice President, Treasurer and Chief
Financial Officer of Kinder Morgan
Management, LLC, Delegate of Kinder Morgan
G.P., Inc. (principal financial officer
and principal accounting officer)
Date: August 8, 2003