Item 5. Other Events
Subject to completion dated May 17, 2004
The information in this prospectus supplement and the accompanying prospectus is
not complete and may be changed. This prospectus supplement and accompanying
prospectus are not an offer to sell these securities and are not soliciting an
offer to buy these securities in any state where the offer or sale is not
permitted.
Prospectus supplement
(To prospectus dated May 16, 2002)
[[Image Removed: GRAPHIC]]
$250,000,000
% Senior Notes due 2014
Interest payable and
Issue price: %
The notes will bear interest at the rate of % per year. Interest on the notes
will accrue from , 2004. Interest on the notes is
payable on and of each
year, beginning , 2004. The notes will mature
on , 2014.
We may redeem some or all of the notes at any time at a redemption price that
includes a make-whole premium, as described under the caption "Description of
notes-Optional redemption."
Investing in the notes involves risk. See "Risk factors" beginning on page S-16
of this prospectus supplement and on page 2 of the accompanying prospectus.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved these securities or determined if this
prospectus supplement or the accompanying prospectus is truthful or complete.
Any representation to the contrary is a criminal offense.
Price to Underwriting Proceeds to us
public discounts before expenses
Per note % % %
Total $ $ $
The notes will not be listed on any securities exchange. Currently, there is no
public market for the notes.
We expect to deliver the notes to investors in registered book-entry form only
through the facilities of The Depository Trust Company on or
about , 2004.
Joint Book-Running Managers
JPMorgan Lehman Brothers
Citigroup
Scotia Capital Markets
SunTrust Robinson
Humphrey
Summary
This summary highlights information contained elsewhere in this prospectus
supplement and the accompanying prospectus. You should read the entire
prospectus supplement, the accompanying prospectus, the documents incorporated
by reference and the other documents to which we refer for a more complete
understanding of this offering. You should read "Risk factors" beginning on page
S-16 of this prospectus supplement and page 2 of the accompanying prospectus for
more information about important factors that you should consider before buying
the notes in this offering. Unless we indicate otherwise, the information we
present in this prospectus supplement assumes that we will consummate the common
unit offering described below in "-Overview of our refinancing plan." As used in
this prospectus supplement and the accompanying prospectus, unless we indicate
otherwise, the terms "our," "we," "us" and similar terms refer to Magellan
Midstream Partners, L.P., together with our subsidiaries.
Magellan Midstream Partners, L.P.
We are a publicly traded Delaware limited partnership that owns and operates a
diversified portfolio of complementary energy assets. We are principally engaged
in the transportation, storage and distribution of refined petroleum products
and ammonia. For the year ended December 31, 2003, we had revenues of
$485.2 million, EBITDA of $161.6 million and net income of $88.2 million. For
the three months ended March 31, 2004, we had revenues of $133.1 million, EBITDA
of $44.1 million and net income of $25.8 million. For a reconciliation of EBITDA
to net income and a discussion of EBITDA as a performance measure, please see
"-Summary selected financial and operating data."
We completed the initial public offering of our common units in February 2001 at
an initial offering price of $21.50 per common unit. Since our initial public
offering, we have increased our quarterly cash distribution for 12 consecutive
quarters, resulting in an aggregate increase of approximately 62% from $0.525
per unit, or $2.10 per unit on an annualized basis, to $0.85 per unit, or $3.40
per unit on an annualized basis. Since February 2001, we have completed eight
acquisitions for an aggregate purchase price of approximately $1.1 billion, and
we intend to continue pursuing an asset acquisition strategy.
Our asset portfolio currently consists of:
º •
º a 6,700-mile petroleum products pipeline system, including 39
petroleum products terminals, serving the mid-continent region of the
United States;
º •
º five petroleum products terminal facilities located along the Gulf
Coast and near the New York harbor, referred to as "marine terminal
facilities";
º •
º 29 petroleum products terminals (three of which we partially own)
located principally in the southeastern United States, referred to as
"inland terminals"; and
º •
º an 1,100-mile ammonia pipeline system, including six ammonia
terminals, serving the mid-continent region of the United States.
Petroleum products pipeline system. Our petroleum products pipeline system is
a common carrier pipeline that provides transportation, storage and distribution
services for petroleum
S-1
products and liquefied petroleum gases, or LPGs, in 11 states from Oklahoma
through the Midwest to North Dakota, Minnesota and Illinois. Our petroleum
products pipeline system generates revenues from:
º •
º tariffs charged on volumes shipped;
º •
º leasing pipeline and storage tank capacity to shippers;
º •
º providing product and other services such as ethanol loading and
unloading, additive injection, laboratory testing and data services;
and
º •
º product sales.
For each of the year ended December 31, 2003 and the three months ended March
31, 2004, our petroleum products pipeline system generated approximately 80% of
our total revenues.
Our petroleum products pipeline system is the largest common carrier pipeline of
refined petroleum products and LPGs in the United States in terms of pipeline
miles. The products we transport on our pipeline system are largely
transportation fuels, and during 2003 volumes consisted of 58% gasoline, 33%
distillates (which includes diesel fuels and heating oil) and 9% LPGs and
aviation fuel.
Through direct refinery connections and interconnections with other pipelines,
our petroleum products pipeline system can access approximately 41% of the
refinery capacity in the United States and is well-positioned to adapt to shifts
in product supply or demand. According to statistics provided by the Energy
Information Administration, the demand for refined petroleum products in the
Midwest market area served by our petroleum products pipeline system, known as
Petroleum Administration for Defense District II, or PADD II, is expected to
grow at an average rate of approximately 1.7% per year over the next ten years.
The total production of refined petroleum products from refineries located in
PADD II is currently insufficient to meet the demand for refined petroleum
products in PADD II.
The excess PADD II demand has been and is expected to continue to be met largely
by imports of refined petroleum products via pipelines from Gulf Coast
refineries that are located in PADD III. Our petroleum products pipeline system
is well connected to Gulf Coast refineries through interconnections with the
Explorer, Shell, CITGO and Seaway/ConocoPhillips pipelines. These connections to
Gulf Coast refineries, together with our pipeline's extensive network throughout
PADD II and connections to PADD II refineries, should allow us to accommodate
not only demand growth, but also major supply shifts that may occur.
For the year ended December 31, 2003, our petroleum products pipeline system
generated $228.6 million of revenues from transportation tariffs on volumes
shipped. These transportation tariffs vary depending upon where the product
originates, where ultimate delivery occurs and any applicable discounts. All
interstate transportation rates and discounts are in published tariffs filed
with the Federal Energy Regulatory Commission, or FERC. Part of these tariffs
include charges for terminalling and storage of products at our pipeline
system's 39 terminals. In addition, we enter into supplemental agreements with
shippers that commonly result in volume commitments, term commitments or both by
shippers in exchange for reduced tariff rates or capital expansion commitments
on our part. During 2003, approximately 53% of the volumes were subject to these
supplemental agreements, which have terms ranging from one
S-2
to ten years. While many of these agreements do not represent guaranteed
volumes, they do reflect a significant level of shipper commitment to our
petroleum products pipeline system.
For the year ended December 31, 2003, our petroleum products pipeline system
generated $52.8 million of revenues from leasing pipeline and storage tank
capacity to shippers and from providing product and other services such as
ethanol unloading and loading, additive injection, laboratory testing and data
services to shippers. We perform product services such as ethanol unloading and
loading, additive injection, custom blending and laboratory testing under a mix
of "as needed" monthly and long-term agreements. In addition, we began operating
the Rio Grande pipeline system in 2003 and on January 1, 2004 began serving as a
subcontractor to an affiliate of The Williams Companies, Inc., or Williams, for
the interim operations of Longhorn Partners Pipeline, L.P. until its anticipated
start-up in the second quarter of 2004.
For the year ended December 31, 2003, we generated $112.3 million of product
sales revenues, substantially all of which was attributable to our petroleum
products pipeline system, resulting in $12.4 million of operating margin. For a
reconciliation of operating margin to operating profit and a discussion of
operating margin as a performance measure, please see "-Summary selected
financial and operating data" beginning on page S-12. We generate our product
sales revenues from the sale of products that we produce from fractionating
transmix, from overages on our pipeline system and from our petroleum products
management operation. These activities involve the purchase of raw materials,
such as butane, natural gasoline, and pipeline transmix, and as a result we hold
title to the products that are sold. However, we limit our commodity price risk
exposure related to these activities by utilizing hedging strategies, including
entering into forward sales transactions.
Petroleum products terminals. We own and operate five marine terminal
facilities, including four marine terminal facilities located along the Gulf
Coast and one marine terminal facility located in Connecticut near the New York
harbor. For each of the year ended December 31, 2003 and the three months ended
March 31, 2004, our marine terminal facilities and inland terminals generated
approximately 17% of our total revenues.
The marine terminal facilities have an aggregate storage capacity of
approximately 16.6 million barrels. Our marine terminal facilities primarily
receive petroleum products by ship and barge, short-haul pipeline connections
from neighboring refineries and common carrier pipelines. We distribute
petroleum products from our marine terminal facilities by all of those means as
well as by truck and railcar. Once the product has reached the marine terminal
facilities, we store the product for a period of time ranging from a few days to
several months. Products that we store include petroleum products, blendstocks,
heavy oils and feedstocks.
We have long-standing relationships with oil refiners, suppliers and traders at
our marine terminal facilities, and most of our customers have consistently
renewed their short-term contracts. For the year ended December 31, 2003,
approximately 93% of our marine terminal capacity was utilized and approximately
59% of our usable storage capacity was under long-term contracts with remaining
terms in excess of one year or that renew on an annual basis.
Our marine terminal facilities generate revenues primarily through providing
long-term or spot demand storage services and inventory management for a variety
of customers. We charge competitive rates for the services at our marine
terminal facilities that are not subject to
S-3
regulation. In most cases, we do not take title to the products that are stored
in or distributed from our facilities. Refiners and chemical companies will
typically use our marine terminal facilities because their facilities are
inadequate, either because of size constraints or the specialized handling
requirements of the stored product. We also provide storage services and
inventory management to various industrial end-users, marketers and traders that
require access to large storage capacity.
Our inland terminals are part of a distribution network of 29 refined petroleum
products terminals located throughout the southeastern United States used by
retail suppliers, wholesalers and marketers to receive gasoline and other
petroleum products from large, interstate pipelines and to transfer these
products to trucks, railcars or barges for delivery to their final destination.
Our inland terminal facilities typically consist of multiple storage tanks that
are connected to a third-party pipeline system and have a combined storage
capacity of 5.4 million barrels. We load and unload products through an
automated system that allows products to move directly from the common carrier
pipeline to our storage tanks and directly from the storage tanks to a truck or
railcar loading rack.
The majority of our inland terminals connect to the Colonial, Explorer,
Plantation or TEPPCO pipelines and some terminals have multiple pipeline
connections. In addition, our Dallas terminal connects to Dallas Love Field
airport. For the year ended December 31, 2003, gasoline represented
approximately 56% of the product volume distributed through our inland
terminals, with the remaining 44% consisting of distillates, including diesel
fuel, kerosene and heating oil.
We generate revenues by charging our customers a fee based on the amount of
product that we deliver through the inland terminals. In addition to throughput
fees, we generate revenues by charging our customers a fee for injecting
additives into gasoline, diesel and jet fuel, and for filtering jet fuel.
Ammonia pipeline system. We own an 1,100-mile ammonia pipeline system with a
maximum annual delivery capacity of approximately 900,000 tons that transports
and distributes ammonia from production facilities in Texas and Oklahoma to
terminals in the Midwest for ultimate distribution to end-users in Iowa, Kansas,
Minnesota, Missouri, Nebraska, Oklahoma and South Dakota. For each of the year
ended December 31, 2003 and the three months ended March 31, 2004, our ammonia
pipeline system generated approximately 3% of our total revenues.
The ammonia pipeline system originates at production facilities in Borger,
Texas, Verdigris, Oklahoma and Enid, Oklahoma and terminates in Mankato,
Minnesota. The ammonia we transport is primarily used as a nitrogen fertilizer.
It is also the primary feedstock for the production of upgraded nitrogen
fertilizers and chemicals. We transport ammonia to 13 delivery points along the
ammonia pipeline system, including six facilities that we own.
We generate revenues on our ammonia pipeline system from transportation tariffs
for the use of the pipeline capacity and throughput fees at our six ammonia
terminals. We do not produce or trade ammonia, and we do not take title to the
ammonia we transport. For the year ended December 31, 2003, we generated
approximately 93% of the revenues on our ammonia pipeline system through
transportation tariffs. In addition to transportation tariffs, we also earn
revenues by charging our customers for services at the six terminals we own,
including
S-4
unloading ammonia from our customers' trucks to inject it into the pipeline for
shipment and removing ammonia from the pipeline to load it into our customers'
trucks.
Business strategies
Our primary business strategies are to:
º •
º grow through strategic acquisitions and expansion projects that
increase per unit cash flow;
º •
º generate stable cash flows to make quarterly cash distributions; and
º •
º conduct safe and efficient operations.
Competitive strengths
We believe we are well-positioned to execute our business strategies
successfully because of the following competitive strengths:
º •
º our assets are strategically located in areas with high demand for our
services;
º •
º we have little direct commodity price exposure;
º •
º we have long-term relationships with many of our customers that
utilize our pipeline and terminal assets;
º •
º we have a strong financial position with additional borrowing capacity
and cash reserves available for making acquisitions and completing
expansion projects; and
º •
º our senior management has extensive industry experience.
Overview of our refinancing plan
This offering is one component of a refinancing plan that we are undertaking in
an effort to improve our credit profile and increase our financial flexibility
by removing all of the secured debt from our capital structure. We will fund
this refinancing plan through:
º •
º the issuance of $250.0 million of senior notes; and
º •
º our proposed offering of 1.0 million common units with expected net
proceeds of approximately $48.7 million (based upon the last reported
sales price of our common units on the New York Stock Exchange on
May 14, 2004 of $50.03 per common unit), including our general
partner's related capital contribution.
The combined net proceeds to us from our senior notes and proposed common unit
offerings are expected to be approximately $296.2 million (after deducting
underwriting discounts and estimated offering expenses), and we will use them
principally to:
º •
º repay $178.0 million of Series A notes of our Magellan Pipeline
Company, LLC subsidiary, plus the related prepayment premium; and
º •
º repay the $90.0 million outstanding principal balance of the term loan
under our existing credit facility.
S-5
Concurrently with the repayment of the Series A notes and the term loan, we
will:
º •
º replace our existing $85.0 million secured revolving credit facility
with a new five year, $125.0 million unsecured revolving credit
facility; and
º •
º amend the terms of the Series B notes of Magellan Pipeline Company to
release the collateral securing those notes.
Our senior notes offering is not conditioned upon the consummation of our
proposed common unit offering. If we do not consummate our proposed common unit
offering, we may elect to increase the principal amount of our senior notes
offering or borrow funds under our new revolving credit facility in order to
complete our refinancing plan. For more information about our refinancing plan,
please read "Use of proceeds," "Capitalization" and "Our refinancing plan" on
pages S-20, S-21 and S-22, respectively.
Although not part of our refinancing plan, Magellan Midstream Holdings, L.P.
proposes to sell 2.0 million common units together with our proposed offering of
1.0 million common units. We will not receive any proceeds from Magellan
Midstream Holdings' sale of common units.
Recent developments
Distribution increase. On April 22, 2004, the board of directors of our
general partner declared a quarterly cash distribution of $0.85 per common and
subordinated unit for the period of January 1 through March 31, 2004. This first
quarter distribution represents a 13% increase over the first quarter of 2003
distribution of $0.75 per unit and an approximate 62% increase since our initial
public offering in February 2001. We paid this cash distribution on May 14, 2004
to unitholders of record at the close of business on May 3, 2004.
Acquisition of 50% interest in Osage pipeline. On March 2, 2004, we acquired
a 50% ownership interest in Osage Pipe Line Company, LLC for $25.0 million from
National Cooperative Refinery Association, or NCRA. Osage Pipe Line Company,
which owns the Osage pipeline, is in the process of obtaining record title to
the Osage pipeline assets. The 135-mile Osage pipeline is regulated by FERC and
transports crude oil from Cushing, Oklahoma to El Dorado, Kansas and has
connections to the NCRA refinery in McPherson, Kansas and the Frontier refinery
in El Dorado, Kansas. The remaining 50% interest in Osage Pipe Line Company
continues to be owned by NCRA. We operate the Osage pipeline.
Conversion of subordinated units. On February 7, 2004, pursuant to our
partnership agreement, 1,419,923 of the 5,679,694 subordinated units held by
Magellan Midstream Holdings, L.P. converted into an equal number of common
units.
Acquisition of petroleum terminals. On January 29, 2004, we acquired
ownership interests in 14 inland terminals located in the southeastern United
States for $24.8 million and the assumption of $3.8 million of environmental
liabilities. We previously owned an approximate 79% interest in eight of these
terminals and acquired the remaining 21% ownership interest in these eight
terminals from Murphy Oil USA, Inc. In addition, we acquired sole ownership of
six terminals that were previously jointly owned by Murphy Oil USA, Inc. and
Colonial Pipeline Company.
S-6
Partnership structure and management
Our operations are conducted through, and our operating assets are owned by, our
subsidiaries. Upon the consummation of the common unit offering described above:
º •
º There will be 20,775,000 publicly held common units outstanding,
representing a 71.7% limited partner interest in us;
º •
º Magellan Midstream Holdings will own 3,355,541 common units and
4,259,771 subordinated units, representing an aggregate 26.3% limited
partner interest in us; and
º •
º Magellan GP, LLC, our general partner, will continue to own a 2.0%
general partner interest in us and all of the incentive distribution
rights.
In June 2003, Williams sold its membership interest in our general partner and
the common and subordinated units it owned to a new entity owned by affiliates
of Madison Dearborn Partners, LLC and Carlyle/Riverstone Global Energy and Power
Fund II, L.P. In September 2003, we changed our name to Magellan Midstream
Partners, L.P. from Williams Energy Partners L.P.
Our general partner has sole responsibility for conducting our business and
managing our operations. Our general partner does not receive any management fee
or other compensation in connection with its management of our business, but it
is reimbursed for direct and indirect expenses incurred on our behalf.
The chart on the following page depicts our organizational and ownership
structure after giving effect to our refinancing plan and the proposed offering
of 2.0 million common units by Magellan Midstream Holdings. The percentages
reflected in the organizational chart represent the approximate ownership
interests in us and our operating subsidiaries.
S-7
[[Image Removed: logo]]
S-8
The offering
The issuer Magellan Midstream Partners, L.P.
Securities offered by us $250.0 million principal amount of % Senior Notes due 2014.
The notes will be issued in denominations of $1,000 and
integral multiples of $1,000.
Interest payment dates and of each year,
beginning , 2004.
Maturity date , 2014.
Use of proceeds We will use the net proceeds from this offering, together with
the net proceeds from our proposed common unit offering and our
general partner's related capital contribution, to:
• repay all of the outstanding $178.0 million principal amount
of Series A senior notes issued by Magellan Pipeline Company
and pay the related prepayment premium of approximately $12.7
million;
• repay the $90.0 million outstanding principal balance of the
term loan under our existing credit facility;
• pay $1.9 million to Magellan Pipeline Company's Series B
noteholders to release the collateral held by them;
• replenish cash used to fund our recent acquisitions; and
• pay various fees and expenses in connection with our
refinancing plan.
Ratings We have obtained the following ratings on the notes: BBB by
Standard & Poor's Ratings Services and Ba1 by Moody's Investors
Service, Inc.
A rating reflects only the view of a rating agency and is not a
recommendation to buy, sell or hold the notes. Any rating can
be revised upward or downward or withdrawn at any time by a
rating agency if the rating agency decides that the
circumstances warrant a revision.
S-9
Ranking The notes will be our senior unsecured
obligations and will rank equally with
all of our other existing and future
senior indebtedness, including
indebtedness under our new revolving
credit facility.
We conduct substantially all of our
business through our subsidiaries. The
notes will be structurally subordinated
to all existing and future indebtedness
and other liabilities, including trade
payables, of any of our subsidiaries.
As of March 31, 2004, our subsidiaries
had approximately $480.0 million of
outstanding debt to unaffiliated third
parties and $22.8 million of
outstanding trade payables. We will use
a portion of the proceeds of this
offering to repay $178.0 million of
this debt. See "Description of notes -
Ranking."
Subsidiary guarantees We will cause any of our existing and
future subsidiaries that guarantees or
becomes a co-obligor in respect of any
of our funded debt to equally and
ratably guarantee the notes.
Certain covenants and events of default We will issue the notes under an
indenture with SunTrust Bank, as
trustee. The indenture does not limit
the amount of unsecured debt we may
incur. The indenture will contain
limitations on, among other things, our
ability to:
• incur indebtedness secured by certain
liens;
• engage in certain sale-leaseback
transactions; and
• consolidate, merge or dispose of all
or substantially all of our assets.
The indenture will provide for certain
events of default, including default on
certain other indebtedness.
Optional redemption We may redeem some or all of the notes
at any time at a redemption price,
which includes a make-whole premium,
plus accrued and unpaid interest, if
any, to the redemption date, as
described in "Description of notes"
beginning on page S-50 of this
prospectus supplement.
S-10
Risk factors See "Risk factors" beginning on page
S-16 and on page 2 of the accompanying
prospectus and "Management's discussion
and analysis of financial condition and
results of operations" beginning on
page S-24 of this prospectus supplement
for a discussion of factors you should
carefully consider before investing in
the notes.
S-11
Summary selected financial and operating data
We have derived the summary selected historical financial data as of and for the
years ended December 31, 2001, 2002 and 2003 from our audited consolidated
financial statements and related notes. We have derived the summary selected
historical financial data as of and for the three months ended March 31, 2003
and 2004 from our unaudited financial statements, which, in the opinion of our
management, include all adjustments necessary for a fair presentation of the
data. This financial data is an integral part of, and should be read in
conjunction with, the consolidated financial statements and notes thereto, which
are incorporated by reference and have been filed with the Securities and
Exchange Commission, or SEC. You should read these notes for additional
information regarding the acquisition of our general partner and certain of our
common, Class B common and subordinated units in June 2003. All other amounts
have been prepared from our financial records. Information concerning
significant trends in the financial condition and results of operations is
contained in "Management's discussion and analysis of financial condition and
results of operations" beginning on page S-24 of this prospectus supplement.
The non-generally accepted accounting principle financial measures of EBITDA and
operating margin are presented in the summary selected historical financial
data. We have presented these financial measures because we believe that
investors benefit from having access to the same financial measures utilized by
management.
EBITDA is defined as net income plus provision for income taxes, debt placement
fees amortization, interest expense (net of interest income) and depreciation
and amortization. EBITDA should not be considered an alternative to net income,
operating income, cash flow from operations or any other measure of financial
performance presented in accordance with generally accepted accounting
principles, or GAAP. EBITDA is not intended to represent cash flow. Because
EBITDA excludes some but not all items that affect net income and these measures
may vary among other companies, the EBITDA data presented may not be comparable
to similarly titled measures of other companies. Our management uses EBITDA as a
performance measure to assess the viability of projects and to determine overall
rates of return on alternative investment opportunities. We believe investors
can use EBITDA as a simplified means of measuring cash generated by operations
before maintenance capital and fluctuations in working capital. The
reconciliation of EBITDA to net income, which is its nearest comparable GAAP
measure, is included under the heading "Other data" presented on page S-14.
The components of operating margin are computed by using amounts that are
determined in accordance with GAAP. The reconciliation of operating margin to
operating profit, which is its nearest comparable GAAP financial measure, is
included under the heading "Income statement data" presented on the following
page. Operating profit includes expense items that management does not consider
when evaluating the core profitability of an operation such as depreciation and
amortization and general and administrative expenses. Our management believes
that operating margin is an important performance measure of the economic
success of our core operations and individual asset locations. This measure
forms the basis of our internal financial reporting and is used by management in
deciding how to allocate capital resources between segments.
S-12
-----------------------------------------------------------------------------------------------
Three months
Year ended December 31, ended March 31,
--------------------------------------- -------------------------
($ in thousands, except
per unit amounts) 2001 2002 2003 2003 2004
-----------------------------------------------------------------------------------------------
Income statement data:
Transportation and
terminals revenues $ 339,412 $ 363,740 $ 372,848 $ 87,714 $ 88,930
Product sales revenues 108,169 70,527 112,312 32,001 44,214
Affiliate construction
and management fee
revenues 1,018 210 - - -
-------------------------------------------------------------------
Total
revenues 448,599 434,477 485,160 119,715 133,144
Operating expenses
including environmental
expenses net of
indemnifications 160,880 155,146 166,883 33,970 37,790
Product purchases 95,268 63,982 99,907 27,818 38,499
Equity earnings(a) - - - - (120 )
-------------------------------------------------------------------
Operating
margin 192,451 215,349 218,370 57,927 56,975
Depreciation and
amortization 35,767 35,096 36,081 9,379 9,522
General and
administrative 47,365 43,182 56,846 10,438 12,887
-------------------------------------------------------------------
Operating
profit 109,319 137,071 125,443 38,110 34,566
Interest expense, net 12,113 21,758 34,536 8,505 8,069
Debt placement fees
amortization 253 9,950 2,830 547 682
Other income, net (431 ) (2,112 ) (92 ) - -
-------------------------------------------------------------------
Income
before
income
taxes 97,384 107,475 88,169 29,058 25,815
Provision for income
taxes(b) 29,512 8,322 - - -
-------------------------------------------------------------------
Net income $ 67,872 $ 99,153 $ 88,169 $ 29,058 $ 25,815
Basic net
income per
limited
partner
unit $ 1.87 $ 3.68 $ 3.32 $ 0.99 $ 0.87
-------------------------------------------------------------------
Diluted
net income
per
limited
partner
unit $ 1.87 $ 3.67 $ 3.31 $ 0.99 $ 0.87
-------------------------------------------------------------------
Balance sheet data:
Working capital (deficit) $ (2,211 ) $ 47,328 $ 77,438 $ (30,479 ) $ 32,160
Total assets 1,104,559 1,120,359 1,194,930 1,132,549 1,209,433
Total debt 139,500 570,000 570,000 570,000 570,000
Affiliate long-term note
payable(c) 138,172 - - - -
Partners' capital 589,682 451,757 498,149 464,040 497,778
Cash flow data:
Cash distributions
declared per unit(d) $ 2.02 $ 2.71 $ 3.17 $ 0.75 $ 0.85
(continued on following
page)
|
S-13
Other data:
Operating margin:
Petroleum products
pipeline system $ 143,711 $ 163,233 $ 162,494 $ 41,202 $ 40,326
Petroleum products
terminals 38,240 43,844 46,909 16,167 13,381
Ammonia pipeline system 10,500 8,272 8,094 558 2,613
Allocated partnership
depreciation costs - - 873 - 655
Operating margin $ 192,451 $ 215,349 $ 218,370 $ 57,927 $ 56,975
EBITDA:
Net income $ 67,872 $ 99,153 $ 88,169 $ 29,058 $ 25,815
Income taxes(b) 29,512 8,322 - - -
Debt placement fees
amortization 253 9,950 2,830 547 682
Interest expense, net 12,113 21,758 34,536 8,505 8,069
Depreciation and
amortization 35,767 35,096 36,081 9,379 9,522
EBITDA(e) $ 145,517 $ 174,279 $ 161,616 $ 47,489 $ 44,088
Operating statistics:
Petroleum products pipeline
system:
Transportation revenues
per barrel shipped (cents
per barrel) 90.8 94.9 96.4 98.0 97.2
Transportation barrels
shipped (millions) 236.1 234.6 237.6 52.7 52.8
Barrel miles (billions) 70.5 71.0 70.5 15.8 14.9
Petroleum products
terminals:
Marine terminal average
storage capacity utilized
per month (million
barrels) 15.7 16.2 15.2 15.8 15.5
Marine terminal throughput
(million barrels)(f) 11.5 20.5 22.2 5.3 5.5
Inland terminal throughput
(million barrels) 56.7 57.3 61.2 12.6 20.5
Ammonia pipeline system:
Volume shipped (thousand
tons) 763 712 614 47 219
Footnotes continue on following page.
º (a)
º Represents a partial quarter of equity earnings related to our 50%
ownership interest in Osage Pipe Line Company.
º (b)
º Prior to our initial public offering on February 9, 2001, our petroleum
products terminals and ammonia pipeline system operations were subject to
income taxes. Prior to our acquisition of Magellan Pipeline Company, which
primarily comprises our "petroleum products pipeline system," on April 11,
2002, Magellan Pipeline Company was also subject to income taxes. Because
we are a partnership, the petroleum products terminals and ammonia pipeline
system were no longer subject to income taxes after our initial public
offering, and Magellan Pipeline Company was no longer subject to income
taxes following our acquisition of it.
º (c)
º At the time of our initial public offering, the affiliate note payable
associated with the petroleum products terminals operations was contributed
to us as a capital contribution by an affiliate of Williams. At the closing
of our acquisition of Magellan Pipeline Company, its affiliate note payable
was contributed to us as a capital contribution by an affiliate of
Williams.
S-14
º (d)
º Represents cash distributions declared associated with each respective
calendar year. Cash distributions were declared and paid within 45 days
following the close of each quarter. Cash distributions declared for 2001
include a prorated distribution for the first quarter, which included the
period from February 10, 2001 through March 31, 2001.
º (e)
º Includes $5.9 million and $1.1 million of reimbursable general and
administrative expenses and $10.8 million and $0.6 million of transition
costs for the year ended December 31, 2003 and the three months ended
March 31, 2004, respectively.
º (f)
º For the year ended December 31, 2001, represents a full year of activity
for the New Haven facility (9.3 million barrels) and two months of activity
at the Gibson facility (2.2 million barrels), which was acquired in
October 2001.
S-15
Risk factors
An investment in our notes involves various material risks. You should carefully
read the risk factors set forth below, the risk factors included under the
caption "Risk factors" beginning on page 2 of the accompanying prospectus, and
those risks discussed in our Annual Report on Form 10-K for the year ended
December 31, 2003, which is incorporated by reference.
Restrictions related to the debt securities of Magellan Pipeline Company, LLC
may limit our financial flexibility.
Magellan Pipeline Company is subject to restrictions with respect to its debt
that may limit our flexibility in structuring or refinancing existing or future
debt. These restrictions include the following:
º •
º before October 7, 2007, we may repay Magellan Pipeline Company's
senior notes only by paying the related prepayment premium; and
º •
º in the note purchase agreement relating to the Magellan Pipeline
Company's senior notes, we agreed to maintain a leverage ratio that
limits our debt to EBITDA ratio, as defined in the note purchase
agreement, to 4.5 to 1.0, thereby limiting our ability to incur
additional debt.
Your ability to transfer the notes at a time or price you desire may be limited
by the absence of an active trading market, which may not develop.
The notes are a new issue of securities for which there is no established public
market. Although we have registered the notes under the Securities Act of 1933,
we do not intend to apply for listing of the notes on any securities exchange or
for quotation of the notes in any automated dealer quotation system. In
addition, although the underwriters have informed us that they intend to make a
market in the notes, as permitted by applicable laws and regulations, they are
not obliged to make a market in the notes, and they may discontinue their
market-making activities at any time without notice. An active market for the
notes may not develop or, if developed, may not continue. In the absence of an
active trading market, you may not be able to transfer the notes within the time
or at the price you desire.
The notes will be senior unsecured obligations. As such, the notes will be
effectively junior to any secured debt we may have, to the existing and future
debt and other liabilities of our subsidiaries that do not guarantee the notes
and to the existing and future secured debt of any subsidiaries that guarantee
the notes.
The notes will be our senior unsecured debt and will rank equally in right of
payment with all of our other existing and future unsubordinated debt. The notes
will be effectively junior to all our future secured debt, to the existing and
future debt of our subsidiaries that do not guarantee the notes and to the
secured debt of any subsidiaries that guarantee the notes. As of March 31, 2004,
our subsidiaries had $480.0 million of debt outstanding and $22.8 million of
outstanding trade payables, of which $178.0 will be repaid from the proceeds of
this offering. Initially, there will be no subsidiary guarantors, and there may
be none in the future. Since Magellan Pipeline Company will not guarantee the
notes offered by us in this prospectus supplement, the notes will be effectively
subordinated to all debt of Magellan Pipeline Company. In addition, the terms of
Magellan Pipeline Company's Series B senior notes due October 2007 would not
permit it to guarantee the notes in the future until it has repaid those senior
notes.
S-16
If we are involved in any dissolution, liquidation or reorganization, our
secured debt holders would be paid before you receive any amounts due under the
notes to the extent of the value of the assets securing their debt and creditors
of our subsidiaries may also be paid before you receive any amounts due under
the notes. In that event, you may not be able to recover any principal or
interest you are due under the notes.
A guarantee could be voided if the guarantor fraudulently transferred the
guarantee at the time it incurred the indebtedness, which could result in the
noteholders being able to rely only on us to satisfy claims.
Initially, there will be no subsidiary guarantors. In the future, however, if
our subsidiaries become guarantors or co-obligors of our funded debt, then these
subsidiaries will guarantee our payment obligations under the notes. Under U.S.
bankruptcy law and comparable provisions of state fraudulent transfer laws, a
guarantee can be voided, or claims under a guarantee may be subordinated to all
other debts of that guarantor if, among other things, the guarantor, at the time
it incurred the indebtedness evidenced by its guarantee:
º •
º intended to hinder, delay or defraud any present or future creditor or
received less than reasonably equivalent value or fair consideration
for the incurrence of the guarantee;
º •
º was insolvent or rendered insolvent by reason of such incurrence;
º •
º was engaged in a business or transaction for which the guarantor's
remaining assets constituted unreasonably small capital; or
º •
º intended to incur, or believed that it would incur, debts beyond its
ability to pay those debts as they mature.
In addition, any payment by that guarantor under a guarantee could be voided and
required to be returned to the guarantor or to a fund for the benefit of the
creditors of the guarantor.
We do not have the same flexibility as other types of organizations to
accumulate cash which may limit cash available to service the notes or to repay
them at maturity.
Our partnership agreement requires us to distribute, on a quarterly basis, 100%
of our available cash to our unitholders of record and our general partner,
subject to reasonable reserves as described below. As a result, we do not have
the same flexibility as corporations or other entities that do not pay dividends
or have complete flexibility regarding the amounts they will distribute to their
equity holders. Available cash is generally all of our cash receipts adjusted
for cash distributions and net changes to reserves. The timing and amount of our
distributions could significantly reduce the cash available to pay the
principal, premium (if any) and interest on the notes. The board of directors of
our general partner will determine the amount and timing of such distributions
and has broad discretion to establish and make additions to our reserves or the
reserves of our operating subsidiaries as it determines are necessary or
appropriate.
Although our payment obligations to our unitholders are subordinate to our
payment obligations to you, the value of our units will decrease in correlation
with decreases in the amount we distribute per unit. Accordingly, if we
experience a liquidity problem in the future, we may not be able to issue equity
to recapitalize.
S-17
Our general partner and its affiliates may have conflicts with our partnership.
The directors and officers of our general partner and its affiliates have duties
to manage the general partner in a manner that is beneficial to its members. At
the same time, the general partner has duties to manage us in a manner that is
beneficial to us. Therefore, the general partner's duties to us may conflict
with the duties of its officers and directors to its members.
Such conflicts may include, among others, the following:
º •
º decisions of our general partner regarding the amount and timing of
cash expenditures, borrowings and issuances of additional limited
partnership units or other securities can affect the amount of
incentive distribution payments we make to our general partner;
º •
º under our partnership agreement, we reimburse the general partner for
the costs of managing and operating us; and
º •
º under our partnership agreement, it is not a breach of our general
partner's fiduciary duties for affiliates of our general partner to
engage in activities that compete with us. For example, an affiliate
of our general partner also owns the general partner of another
publicly traded limited partnership that engages in businesses similar
to ours and may compete with us in the future to acquire assets that
we may also wish to acquire.
S-18
Use of proceeds
We expect the net proceeds of this offering to be approximately $247.5 million,
after deducting underwriting discounts and the estimated offering expenses. We
expect to receive net proceeds of approximately $48.7 million from our proposed
1.0 million common unit offering (based upon the last reported sales price of
our common units on the New York Stock Exchange on May 14, 2004 of $50.03 per
common unit) and our general partner's related capital contribution, after
deducting underwriting discounts and the estimated offering expenses payable by
us.
We intend to use the net proceeds from this offering, together with the net
proceeds from our proposed 1.0 million common unit offering and our general
partner's related capital contribution, to:
º •
º repay all of the outstanding $178.0 million principal amount of
Series A senior notes issued by Magellan Pipeline Company and pay the
related prepayment premium of approximately $12.7 million;
º •
º repay the $90.0 million outstanding principal balance of the term loan
under our existing credit facility;
º •
º pay $1.9 million to Magellan Pipeline Company's Series B noteholders
to release the collateral held by them;
º •
º replenish cash used to fund our recent acquisitions; and
º •
º pay various fees and expenses in connection with our refinancing plan.
As of March 31, 2004, the term loan under our existing credit facility had an
interest rate of 3.1% and matures on August 6, 2008. We used borrowings under
our term loan to refinance outstanding indebtedness under a former credit
facility. As of March 31, 2004, the Series A notes had an interest rate of 5.4%
and mature on October 7, 2007.
Our senior notes offering is not conditioned upon the consummation of our
proposed common unit offering. If we do not consummate our proposed common unit
offering, we may elect to increase the principal amount of our senior notes
offering or borrow funds under our new revolving credit facility in order to
complete our refinancing plan.
S-20
Capitalization
The following table sets forth our capitalization as of March 31, 2004:
º •
º on a historical basis;
º •
º as adjusted to give effect to the notes offered by us and the
application of the net proceeds therefrom in the manner described
under "Use of proceeds"; and
º •
º as further adjusted to give effect to our proposed 1.0 million common
unit offering, our general partners' related capital contribution and
the application of the net proceeds therefrom.
We expect the net proceeds from this offering to be approximately
$247.5 million, after deducting underwriting discounts and the estimated
offering expenses. We expect the net proceeds of our proposed 1.0 million common
unit offering and our general partner's related capital contribution to be
approximately $48.7 million (based upon the last reported sales price of our
common units on the New York Stock Exchange on May 14, 2004 of $50.03 per common
unit), after deducting underwriting discounts and the estimated offering
expenses payable by us. Please read "Use of proceeds."
As of March 31, 2004
As further
adjusted for
As adjusted our proposed
for this common unit
(unaudited) ($ in thousands) Historical offering(a)(b) offering
Cash and cash equivalents $ 43,891 $ 56,768 $ 56,768
Debt:
Credit facility $ 90,000 $ 48,685 $ -
Magellan Pipeline Company Series A
senior notes 178,000 - -
Magellan Pipeline Company Series B
senior notes due 2007 302,000 302,000 302,000
% Senior notes due 2014 - 250,000 250,000
Total debt $ 570,000 $ 600,685 $ 552,000
Total partners' capital 497,778 480,079 528,764
Total capitalization $ 1,067,778 $ 1,080,764 $ 1,080,764
º (a)
º This table assumes that we will use the net proceeds from this offering to
repay all of the outstanding $178.0 million principal amount of Series A
senior notes issued by Magellan Pipeline Company and repay approximately
$41.3 million of the $90.0 million outstanding principal balance under our
exisiting term loan. We will repay the remaining outstanding indebtedness
under our existing term loan using the net proceeds from our proposed
common unit offering and our general partner's related capital
contribution. If we do not consummate our proposed common unit offering, we
may elect to increase the principal amount of our senior notes offering or
borrow funds under our new revolving credit facility in order to complete
our refinancing plan.
º (b)
º Total partners' capital was reduced to reflect the prepayment of the
Series A senior notes and certain write-offs associated with prepaid debt
fees.
S-21
Our refinancing plan
This offering is one component of a refinancing plan that we are undertaking in
an effort to improve our credit profile and increase our financial flexibility
by removing all of the secured debt from our capital structure. We will fund
this refinancing plan through:
º •
º the issuance of $250.0 million of senior notes; and
º •
º our proposed offering of 1.0 million common units with expected net
proceeds of approximately $48.7 million, including our general
partner's related capital contribution.
The combined net proceeds to us from our senior notes and proposed common unit
offerings are expected to be approximately $296.2 million (after deducting
underwriting discounts and estimated offering expenses), and we will use them
principally to:
º •
º repay $178.0 million of Series A notes of our Magellan Pipeline
Company subsidiary, plus the related prepayment premium; and
º •
º repay the $90.0 million outstanding principal balance of the term loan
under our existing credit facility.
Concurrently with the repayment of the Series A notes and the term loan, we
will:
º •
º replace our existing $85.0 million secured revolving credit facility
with a new five year, $125.0 million unsecured revolving credit
facility; and
º •
º amend the terms of the Series B notes of Magellan Pipeline Company to
release the collateral securing those notes.
Our senior notes offering is not conditioned upon the consummation of our
proposed common unit offering. If we do not consummate our proposed common unit
offering, we may elect to increase the principal amount of our senior notes
offering or borrow funds under our new revolving credit facility in order to
complete our refinancing plan.
Our new revolving credit facility
As part of our refinancing plan, we expect to enter into a new five-year
$125.0 million revolving credit facility with a syndicate of banks. Up to
$50.0 million of the revolving credit facility will be available for the
issuance of letters of credit. Borrowings under the revolving credit facility
will be unsecured.
Borrowings under the revolving credit facility will bear interest, at our
election, at an annual rate equal to:
º •
º the highest of (1) the rate of interest publicly announced by JPMorgan
Chase Bank as its prime rate in effect at its principal office in New
York City; (2) the secondary market rate for three-month certificates
of deposit plus 1.0%; and (3) the federal funds effective rate plus
0.5%; or
º •
º LIBOR, as adjusted for statutory reserve requirements for eurocurrency
liabilities, plus a spread ranging from 0.625% to 1.500%, based upon
our credit rating.
The revolving credit facility will require that we maintain specified ratios of:
º •
º consolidated debt to EBITDA of no greater than 4.50 to 1.00; and
º •
º consolidated EBITDA to interest expense of at least 2.50 to 1.00.
S-22
In addition, the revolving credit facility will contain covenants that limit our
ability to, among other things:
º •
º incur additional indebtedness or modify our other debt instruments;
º •
º encumber our assets;
º •
º make debt or equity investments;
º •
º make loans or advances;
º •
º engage in certain transactions with affiliates;
º •
º engage in sale or leaseback transactions;
º •
º merge, consolidate, liquidate or dissolve;
º •
º sell or lease all or substantially all of our assets; and
º •
º change the nature of our business.
Magellan Pipeline Company senior notes
In connection with the long-term financing of our April 2002 acquisition of
Magellan Pipeline Company, we and our subsidiary, Magellan Pipeline Company,
entered into a note purchase agreement on October 1, 2002. Magellan Pipeline
Company issued two series of notes under the note purchase agreement consisting
of $178.0 million of Series A notes that bear interest at a floating rate based
on the six-month Eurodollar rate plus 4.25% and $302.0 million of Series B notes
that bear interest at a weighted average fixed rate of 7.77%.
The note purchase agreement requires that we and Magellan Pipeline Company
maintain specified ratios of:
º •
º consolidated debt to EBITDA of no greater than 4.50 to 1.00; and
º •
º consolidated EBITDA to interest expense of at least 2.50 to 1.00.
In addition, the note purchase agreement contains additional covenants that
limit Magellan Pipeline Company's ability to, among other things:
º •
º incur additional indebtedness;
º •
º encumber its assets;
º •
º make debt or equity investments;
º •
º make loans or advances;
º •
º engage in transactions with affiliates;
º •
º merge, consolidate, liquidate or dissolve;
º •
º sell or lease a material portion of its assets;
º •
º engage in sale and leaseback transactions; and
º •
º change the nature of its business.
In connection with our repaying the $178.0 million in outstanding Series A
senior notes from the proceeds of this offering and our proposed 1.0 million
common unit offering, we expect to amend the note purchase agreement to release
the collateral held by the Series B noteholders and change certain other
covenants, including decreasing the debt to EBITDA ratio for Magellan Pipeline
Company to 3.50 to 1.00.
S-23
Management's discussion and analysis
of financial condition and results of operations
Management's discussion and analysis of financial condition and results of
operations should be read in conjunction with the consolidated financial
statements and notes contained in our Annual Report on Form 10-K for the year
ended December 31, 2003 and our Quarterly Report on Form 10-Q for the three
months ended March 31, 2004, each of which is incorporated by reference into
this prospectus supplement. We are a publicly traded limited partnership formed
to own and operate a diversified portfolio of complementary energy assets. We
are principally engaged in the transportation, storage and distribution of
refined petroleum products.
Overview
In 2003, our cash flow significantly exceeded our debt service obligations and
cash distributions to our unitholders. Our petroleum products pipeline system
generates a substantial portion of this cash flow. The revenues generated from
the petroleum products pipeline business are significantly influenced by demand
for refined petroleum products, which has been growing in the markets we serve.
Expenses for this business are principally fixed and relate to routine
maintenance and system integrity work as well as field and support personnel
cost.
We expect to maintain or grow the cash flow of the petroleum products pipeline
system as well as our other businesses in the future. However, a prolonged
period of high refined-product prices could lead to a reduction in demand and
result in lower shipments on our pipeline system. In addition, increased
pipeline maintenance regulations, higher power costs and higher interest rates
could decrease the amount of cash we generate.
Petroleum products pipeline system. Our petroleum products pipeline system is
a common carrier transportation pipeline and terminals network. The system
generates approximately 81% of its revenues, excluding the sale of petroleum
products, through transportation tariffs for volumes of petroleum products it
ships. These tariffs vary depending upon where the product originates, where
ultimate delivery occurs and any applicable discounts. All transportation rates
and discounts are in published tariffs filed with FERC. The petroleum products
pipeline system also earns revenues from non-tariff based activities, including
leasing pipeline and storage tank capacity to shippers on a long-term basis and
by providing data services and product services such as ethanol unloading and
loading, additive injection, custom blending and laboratory testing.
Our petroleum products pipeline system generally does not produce, trade or take
title to the products it transports. However, the system does generate small
volumes of product through its fractionation activities. In July 2003, we
purchased a petroleum products management operation from Williams and we now
take title to the associated inventories and resulting products. From April 2002
through June 2003, we did not purchase and take title to the inventories or
resulting products associated with this operation but performed services related
to this operation for an annual fee of approximately $4 million. We also
purchase and fractionate transmix and sell the resulting separated products.
Operating costs and expenses incurred by the petroleum products pipeline system
are principally fixed costs related to routine maintenance and system integrity
as well as field and support personnel. Other costs, including power, fluctuate
with volumes transported and stored on the system. Expenses resulting from
environmental remediation projects have historically included costs from
projects relating both to current and past events. In connection with our
acquisition of this pipeline system, an affiliate of Williams agreed to
indemnify us for costs and
S-24
expenses relating to environmental remediation for events that occurred before
April 11, 2002 and are discovered within six years from that date.
Petroleum products terminals. Within our terminals network, we operate two
types of terminals: marine terminal facilities and inland terminals. The marine
terminal facilities are large product storage facilities that generate revenues
primarily from fees that we charge customers for storage and throughput
services. The inland terminals earn revenues primarily from fees we charge based
on the volumes of refined petroleum products distributed from these terminals.
The inland terminals also earn ancillary revenues from injecting additives into
gasoline and jet fuel and filtering jet fuel.
Operating costs and expenses that we incur in our marine and inland terminals
are principally fixed costs related to routine maintenance as well as field and
support personnel. Other costs, including power, fluctuate with storage
utilization or throughput levels.
Ammonia pipeline system. The ammonia pipeline system earns the majority of
its revenue from transportation tariffs that we charge for transporting ammonia
through the pipeline. Effective February 2003, we entered into an agreement with
a third-party pipeline company to operate our ammonia pipeline system. Operating
costs and expenses charged to us are principally fixed costs related to routine
maintenance as well as field personnel. Other costs, including power, fluctuate
with volumes transported on the pipeline.
Results of operations
The non-generally accepted accounting principle financial measure of operating
margin is presented below. The components of operating margin are computed by
using amounts that are determined in accordance with GAAP. A reconciliation of
operating margin to operating profit, which is its nearest comparable GAAP
financial measure, is included in the table below.
We believe that investors benefit from having access to the same financial
measures being utilized by management. Operating margin is an important
performance measure of the economic success of our core operations and
individual asset locations. This measure forms the basis of our internal
financial reporting and is used by management in deciding how to allocate
capital resources between segments. Operating profit, alternatively, includes
expense items that management does not consider when evaluating the core
profitability of an operation such as depreciation and amortization and general
and administrative costs.
S-25
Three months ended March 31, 2003 compared to three months ended March 31, 2004
Three months ended
March 31,
2003 2004
Financial highlights (in millions)
Revenues:
Transportation and terminals revenue:
Petroleum products pipeline system $ 64.7 $ 64.6
Petroleum products terminals 21.4 20.8
Ammonia pipeline system 1.6 3.6
Eliminations - (0.1 )
Total transportation and terminals revenue 87.7 88.9
Product sales 32.0 44.2
Total revenues 119.7 133.1
Operating expenses, environmental expenses and environmental
reimbursements:
Petroleum products pipeline system 25.2 29.2
Petroleum products terminals 7.7 8.3
Ammonia pipeline system 1.1 1.0
Eliminations - (0.7 )
Total operating expenses, environmental expenses and
environmental reimbursements 34.0 37.8
Product purchases 27.8 38.5
Equity earnings - (0.1 )
Operating margin 57.9 56.9
Depreciation and amortization 9.4 9.4
Affiliate general and administrative expenses 10.4 12.9
Operating profit $ 38.1 $ 34.6
Operating statistics
Petroleum products pipeline system:
Transportation revenue per barrel shipped (cents per
barrel) 98.0 97.2
Transportation barrels shipped (million barrels) 52.7 52.8
Barrel miles (billions) 15.8 14.9
Petroleum products terminals:
Marine terminal facilities:
Average storage capacity utilized per month (barrels in
millions) 15.8 15.5
Throughput (barrels in millions) 5.3 5.5
Inland terminals:
Throughput (barrels in millions) 12.6 20.5
Ammonia pipeline system:
Volume shipped (tons in thousands) 47 219
S-26
Transportation and terminals revenues for the three months ended March 31, 2004
were $88.9 million compared to $87.7 million for the three months ended
March 31, 2003, an increase of $1.2 million, or 1%. This increase was the result
of:
º •
º a decrease in petroleum products pipeline system revenues of
$0.1 million, or less than 1%. Slightly lower transportation revenue
per barrel shipped exceeded slightly higher transportation volumes
during the current period. Further, additional revenue associated with
our operation of the Longhorn Pipeline beginning in 2004 exceeded
revenue declines related to data service fees;
º •
º a decline in petroleum products terminals revenues of $0.6 million, or
3%, primarily due to the first-quarter 2003 settlement received from a
former customer associated with the early termination of its storage
contract at our Galena Park facility. Increased throughput at our
inland terminals resulting primarily from our acquisition of ownership
interests in 14 terminals during January 2004 principally offset a
decline in marine terminal revenue; and
º •
º an increase in ammonia pipeline system revenues of $2.0 million, or
125%, primarily due to significantly increased transportation volumes
during the current year. Volumes increased in the current quarter due
to slightly lower natural gas prices, higher farm commodity prices and
the implementation of a proportional credit program during late 2003.
Operating expenses, environmental expenses and environmental reimbursements
combined were $37.8 million for the three months ended March 31, 2004 compared
to $34.0 million for the three months ended March 31, 2003, an increase of
$3.8 million, or 11%. By business segment, this increase was principally the
result of:
º •
º an increase in petroleum products pipeline system expenses of
$4.0 million, or 16%, primarily attributable to higher insurance
costs, asset retirements principally resulting from improvements to a
leased terminal that are no longer utilized and less favorable product
loss allowances; and
º •
º an increase in petroleum products terminals expenses of $0.6 million,
or 8%, primarily due to operating costs associated with our newly
acquired ownership interest in 14 inland terminals. Partially
offsetting this increase was a reduction in costs at our Marrero
marine facility resulting from the 2003 demolition of smaller,
inefficient storage tanks at this location.
Revenues from product sales were $44.2 million for the three months ended
March 31, 2004, while product purchases were $38.5 million, resulting in a net
margin of $5.7 million in 2004. The 2004 net margin represents an increase of
$1.5 million compared to a net margin in 2003 of $4.2 million resulting from
product sales for the three months ended March 31, 2003 of $32.0 million and
product purchases of $27.8 million. The increase in 2004 primarily reflects the
margin results from our acquisition of the petroleum products management
operation during July 2003. This increase was partially offset by lower product
margin for the petroleum products terminals due to the sale of additional
product overages in the 2003 period during a high pricing environment. Product
sales and margins from our petroleum products management business historically
have been realized primarily during the first and fourth quarters of each year.
Product sales and margins from this business typically are lower during the
second and third quarters of each year.
S-27
Affiliate general and administrative expenses for the three months ended
March 31, 2004 were $12.9 million compared to $10.4 million for the three months
ended March 31, 2003, an increase of $2.5 million, or 24%. This increase was
primarily attributable to the following:
º •
º $0.6 million of reimbursable transition costs associated with the
separation of our general and administrative functions from Williams,
which principally included expenses during the current year related to
the creation of our technology systems. These cumulative transition
costs have exceeded the $5.9 million cash amount for which we are
responsible. As a result, the amounts in excess of $5.9 million
represent a non-cash charge to us and have been recorded as a capital
contribution by our general partner;
º •
º $1.1 million of general and administrative costs that will be
reimbursed by our general partner. Our general partner provides
general and administrative services to us for an established amount,
which was $10.1 million for first quarter 2004. The owner of our
general partner is responsible for general and administrative expenses
in excess of this cap up to a certain amount. We record total general
and administrative costs, including those costs above the cap amount
that are reimbursed by the owner of our general partner, as an
expense, and we record this amount in excess of the cap for which we
are reimbursed as a capital contribution by our general partner. When
our general partner was owned by Williams, we were unable to identify
specific costs required to support our operations. As a result, we
recorded as expense only the general and administrative costs under
the cap, which reflected our actual cash costs. As a result of the
change in our organization structure following Magellan Midstream
Holdings' acquisition of our general partner's membership interests
from Williams in June 2003, we are now able to clearly identify all
general and administrative costs required to support ourselves. The
actual cash general and administrative costs we incur continue to be
limited to the general and administrative cap; and
º •
º $0.7 million of incremental general and administrative costs
associated with an annual escalation factor and costs associated with
completed acquisitions. As agreed with our general partner, the amount
of general and administrative costs we incur will increase on an
annual basis by 7% until we are fully funding our general and
administrative cost. In addition, we are responsible for incurring
incremental general and administrative costs associated with completed
acquisitions.
Net interest expense for the three months ended March 31, 2004 was $8.1 million
compared to $8.5 million for the three months ended March 31, 2003. The
weighted-average interest rate on our borrowings decreased slightly from 6.3% in
the first quarter of 2003 to 6.2% in the first quarter of 2004 with the average
debt outstanding unchanged at $570.0 million for both periods.
Net income for the three months ended March 31, 2004 was $25.8 million compared
to $29.1 million for the three months ended March 31, 2003, a decrease of
$3.3 million, or 11%. Operating margin decreased by $1.0 million, or 2%,
primarily due to increased costs on the petroleum products pipeline system,
partially offset by increased ammonia pipeline system revenues and improved net
margin from product sales. General and administrative costs increased by
$2.5 million, primarily related to $1.1 million of reimbursable costs and
$0.6 million of reimbursable transition costs. Net interest expense declined by
$0.4 million between periods.
S-28
Year ended December 31, 2002 compared to year ended December 31, 2003
Year ended
December 31,
2002 2003
Financial highlights (in millions)
Revenues:
Transportation and terminals revenue:
Petroleum products pipeline system $ 272.5 $ 281.4
Petroleum products terminals 78.1 78.9
Ammonia pipeline system 13.1 12.6
Total transportation and terminals revenue 363.7 372.9
Product sales 70.6 112.3
Affiliate management fees 0.2 -
Total revenues 434.5 485.2
Operating expenses, environmental expenses and environmental
reimbursements:
Petroleum products pipeline system 114.7 128.5
Petroleum products terminals 35.5 34.7
Ammonia pipeline system 4.9 4.5
Eliminations - (0.8 )
Total operating expenses, environmental expenses and
environmental reimbursements 155.1 166.9
Product purchases 64.0 99.9
Operating margin 215.4 218.4
Depreciation and amortization 35.1 36.1
Affiliate general and administrative expenses 43.2 56.9
Operating profit $ 137.1 $ 125.4
Operating statistics
Petroleum products pipeline system:
Transportation revenue per barrel shipped (cents per
barrel) 94.9 96.4
Transportation barrels shipped (million barrels) 234.6 237.6
Barrel miles (billions) 71.0 70.5
Petroleum products terminals:
Marine terminal facilities:
Average storage capacity utilized per month (barrels in
millions) 16.2 15.2
Throughput (barrels in millions) 20.5 22.2
Inland terminals:
Throughput (barrels in millions) 57.3 61.2
Ammonia pipeline system:
Volume shipped (tons in thousands) 712 614
S-29
Transportation and terminals revenues for the year ended December 31, 2003 were
$372.9 million compared to $363.7 million for the year ended December 31, 2002,
an increase of $9.2 million, or 3%. This increase was a result of:
º •
º an increase in petroleum products pipeline system revenues of
$8.9 million, or 3%, primarily attributable to a higher
weighted-average tariff and increased volumes during the current
period. The higher transportation rates per barrel principally
resulted from tariff increases during July 2002 and April 2003. Tariff
adjustments generally occur during July of each year, as allowed by
FERC. However, the April 2003 increase was allowed by FERC due to a
change to the mid-year FERC-defined tariff calculation. The
incremental volume resulted from the short-term refinery production
decreases in the mid-continent region of the U.S. These production
decreases resulted in substitute volumes from alternative sources
moving through our pipeline system. Further, increased revenues from
higher data service fees as well as greater capacity lease utilization
and other ancillary revenues benefited the current year;
º •
º an increase in petroleum products terminals revenues of $0.8 million,
or 1%, primarily due to increased throughput at our inland terminals
as volumes of a former affiliate were more than replaced with higher
volumes from third-party customers. Utilization at the Gulf Coast
marine facilities was lower between the two periods due to the
termination of a former affiliate's storage agreement at our Galena
Park, Texas facility during the first quarter of 2003. Increased
revenues from the $3.0 million settlement we received were more than
offset by the resulting reduced storage utilization; and
º •
º a decrease in ammonia pipeline system revenues of $0.5 million, or 4%,
primarily due to significantly reduced transportation volumes during
the first quarter of 2003 resulting from extremely high prices for
natural gas, the primary component in the production of ammonia.
Partially offsetting this volume decline was a higher weighted-average
tariff in 2003.
Operating expenses, environmental expenses and environmental reimbursements
combined were $166.9 million for the year ended December 31, 2003 compared to
$155.1 million for the year ended December 31, 2002, an increase of
$11.8 million, or 8%. Of this increase, $3.4 million was associated with the
affiliate paid-time off benefits liability associated with operations employees
and was recorded in conjunction with the change in ownership of our general
partner. By business segment, this increase was the result of:
º •
º an increase in petroleum products pipeline system expenses of
$13.8 million, or 12%, in part due to a $2.6 million affiliate
paid-time off benefits accrual. Operating expenses further increased
due to the retirement of assets and increased costs for tank
maintenance and pipeline testing associated with the ongoing
implementation of our system integrity program. Increased power costs
resulting from higher transportation volumes and power rates as well
as higher ad valorem taxes also resulted in greater costs during 2003;
º •
º a decrease in petroleum products terminals expenses of $0.8 million,
or 2%, primarily due to reduced maintenance expenses resulting from
efficiency projects that lowered contract labor and repair costs.
Timing of tank inspection and cleaning further resulted in reduced
maintenance expenses during 2003. These positive variances were
partially
S-30
offset by a charge associated with the retirement of an asset, a
$0.8 million affiliate paid-time off benefits accrual and increased ad
valorem taxes; and
º •
º a decrease in ammonia pipeline system expenses of $0.4 million, or 8%,
primarily due to the purchase in 2002 of right-of-way easements that
have historically been leased.
Revenues from product sales were $112.3 million for the year ended December 31,
2003, while product purchases were $99.9 million, resulting in a net margin of
$12.4 million in 2003. The 2003 net margin represents an increase of
$5.8 million compared to a net margin in 2002 of $6.6 million resulting from
product sales for the year ended December 31, 2002 of $70.6 million and product
purchases of $64.0 million. The increase in 2003 primarily reflects the margin
results from our acquisition of the petroleum products management operation
during July 2003. From April 2002 through June 2003, we provided services
related to this operation for an affiliate of Williams for an annual fee rather
than generating a commodity margin.
Depreciation and amortization expense for the year ended December 31, 2003 was
$36.1 million, representing a $1.0 million increase from 2002 at $35.1 million
due to the additional depreciation associated with acquisitions and capital
improvements.
General and administrative expenses for the year ended December 31, 2003 were
$56.9 million compared to $43.2 million for the year ended December 31, 2002, an
increase of $13.7 million, or 32%.
º •
º $7.4 million of this increase was associated with one-time costs
resulting from the change in ownership of our general partner during
2003 as follows:
º •
º $3.7 million was associated with the separation of our
general and administrative functions from Williams, which
primarily included the creation of our information
technology systems and benefits programs;
º •
º $2.1 million was related to recording an affiliate paid-time
off benefits liability associated with general and
administrative employees; and
º •
º $1.6 million was associated with the early vesting of units
granted under our 2001 and 2002 equity-based incentive
compensation plan resulting from the change in control of
our general partner.
º •
º $5.9 million was associated with general and administrative costs in
excess of the general and administrative cap that will be reimbursed
by our general partner. As a result of the change in our
organizational structure we are now able to clearly identify all
general and administrative costs required to support ourselves and
total general and administrative costs, including those costs above
the cap amount that will be reimbursed by our general partner, are
recorded as our expense. Under the previous structure, we were unable
to identify specific costs required to support our operations;
consequently, we recorded as expense only the general and
administrative costs under the cap, which reflected our actual cash
cost. The actual cash general and administrative costs we incur will
continue to be limited to the general and administrative cap and the
amount of costs above the cap will be recorded as a capital
contribution by our general partner.
S-31
Net interest expense for the year ended December 31, 2003 was $34.5 million
compared to $21.8 million for the year ended December 31, 2002. The increase in
interest expense was primarily related to the replacement during the fourth
quarter of 2002 of short-term debt financing associated with the acquisition of
our petroleum products pipeline system with long-term debt at higher interest
rates. The weighted-average interest rate on our borrowings increased from 4.6%
in 2002 to 6.3% in 2003 with the average debt outstanding increasing from
$522.0 million in 2002 to $570.0 million in 2003.
Debt placement fee amortization declined from $9.9 million in 2002 to
$2.8 million in 2003. During the 2002 period, the short-term debt associated
with our acquisition of the petroleum products pipeline system was outstanding
with related debt costs amortized over the seven-month period that the debt was
outstanding. Our subsequent long-term debt financing costs are amortized over
the five-year life of the notes.
We do not pay income taxes because we are a partnership. However, earnings from
the petroleum products pipeline system were subject to income taxes prior to our
acquisition of it in April 2002. Taxes on these earnings were at income tax
rates of 37% for the year ended December 31, 2002, based on the effective income
tax rate for Williams as a result of Williams' tax-sharing arrangement with its
subsidiaries. The effective income tax rate exceeds the U.S. federal statutory
income tax rate primarily due to state income taxes.
Net income for the year ended December 31, 2003 was $88.2 million compared to
$99.2 million for the year ended December 31, 2002, a decrease of $11.0 million,
or 11%, primarily due to $10.8 million of one-time costs associated with the
2003 change in ownership of our general partner, of which $3.4 million was
operating expense and $7.4 was general and administrative expense. Our net
income further declined due to an additional $5.9 million of reimbursable
general and administrative costs. Our operating margin increased by $3.0 million
over the prior year despite the $3.4 million of one-time operating expense
items, largely as a result of increased transportation volumes and rates on our
petroleum products pipeline system, increased product margin associated with the
purchase of our petroleum products management operation in July 2003 and reduced
operating expenses associated with the petroleum products terminals.
Depreciation and net interest expense increased by $1.0 million and
$12.7 million, respectively, while debt placement fee amortization expense
decreased $7.1 million. Other income declined $2.0 million primarily due to a
gain on the sale of assets during 2002. Income taxes decreased $8.3 million due
to our partnership structure.
S-32
Year ended December 31, 2001 compared to year ended December 31, 2002
Year ended
December 31,
2001 2002
Financial highlights (in millions)
Revenues:
Transportation and terminals revenue:
Petroleum products pipeline system $ 254.9 $ 272.5
Petroleum products terminals 70.0 78.1
Ammonia pipeline system 14.5 13.1
Total transportation and terminals revenue 339.4 363.7
Product sales 108.2 70.6
Affiliate management fees 1.0 0.2
Total revenues 448.6 434.5
Operating expenses, environmental expenses and environmental
reimbursements:
Petroleum products pipeline system 123.6 114.7
Petroleum products terminals 33.3 35.5
Ammonia pipeline system 4.0 4.9
Total operating expenses, environmental expenses and
environmental reimbursements. 160.9 155.1
Product purchases 95.3 64.0
Operating margin 192.4 215.4
Depreciation and amortization 35.8 35.1
Affiliate general and administrative expense 47.3 43.2
Operating profit $ 109.3 $ 137.1
Operating statistics
Petroleum products pipeline system:
Transportation revenue per barrel shipped (cents per
barrel) 90.8 94.9
Transportation barrels shipped (million barrels) 236.1 234.6
Barrel miles (billions) 70.5 71.0
Petroleum products terminals:
Marine terminal facilities:
Average storage capacity utilized per month (barrels in
millions) 15.7 16.2
Throughput (barrels in millions) 11.5 20.5
Inland terminals:
Throughput (barrels in millions) 56.7 57.3
Ammonia pipeline system:
Volume shipped (tons in thousands) 763 712
S-33
Transportation and terminals revenues for the year ended December 31, 2002 were
$363.7 million compared to $339.4 million for the year ended December 31, 2001,
an increase of $24.3 million, or 7%. This increase was the result of:
º •
º an increase in petroleum products pipeline system revenues of
$17.6 million, or 7%. Transportation revenues increased between
periods due to higher weighted-average tariffs that more than offset
slightly lower shipments. The tariffs were higher due to a mid-year
rate increase and our customers' transporting products longer
distances. These longer hauls resulted primarily from supply shifts
within our pipeline system during the latter part of 2002 caused by
temporary reductions of refinery production on our system. Further,
increased rates for data services as well as higher ethanol loading
and storage volumes resulted in additional revenue;
º •
º an increase in petroleum products terminals revenues of $8.1 million,
or 12%, primarily due to the acquisitions of our Gibson marine
terminal facility in October 2001 and two Little Rock inland terminals
in June 2001. An improved marketing environment resulted in higher
utilization and rates at our Gulf Coast facilities, further increasing
revenues during 2002; and
º •
º a decrease in ammonia pipeline system revenues of $1.4 million, or
10%, primarily due to a throughput deficiency billing in the prior
year that resulted from a shipper's inability to meet its minimum
annual throughput commitment for the contract year ended June 2001. In
addition, revenue also declined due to significantly reduced volumes
from one of our shippers following its filing for Chapter 11
bankruptcy during May 2002. Partially offsetting these decreases was a
higher weighted-average tariff in 2002.
Operating expenses, environmental expenses and environmental reimbursements
combined were $155.1 million for the year ended December 31, 2002, compared to
$160.9 million for the year ended December 31, 2001, a decrease of $5.8 million,
or 4%. This decrease was the result of:
º •
º a decrease in petroleum products pipeline system expenses of
$8.9 million, or 7%, primarily due to lower environmental and
maintenance expenses and reduced power costs. Environmental costs were
lower due to the indemnification from an affiliate of Williams for
environmental issues resulting from operations prior to our ownership
of the pipeline. Maintenance expenses declined due to improved cost
controls as a result of the implementation of improved operating
practices. Reduced power costs resulted from lower volumes transported
coupled with reduced power rates. Partially offsetting these
reductions was an increase in pipeline lease expenses, which represent
tariffs paid on connecting pipelines to move a customer's product to
its ultimate destination;
º •
º an increase in petroleum products terminals expenses of $2.2 million,
or 7%, primarily due to the addition of the Gibson marine facility and
the Little Rock inland terminals and increased maintenance expenses
resulting from timing of tank cleaning and inspections at the inland
terminals; and
º •
º an increase in ammonia pipeline system expenses of $0.9 million, or
23%, primarily due to the purchase in the current year of right-of-way
easements that have historically been leased and higher property
taxes.
S-34
Revenues from product sales were $70.6 million for the year ended December 31,
2002, while product purchases were $64.0 million, resulting in a net margin of
$6.6 million in 2002. The 2002 net margin represents a decrease of $6.3 million
compared to a net margin in 2001 of $12.9 million resulting from product sales
for the year ended December 31, 2001 of $108.2 million and product purchases of
$95.3 million. The margin decline in 2002 reflects our agreement with an
affiliate of Williams to provide blending services for them for an annual fee
rather than generating a commodity margin in relation to this activity from
April 2002 through December 2002.
Affiliate management fee revenues for the year ended December 31, 2002 were
$0.2 million compared to $1.0 million for the year ended December 31, 2001.
Historically, the petroleum products pipeline system received a fee to manage an
affiliate pipeline.
Depreciation and amortization expense for the year ended December 31, 2002 was
$35.1 million, representing a $0.7 million decrease from 2001 at $35.8 million.
Additional depreciation associated with acquisitions and capital improvements
was more than offset by the elimination of depreciation associated with assets
that previously were a part of Magellan Pipeline Company but were excluded from
the assets transferred to us when we acquired the petroleum products pipeline
system.
General and administrative expenses for the year ended December 31, 2002 were
$43.2 million compared to $47.3 million for the year ended December 31, 2001, a
decrease of $4.1 million, or 9%. Prior to our acquisition of the petroleum
products pipeline system, this operating unit was allocated general and
administrative costs from Williams based on a multi-factor formula. Following
the acquisition, general and administrative expenses that we paid to Williams
for this pipeline system were subject to an expense limitation, which resulted
in a lower general and administrative costs to us. Incentive compensation costs
associated with our long-term incentive plan were specifically excluded from the
expense limitation and were $3.7 million during 2002 and $2.0 million during
2001. The 2002 incentive compensation costs included $2.1 million associated
with the early vesting of the restricted units issued to key employees at the
time of our initial public offering. The early vesting was triggered as a result
of meeting targets for our growth in cash distributions paid to unitholders.
Net interest expense for the year ended December 31, 2002 was $21.8 million
compared to $12.1 million for the year ended December 31, 2001. The increase in
interest expense was primarily related to the debt financing of the petroleum
products pipeline system. Although the weighted-average interest rates decreased
from 5.0% in 2001 to 4.6% in 2002, the weighted-average debt outstanding
increased from $113.3 million in 2001 to $522.0 million in 2002.
We do not pay income taxes because we are a partnership. However, earnings from
the petroleum products pipeline system were subject to income taxes prior to our
acquisition of it in April 2002, and our pre-initial public offering earnings in
2001 were also taxable. Taxes on these earnings were at income tax rates of 37%
and 39% for the year ended December 31, 2002 and 2001, respectively, based on
the effective income tax rate for Williams as a result of Williams' tax-sharing
arrangement with its subsidiaries. The effective income tax rate exceeds the
U.S. federal statutory income tax rate primarily due to state income taxes.
S-35
Net income for the year ended December 31, 2002 was $99.2 million compared to
$67.9 million for the year ended December 31, 2001, an increase of
$31.3 million, or 46%. The operating margin increased by $23.0 million during
the period, largely as a result of increased revenues and reduced operating
expenses including environmental expenses net of reimbursements for the
petroleum products pipeline system, earnings from the acquisitions of the Little
Rock and Gibson terminal facilities and increased utilization and rates at our
Gulf Coast marine facilities. Depreciation expense and general and
administrative expenses decreased by $0.7 million and $4.1 million,
respectively, while net interest expense increased by $9.7 million. Debt
placement fee amortization expense increased $9.7 million primarily due to costs
from debt financing associated with the petroleum products pipeline system
acquisition. Other income increased $1.7 million primarily due to a gain on the
sale of assets during 2002 and an impairment charge recorded during 2001 related
to the inactive refinery site at Augusta, Kansas, the assets and liabilities of
which were not transferred to us as part of our acquisition of the petroleum
products pipeline system. Income taxes decreased $21.2 million due to our
partnership structure.
Liquidity and capital resources
Cash flows and capital expenditures
Three months ended March 31, 2004. During the three months ended March 31,
2004, distributions paid and maintenance capital requirements exceeded net cash
provided by operating activities by $12.4 million. Working capital needs,
described below, significantly reduced our net cash provided by operating
activities in the current quarter. We do not expect this situation to continue
for the remainder of 2004. Our current cash distributions exceeded the minimum
quarterly distribution of $0.525 per unit by $12.2 million.
Net cash provided by operating activities was $15.6 million for the three months
ended March 31, 2004 and $40.2 million for the three months ended March 31,
2003. Lower net income and changes in components of operating assets and
liabilities during 2004 resulted in decreased cash from operations. Significant
changes in working capital included:
º •
º a decrease in accrued affiliate payroll and benefits of $8.0 million
in 2004 compared to an increase of $0.8 million in 2003. The decrease
in 2004 was primarily the result of the payment of larger bonuses
related to 2003 in the first quarter of 2004, while smaller bonuses
related to 2002 were paid partially in March of 2003 and partially in
August of 2003;
º •
º a decrease in accrued product purchases in 2004 of $3.7 million,
compared to an increase of $4.9 million in 2003. The decrease in
accrued product purchases in 2004 was primarily the result of seasonal
fluctuations related to our petroleum products management operation,
which we purchased in July 2003. This decrease was partially offset by
a decrease in inventories of $3.3 million in 2004 versus a decrease of
only $0.3 million in 2003;
º •
º an increase in current and noncurrent environmental liabilities in
2004 of $20.1 million, compared to an increase of $0.5 million in
2003. The increase in 2004 was primarily the result of indemnified
environmental liabilities for which we recorded offsetting
receivables; and
S-36
º •
º an increase in accounts receivable and other accounts receivable in
2004 of $25.6 million, compared to an increase of $3.0 million in
2003. The majority of the increase in 2004 was related to indemnified
environmental liabilities, which largely offset the increase in
accounts receivable and other accounts receivable. The remaining
increase in 2004 was attributable primarily to receivables from
insurers related to environmental remediation performed during 2004,
and to higher trade receivables related to our petroleum products
management business as a result of favorable market conditions.
Net cash used by investing activities for the three months ended March 31, 2004
and 2003 was $59.7 million and $4.5 million, respectively. During 2004, we
acquired ownership in 14 petroleum products terminals and a 50% interest in
Osage Pipe Line Company, LLC. We also invested capital to maintain our existing
assets. Total maintenance capital spending before reimbursements was
$2.7 million and $2.6 million in 2004 and 2003, respectively. Please see
"-Capital requirements" below for a further discussion of capital expenditures
as well as maintenance capital amounts net of reimbursements.
During the first quarter of 2004, we paid $25.8 million in cash distributions to
our unitholders and general partner. The quarterly distribution amount
associated with the first quarter of 2004 that will be paid during the second
quarter of 2004 was $0.85 per unit, which equates to a total payment of
$26.9 million. If we continue to pay cash distributions at this level and the
number of outstanding units remains the same, we will pay total cash
distributions of $107.6 million to our unitholders on an annual basis. Of this
amount, $14.5 million, or 13%, is related to our general partner's 2% ownership
interest and incentive distribution rights held by our general partner.
Net cash used by financing activities for the three months ended March 31, 2004
and 2003 was $23.3 million and $17.4 million, respectively, consisting primarily
of the payment of cash distributions to our unitholders during both periods.
Years Ended December 31, 2001, 2002 and 2003. During 2003, net cash provided
by operating activities exceeded distributions paid and maintenance capital
requirements by $32.6 million. Our cash distributions exceeded the minimum
quarterly distribution of $0.525 per unit by $38.2 million.
Net cash provided by operating activities was $144.0 million for the year ended
December 31, 2003, $161.0 million for 2002 and $135.3 million for 2001.
º •
º The $17.0 million decrease from 2002 to 2003 was primarily
attributable to:
º •
º reduced net income of $11.0 million principally resulting
from the one-time costs related to the 2003 change in
control of our general partner that impacted the current
year;
º •
º an increase in inventory of $12.1 million during 2003
resulting from our July 2003 purchase of a petroleum
products management operation. The corresponding increase in
accrued product purchases of $8.5 million partially offset
the inventory change; and
º •
º non-cash one-time expenses associated with the change of
control of our general partner in 2003 were generally offset
by changes in our affiliate assets and liabilities.
S-37
º •
º The $25.7 million increase in cash from operating activities from 2001
to 2002 was primarily attributable to an increase in net income of
$31.3 million and changes in operating assets and liabilities. Changes
in operating assets and liabilities reduced net cash from operating
activities by $7.2 million and were principally attributable to:
º •
º an increase in accounts receivable and other accounts
receivable of $15.4 million. As part of our acquisition of
the petroleum products pipeline system in April 2002,
Williams retained $15.0 million of receivables resulting in
a significant increase in receivables during 2002 as the
receivables retained by Williams were replaced in the
ordinary course of business;
º •
º a reduction in inventory of $18.3 million due to the
elimination of inventories associated with the petroleum
products management operation retained by Williams at the
time of our acquisition of the petroleum products pipeline
system; and
º •
º net affiliate assets and liabilities increased
$17.6 million. However, $5.0 million of the increase was
offset by related increases in environmental liabilities
indemnified by affiliates. The remaining increase of
$12.6 million was due primarily to establishing affiliate
receivables for environmental liabilities indemnified at the
time of our acquisition of the petroleum products pipeline
system.
Net cash used by investing activities for the years ended December 31, 2001,
2002 and 2003 was $87.5 million, $727.0 million and $45.9 million, respectively.
During 2003, we acquired our petroleum products management operation. During
2002, we acquired our petroleum products pipeline system and the Aux Sable
natural gas liquids pipeline. During 2001, we acquired our two Little Rock
inland terminals and the Gibson marine facility. We also invested capital to
maintain our existing assets. Total maintenance capital spending before
reimbursements was $24.4 million, $26.4 million and $20.9 million in 2001, 2002
and 2003, respectively. Please see "-Capital requirements" below for further
discussion of capital expenditures as well as maintenance capital amounts net of
reimbursements.
Net cash provided (used) by financing activities for the years ended
December 31, 2001, 2002 and 2003 was $(34.0) million, $627.3 million and $(61.8)
million, respectively. Cash was used during 2003 primarily to pay cash
distributions to our unitholders. Cash provided during 2002 principally included
the debt and equity funding that were completed in conjunction with our
acquisition of the petroleum products pipeline system. Cash was used in 2001 to
repay affiliate notes associated with the assets held at the time of our initial
public offering assets as well as payments made by our petroleum products
pipeline system to decrease its affiliate note balance, partially offset by
proceeds from debt borrowings and equity issued in our initial public offering
and subsequent debt borrowings for acquisitions.
During 2003, we paid $90.5 million in cash distributions to our unitholders.
S-38
Capital requirements
The transportation, storage and distribution business requires continual
investment to upgrade or enhance existing operations and to ensure compliance
with safety and environmental regulations. The capital requirements of our
businesses consist primarily of:
º •
º maintenance capital expenditures, such as those required to maintain
equipment reliability and safety and to address environmental
regulations; and
º •
º payout capital expenditures to acquire additional complementary assets
to grow our business and to expand or upgrade our existing facilities,
referred to as organic growth projects. Organic growth projects
include capital expenditures that increase storage or throughput
volumes or develop pipeline connections to new supply sources.
Williams agreed to reimburse us for maintenance capital expenditures incurred in
2001 and 2002 in excess of $4.9 million per year related to the assets held at
the time of our initial public offering. This reimbursement obligation was
subject to a maximum combined reimbursement for both years of $15.0 million.
During 2001 and 2002, we recorded reimbursements from Williams associated with
these assets of $3.9 million and $11.0 million, respectively.
In connection with our acquisition of Magellan Pipeline Company, Williams agreed
to reimburse us for maintenance capital expenditures incurred in 2002, 2003 and
2004 in excess of $19.0 million per year related to this pipeline system,
subject to a maximum combined reimbursement for all years of $15.0 million. Our
maintenance capital expenditures related to the petroleum products pipeline
system for 2002 and 2003 were less than $19.0 million per year and we expect
that they will be less than $19.0 million in 2004. Therefore, we do not
anticipate reimbursement by Williams associated with this agreement.
During first-quarter 2004, we spent maintenance capital of $2.2 million on our
operations. Further, we spent an additional $0.5 million of capital associated
with our separation from Williams, all of which was reimbursed by our general
partner. For 2004, we expect to incur maintenance capital expenditures net of
reimbursable projects for all of our businesses of approximately $18.5 million.
During 2003, our maintenance capital spending net of environmental
reimbursements was $12.2 million. Reimbursable environmental projects were
$3.6 million during 2003. Further, we spent an additional $5.0 million of
capital associated with our separation from Williams, or $3.4 million net of
reimbursements.
In addition to maintenance capital expenditures, we also incur payout capital
expenditures at our existing facilities. During first-quarter 2004, we spent
$6.6 |