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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-16335
WILLIAMS ENERGY PARTNERS L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 73-1599053
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
WILLIAMS GP LLC
ONE WILLIAMS CENTER, TULSA, OKLAHOMA 74172
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(918) 573-2000
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
------------------- ------------------------
Common Units representing limited New York Stock Exchange
partnership interests
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the registrant's voting and non-voting units
held by non-affiliates as of the close of business on February 28, 2002, was
approximately $154.7 million.
The number of units of the registrant's common units held by non-affiliates
and outstanding at February 28, 2002, was 4,600,000.
DOCUMENTS INCORPORATED BY REFERENCE
NONE
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EXPLANATORY NOTE
We are filing this Amendment No. 1 on Form 10-K/A in response to comments
received from the Securities and Exchange Commission regarding our Annual Report
on Form 10-K for the fiscal year ended December 31, 2001 that was originally
filed on March 7, 2002 (the "Original Filing").
This report revises the disclosure under the "Use of Proceeds" section to
include a description of the capital expenditures for which we were required to
reimburse Williams Energy Services, LLC $12.1 million of the proceeds from our
initial public offering in February 2001. In addition, the "Related Party
Transactions" section has been revised to include additional disclosure on the
nature of our contracts with Williams Energy Marketing & Trading Company and
Williams Refining & Marketing, L.L.C. and appropriate cross-references to this
disclosure have been added throughout the document. In addition, Management's
Discussion & Analysis of Financial Condition and Results of Operations has been
revised to describe our and our affiliate's contractual arrangements with Enron
Corp. and its affiliates.
This report continues to speak as of the date of the Original Filing, and
we have not updated the disclosure in this report to speak as of a later date.
All information contained in this report and the Original Filing is subject to
updating and supplementing as provided in our periodic reports filed with the
SEC.
WILLIAMS ENERGY PARTNERS L.P.
FORM 10-K/A
PART I
ITEM 1. BUSINESS
(a) GENERAL DEVELOPMENT OF BUSINESS
We were formed as a limited partnership under the laws of the State of
Delaware in August 2000. The principal executive offices of Williams GP LLC, our
general partner, are located at One Williams Center, Tulsa, Oklahoma 74172
(telephone (918) 573-2000).
On October 30, 2000, we filed with the Securities and Exchange Commission a
registration statement on Form S-1 related to an initial public offering of
common units. In February 2001, 4,600,000 common units, representing
approximately 40 percent of our total outstanding units, were sold to the
public. The Williams Companies, Inc., through its wholly owned subsidiaries,
currently owns approximately 60 percent of our Partnership interests including
its general partner interest.
Effective June 30, 2001, we purchased two petroleum distribution facilities
in Little Rock, Arkansas, from TransMontaigne, Inc. for $29.1 million. These
facilities primarily handle gasoline and diesel fuel and have 452,000 barrels of
storage capacity.
Effective November 8, 2001, we purchased the crude oil storage and
distribution assets of Geonet Gathering, Inc., for $21.1 million. The assets
included three pipelines in Gibson, Louisiana that have a combined capacity to
distribute up to 60,000 barrels per day of crude oil from a storage facility
into pipeline interconnects. The acquisition also included long-term lease
agreements for 56,000 barrels of crude oil storage, two barge docks and a truck
loading rack.
(b) FINANCIAL INFORMATION ABOUT SEGMENTS
See Part II, Item 8 -- Financial Statements and Supplementary Data.
(c) NARRATIVE DESCRIPTION OF BUSINESS
We were formed by The Williams Companies, Inc., which we sometimes refer to
as Williams or WMB, to own, operate and acquire a diversified portfolio of
complementary energy assets. We are principally engaged in the storage,
transportation and distribution of refined petroleum products and ammonia. Our
asset portfolio currently consists of:
- Five petroleum product terminal facilities located along the Gulf Coast
and near the New York harbor. We refer to these facilities as our marine
terminals.
- 25 petroleum product terminals (some of which are partially owned)
located principally in the southeastern United States. We refer to these
terminals as our inland terminals.
- An ammonia pipeline and terminals system, which extends approximately
1,100 miles from Texas and Oklahoma to Minnesota.
Upon the closing of our initial public offering in February 2001, four
marine terminals, 24 inland terminals and the ammonia pipeline and terminals
system were transferred to us, including the related liabilities. We acquired an
additional marine terminal and two additional inland terminals and sold one
inland terminal during 2001.
1
PETROLEUM PRODUCT TERMINALS
The United States refined petroleum product distribution system links oil
refineries to end-users of gasoline and other refined petroleum products. It is
comprised of a network of terminals, storage facilities, pipelines, tankers,
barges, rail cars and trucks and is used to move refined petroleum products from
refineries to the ultimate end-consumer. Throughout the distribution system,
terminals play a key role in moving product to the end-user market by providing
storage, distribution, blending and other ancillary services. Products stored in
and distributed through our terminal network include:
- Refined Petroleum Products, which are the output from refineries and are
often used as fuels for consumers. Refined petroleum products include
gasoline, diesel, jet fuel, kerosene and heating oil.
- Blendstocks, which are blended with other products to change or enhance
their characteristics such as increasing a gasoline's octane or oxygen
content. Blendstocks include products such as alkylates and oxygenates.
- Heavy Oils and Feedstocks, which are often used as burner fuels or
feedstocks for further processing by refineries and petrochemical
facilities. Heavy oils and feedstocks include products such as number six
fuel oil, vacuum gas oil and asphalt.
Within our terminal network, we operate two types of terminals: marine
terminals and inland terminals. Our marine terminal facilities are located in
close proximity to refineries and are large storage and distribution facilities
that handle refined petroleum products, blendstocks and heavy oils and
feedstocks. Our inland terminals are located in the southeastern United States
and are primarily located along third party pipelines such as Colonial, TEPPCO
and Plantation. These facilities receive products from pipelines and distribute
them to third parties at the terminals, who in turn deliver them to end-users
such as retail outlets. Because these terminals are unregulated, the marketplace
determines the prices we can charge for our services. Williams Energy Marketing
& Trading Company and Williams Refining & Marketing, L.L.C., subsidiaries of The
Williams Companies, Inc., utilize our facilities to support their business
activities and are among our largest terminal customers. Williams Energy
Marketing & Trading Company and Williams Refining & Marketing, L.L.C.
represented approximately 13 percent and 9 percent, respectively, of our
terminal's revenues and 11 percent and 7 percent, respectively, of our total
revenues for the year ended December 31, 2001. For additional information
relating to our commercial agreements with The Williams Companies, Inc. and its
affiliates, please read "Management's Discussion & Analysis of Financial
Condition and Results of Operations -- Related Party Transactions," which begins
on page 31.
MARINE TERMINALS
The Gulf Coast region is a major hub for petroleum refining, representing
approximately 42 percent of total U.S. daily refining capacity and 67 percent of
U.S. refining capacity expansion from 1990 to 2000. The growth in Gulf Coast
refining capacity has resulted in part from consolidation in the petroleum
industry to take advantage of economies of scale from operating larger,
concentrated refineries. We expect this trend to continue in order to meet
growing domestic and international demand. From 1990 to 2000, the amount of
petroleum products exported from the Gulf Coast region increased by
approximately 18 percent, or 195 million barrels. The growth in refining
capacity and increased product flow attributable to the Gulf Coast region has
created a need for additional transportation, storage and distribution
facilities. In the future, the competition resulting from the consolidation
trend, combined with continued environmental pressures, governmental regulations
and market conditions, could result in the closing of smaller, less economical
inland refiners, creating even greater demand for petroleum products refined in
the Gulf Coast region.
We own and operate five marine terminal facilities, including four marine
terminal facilities located along the Gulf Coast and one terminal facility
located in Connecticut near the New York harbor. Our marine terminals are large
storage and distribution facilities that provide inventory management, storage
and distribution services for refiners and other large end-users of petroleum
products. Our marine terminal facilities have an aggregate storage capacity of
approximately 17.6 million barrels.
2
Our marine terminal facilities primarily receive petroleum products by ship
and barge, short-haul pipeline connections to neighboring refineries and common
carrier pipelines. We distribute petroleum products from our marine terminals by
all of those means as well as by truck and rail. Once the product has reached
our terminal facilities, we store the product for a period of time ranging from
a few days to several months. Products that we store in our marine terminal
facilities include petroleum products, blendstocks and heavy oils and
feedstocks.
In addition to providing storage and distribution services, our marine
terminal facilities provide ancillary services including heating, blending and
mixing of stored products and injection services. Many heavy oils require
heating to keep them in a liquid state. In addition, in order to meet government
specifications, products often must be combined with other products through the
blending and mixing process. Blending is the combination of products from
different storage tanks. Once the products are blended together, the mixing
process circulates the blended product through mixing lines and nozzles to
further combine the products. Finally, injection is the process of injecting
refined petroleum products with additives and dyes to comply with governmental
regulations and to meet our customer's marketing initiatives. We also provide
marine vessel fueling services, referred to as bunkering.
Our terminals generate fees primarily through providing long term or spot
on demand storage services and inventory management for a variety of customers.
Refiners and chemical companies will typically use our 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.
The following table outlines our marine terminal locations, capacities,
primary products handled and the connections to and from these terminals:
RATED STORAGE
CAPACITY
(THOUSAND
FACILITY BARRELS) PRIMARY PRODUCTS HANDLED CONNECTIONS
-------- ------------- ------------------------ -----------
Galena Park, Texas........................ 8,884 Refined petroleum products, Pipeline, barge, ship,
blendstocks, heavy oils and rail and truck
feedstocks
Corpus Christi, Texas..................... 2,711 Blendstocks, heavy oils and Pipeline, barge, ship
feedstocks and truck
Marrero, Louisiana........................ 2,006 Heavy oils and feedstocks Barge, ship, rail and
truck
Gibson, Louisiana......................... 56 Crude oil and condensate Pipeline, barge and
truck
New Haven, Connecticut.................... 3,986 Refined petroleum products, Pipeline, barge, ship
heavy oils and feedstocks and truck
------
Total storage capacity.......... 17,643
======
Galena Park Facility. Our Galena Park, Texas facility is located along the
Houston Ship Channel and is one of the largest marine distribution facilities in
the United States. It has 103 tanks with an aggregate storage capacity of 8.9
million barrels, two ship docks and three barge docks and includes a storage
tank at Channelview, Texas. The facility stores a mix of refined petroleum
products, blendstocks and heavy oils and feedstocks. We primarily receive
products in this facility via barge, pipe and ship and distribute products from
the facility via truck, barge, ship and pipeline.
Our Galena Park facility provides our customers with access to multiple
common carrier pipelines, deep-water port facilities that accommodate both ship
and barge traffic and loading and unloading facilities for trucks and rail cars.
The facility has a 14-inch, 2.5-mile pipeline that runs under the Houston Ship
Channel to the Witter Street Station. The Witter Street Station is a major
pipeline junction that connects our facility to most major Gulf Coast refineries
and common carrier pipelines such as the TEPPCO Partners, L.P. and
3
El Paso Corporation pipelines. These refineries and pipelines provide marketers
such as Valero Marketing and Supply Company, Koch Supply and Trading Company,
CITGO Petroleum Corporation, El Paso Corporation and Shell Oil Company with
opportunities to supply their retail and wholesale needs along our terminal
network. We also own two 36-inch pipelines and one 14-inch pipeline that connect
our facility to the Colonial and Explorer pipelines, providing distribution
capacity to markets in the southeastern, east coast and midwestern United
States. We also own one active pipeline and several inactive pipelines that run
to the Holland Avenue Station and connect our facility to Equistar Chemicals'
petrochemical plant.
Corpus Christi Facility. Our Corpus Christi, Texas facility is located
near four major refineries and one petrochemical plant. This facility includes
47 tanks with an aggregate storage capacity of 2.7 million barrels. We primarily
receive products at our Corpus Christi facility by ship and barge through three
docks owned by the Port of Corpus Christi, and we deliver product by barge,
ship, truck and pipeline, including El Paso's common carrier pipeline with
appropriate connections that transport products from Corpus Christi to Houston.
We provide inventory management and storage services for the refineries and
petrochemical plants. We store blendstocks, heavy oils and feedstocks. Our
Corpus Christi facility has pipeline connections to many of the local refineries
including Koch, CITGO, El Paso and Equistar Chemicals' petrochemical plant.
Marrero Facility. Our Marrero, Louisiana facility is located adjacent to
the Mississippi River and is 22 miles from the Port of New Orleans. This
facility has 71 tanks with an aggregate storage capacity of 2.0 million barrels
and three barge docks. We primarily receive products at our Marrero facility by
ship and barge, and we deliver products from Marrero by rail, barge and truck.
In addition, our facility is connected to a Texaco, Inc. terminal by four
separate pipelines.
Our Marrero facility primarily stores heavy oils and feedstocks. Also, a
major local refiner uses our facility to store its excess production.
Gibson Facility. Our Gibson, Louisiana facility is located adjacent to
Bayou Black, a body of water which connects to the Intracoastal Waterway. The
facility has five tanks with an aggregate storage capacity of 0.1 million
barrels and two barge docks. The facility receives products by barge, pipeline
and truck, and we primarily deliver products by pipeline.
Our Gibson terminal primarily stores and transports crude oil and
condensate. The facility is connected to the Ship Shoal Pipeline system by one
8-inch pipeline and one 6-inch pipeline, both of which we own.
New Haven Facility. Our New Haven, Connecticut facility has four refined
product terminals, the Waterfront, Forbes, 85 East and Hamden terminals, with an
aggregate refined product storage capacity of 3.6 million barrels and asphalt
tankage with 0.4 million barrels of storage capacity. Our New Haven facility
receives product by ship and barge and distributes products by pipeline and
truck. We also have the capability to deliver products via ship and barge.
Our Waterfront terminal has 0.8 million barrels of storage capacity and
handles refined petroleum products. We receive products in this terminal via
barge and ship, and we deliver products from the terminal via truck, barge and
the Buckeye Pipeline. The Forbes terminal has 0.6 million barrels of storage
capacity and handles refined petroleum products. The Forbes terminal is
connected to the Waterfront terminal by four two-way 10-inch and 12-inch
pipelines that we own. The 85 East terminal has 1.4 million barrels of storage
capacity and handles refined petroleum products and asphalt. The Hamden terminal
has 1.2 million barrels of storage capacity and handles refined petroleum
products. The Hamden terminal is connected to the 85 East Terminal by a three
mile 8-inch pipeline that we own.
Customers and Contracts. We have long-standing relationships with oil
refiners, suppliers and traders at our facilities, and most of our customers
have consistently renewed their short-term contracts. During 2001, approximately
89 percent of our marine terminal working storage capacity was under contract.
As of December 31, 2001, approximately 44 percent of the revenues that we
generated were from contracts with remaining terms in excess of one year or that
renew on an annual basis. Williams Energy Marketing & Trading Company
represented approximately 17 percent of revenues at our marine terminals for the
year ended
4
December 31, 2001. For a further discussion of revenues from major customers and
concentration of credit risk, refer to Note 6 of the Consolidated Financial
Statements.
Markets and Competition. We believe that the strong demand for our marine
terminal facilities from our refining and chemical customers results from our
cost-effective distribution services and key transportation links such as
deep-water ports. We experience the greatest demand at our marine terminals in a
contango market, when customers tend to store more product to take advantage of
favorable pricing expected in the future. When the opposite market condition,
known as backwardation, exists, some companies choose not to store product. The
additional heating and blending services that we provide at our marine
terminals, however, attract additional demand for our storage services and
result in increased revenue opportunities.
Several major and integrated oil companies have their own proprietary
storage terminals along the Gulf Coast that are currently being used in their
refining operations. If these companies choose to shut down their refining
operations and elect to store and distribute refined petroleum products through
their proprietary terminals, we would experience increased competition for the
services that we provide. In addition, several companies have facilities in the
Gulf Coast region and offer competing storage and distribution services.
INLAND TERMINALS
We own and operate a network of 25 refined petroleum product terminals
located primarily in the southeastern United States. These terminals have a
combined storage capacity of 5.0 million barrels. Our customers utilize these
facilities to take delivery of refined petroleum products transported on major
common-carrier interstate pipelines. The majority of our inland terminals
connect to the Colonial, Plantation, TEPPCO or Explorer pipelines, and some
facilities have multiple pipeline connections. In addition, our Dallas terminal
connects to Dallas Love Field airport via a 6-inch pipeline we purchased in
April 2001. During 2001, gasoline represented approximately 53 percent of the
volume of product distributed through our inland terminals, with the remaining
47 percent consisting of distillates such as low sulfur diesel and jet fuel.
Our inland terminal facilities typically consist of multiple storage tanks
that are connected by a third-party pipeline system. 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 our storage tanks
to a truck or rail car loading rack.
We are an independent provider of storage and distribution services.
Because we do not own the products moving through our terminals, we are not
exposed to the risks of product ownership. We operate our inland terminals as
distribution terminals, and we primarily serve the retail, industrial and
commercial sales markets. We provide the following services at our inland
terminals:
- inventory and supply management through our virtual supply network and
the ATLAS 2000 software system;
- distribution; and
- other services such as injection of gasoline additives.
We generate revenues by charging our customers a fee based on the amount of
product that we deliver through our terminals. We charge these fees when we
deliver the product to our customers and load it into a truck or rail car. 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.
5
We wholly own 14 of these inland terminals and our percentage ownership of
the remaining 11 inland terminals ranges from 50 percent to 79 percent. The
following table sets forth our inland terminal locations, percentage ownership,
capacities and methods of supply:
TOTAL STORAGE
PERCENTAGE CAPACITY
FACILITY OWNERSHIP (THOUSAND BARRELS) CONNECTIONS
-------- ---------- ------------------ -----------
Alabama
Mobile.................................. 100 135 Barge
Montgomery.............................. 100 104 Plantation Pipeline
Arkansas
South Little Rock....................... 100 273 TEPPCO Pipeline
North Little Rock....................... 100 179 TEPPCO Pipeline
Florida
Jacksonville............................ 100 252 Barge and ship
Georgia
Doraville............................... 100 295 Colonial and
Plantation Pipelines
Albany.................................. 79 124 Colonial Pipeline
Missouri
St. Charles............................. 100 118 Explorer Pipeline
North Carolina
Charlotte............................... 100 334 Colonial Pipeline
Selma................................... 79 305 Colonial Pipeline
Greensboro.............................. 60 248 Colonial Pipeline
Greensboro.............................. 79 239 Colonial and
Plantation Pipelines
Charlotte............................... 79 158 Colonial Pipeline
South Carolina
North Augusta........................... 79 156 Colonial Pipeline
North Augusta........................... 100 123 Colonial Pipeline
Spartanburg............................. 100 116 Colonial Pipeline
Tennessee
Nashville............................... 50 252 Colonial Pipeline and
barge
Nashville............................... 100 164 Colonial Pipeline
Nashville............................... 79 148 Colonial Pipeline
Knoxville............................... 100 115 Colonial and
Plantation Pipelines
Chattanooga............................. 100 105 Colonial Pipeline
Texas
Dallas.................................. 100 400 Explorer and Magtex
Pipelines and
pipeline to Dallas
Love Field owned by
us
Southlake............................... 50 277 Explorer, Koch and
UDS Pipelines
Virginia
Montvale................................ 79 171 Colonial Pipeline
Richmond................................ 79 169 Colonial Pipeline
-----
Total........................... 4,960
=====
6
Our inland terminals are equipped with automated loading facilities that
are available 24 hours a day. The Williams Companies, Inc.'s proprietary ATLAS
2000 software system allows us to manage inventory across our inland terminal
network and bill our customers electronically. The ATLAS system provides our
customers with the ability to manage, among other things, inventory allocations,
throughput and carrier certification from remote locations. Our customers can
access the ATLAS system via the internet. Under our omnibus agreement, The
Williams Companies, Inc. and its affiliates have licensed the use of the ATLAS
2000 software system to us. See Item 13 -- Certain Relationships and Related
Transactions.
Customers and Contracts. All but four of our inland terminals were
acquired by The Williams Companies, Inc. over a period of five years, beginning
with the acquisition of interests in eight terminals in 1996. When The Williams
Companies, Inc. acquired the new terminals, it generally entered into long-term
throughput contracts with the sellers under which they agreed to continue to use
the facilities. These agreements typically last for two to ten years from the
beginning of the agreement, and must be renegotiated at the end of the term. In
addition to these agreements, we enter into separate contracts with new
customers that typically last for one year with a continuing one year renewal
provision. Most of these contracts contain a minimum throughput provision that
obligates the customer to move a minimum amount of product through our terminals
or pay for terminal capacity reserved but not used. Our customers include:
- retailers that sell gasoline and other petroleum products through
proprietary retail networks;
- wholesalers that sell petroleum products to retailers as well as to large
commercial and industrial end-users;
- exchange transaction customers, where we act as an intermediary so that
the parties to the transaction are able to exchange petroleum products;
and
- traders that arbitrage, trade and market products stored in our
terminals.
For the year ended December 31, 2001, Williams Refining & Marketing, L.L.C.
accounted for approximately 38 percent of our inland terminal revenues. For a
further discussion of revenues from major customers and concentration of credit
risk, refer to Note 6 to the Consolidated Financial Statements. For additional
information relating to our commercial agreements with The Williams Companies,
Inc. and its affiliates, please read "Management's Discussion & Analysis of
Financial Condition and Results of Operations -- Related Party Transactions,"
which begins on page 31.
Markets and Competition. We compete with other independent terminal
operators as well as integrated oil companies on the basis of terminal location
and versatility, services provided and price. Our competition from independent
operators primarily comes from distribution companies with marketing and trading
arms, independent terminal operators and refining and marketing companies.
AMMONIA PIPELINE AND TERMINALS SYSTEM
We own and operate a 1,100-mile pipeline and terminals system. Our pipeline
transports 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. The ammonia we
transport is primarily used as a nitrogen fertilizer. Nitrogen is an essential
nutrient for plant growth and is the single most important element for
maintenance of high crop yields for all grains. Unlike other primary nutrients,
however, nitrogen must be applied each year because virtually all of its
nutritional value is consumed during the growing season. Ammonia is the most
cost-effective source of nitrogen and the simplest nitrogen fertilizer. It is
also the primary feedstock for the production of upgraded nitrogen fertilizers
and chemicals.
Although ammonia consumption peaks in the fall and early spring, ammonia
production is reasonably consistent throughout the year. Generally, storage
facilities reach their peak storage capacities during early spring, prior to
agricultural application. As a result, we experience only limited seasonal
fluctuations for transportation services on our pipeline. Our customers inject
the ammonia they produce into our pipeline, and we transport it as a liquid to
terminal facilities and storage and upgrade facilities located in the Midwest.
7
Ammonia is produced by reacting natural gas with air at high temperatures
and pressures in the presence of catalysts. Because natural gas is the primary
feedstock for the production of ammonia, ammonia is typically produced near
abundant sources of natural gas. Natural gas prices were significantly higher
than historical levels between 1999 and the first six months of 2001. As a
result, our customers substantially curtailed their production of ammonia and
shipped lower volumes of ammonia on our pipeline. However, our shippers have
committed to minimum shipping agreements of an aggregate of 700,000 tons per
year through June 2005.
Operations. We are a common carrier transportation pipeline and terminals
company. We do not produce or trade ammonia, and we do not take title to the
ammonia we transport. Rather, we earn revenue from the following sources:
- transportation tariffs for the use of our pipeline capacity; and
- throughput fees at our six company-owned terminals.
We generate approximately 94 percent of our revenue through transportation
tariffs. These tariffs are postage stamp tariffs, which means that each shipper
pays a defined rate per ton of ammonia shipped regardless of the distance that
ton of ammonia travels on our pipeline. In addition to transportation tariffs,
we also earn revenue by charging our customers for services at the six terminals
we own, including unloading ammonia from our customers' trucks to inject it into
our pipeline for shipment and removing ammonia from our pipeline to load it into
our customers' trucks.
Facilities. Our pipeline was the world's first common carrier pipeline for
ammonia. The main trunk line was completed in 1968. Today, it represents one of
two ammonia pipelines operating in the United States and has a maximum annual
delivery capacity of approximately 900,000 tons. Our ammonia pipeline system
originates at production facilities in Borger, Texas, Verdigris, Oklahoma and
Enid, Oklahoma and terminates in Mankato, Minnesota.
We transport ammonia to 13 delivery points along our pipeline system. The
facilities at these points provide our customers with the ability to deliver
ammonia to distributors who sell the ammonia to farmers and to store ammonia for
future use. These facilities also provide our customers with the ability to
remove ammonia from our pipeline for distribution to upgrade facilities that
produce complex nitrogen compounds such as urea, ammonium nitrate, ammonium
phosphate and ammonium sulfate.
Customers and Contracts. We ship ammonia for three customers:
- Farmland Industries, Inc., one of the largest farmer-owned cooperatives
in the United States;
- Agrium U.S. Inc., a subsidiary of Agrium Inc., the largest producer of
nitrogen fertilizers in North America; and
- Terra Nitrogen, L.P., a wholesaler of nitrogen fertilizer products.
Each of these companies has an ammonia production facility connected to our
pipeline as well as related storage and distribution facilities along the
pipeline. The transportation contracts with our customers extend through June
2005. Our customers are obligated to ship an aggregate minimum of 700,000 tons
per year and have historically shipped an amount in excess of the required
minimum. Our customers have been shipping ammonia through our pipeline for an
average of more than 20 years.
Each transportation contract contains a ship or pay mechanism, whereby each
customer must ship a specific minimum tonnage per year and an aggregate minimum
tonnage over the life of the contract. On July 1 of each contract year, each of
our customers nominates a tonnage that it expects to ship during the upcoming
year. This annual commitment may be equal to or greater than the contractual
minimum tonnage.
Currently, our customers' annual commitments represent 78 percent of our
pipeline's 900,000 ton per year capacity. If a customer fails to ship its annual
commitment, that customer must pay for the pipeline capacity it did not use.
In general, our customers have historically shipped ammonia in excess of
their annual commitments. We allow our customers to bank any ammonia shipped in
excess of their annual commitments. If a customer has
8
previously shipped an amount in excess of its annual commitment, the shipper may
offset subsequent annual shipment shortfalls against the excess tonnage in its
bank. There are approximately 115,000 tons in this combined bank that may be
used to offset future ship or pay obligations.
The transportation contracts establish a fixed tariff schedule per ton of
ammonia shipped for each customer for the first five years of the contract
period. Because of the long-term nature of these contracts, the shippers receive
a volume incentive tariff per ton that decreases with increased commitments.
Since July 1, 2000, we have had the right to adjust our tariff schedule on an
annual basis pursuant to a formula contained in the contracts. The adjustment
formula takes into consideration the cost of labor, power, property taxes and
changes in the producer price index. We use the combined increase or decrease in
these factors to calculate any increases or decreases in tariffs. Any annual
adjustment is limited to a maximum increase or decrease of five percent measured
against the rate previously in effect. These tariff adjustments cannot decrease
the tariffs to rates less than those charged in 1997.
Two of our three customers have credit ratings below investment grade. For
a further discussion of revenues from major customers and concentrations of
credit risk, refer to Note 6 of the Consolidated Financial Statements.
Markets and Competition. Demand for nitrogen fertilizer has typically
followed a combination of weather patterns and growth in population, acres
planted and fertilizer application rates. Because natural gas is the primary
feedstock for the production of ammonia, the profitability of our customers is
impacted by high natural gas prices. To the extent our customers are unable to
pass on higher costs to their customers, they may reduce shipments through our
pipeline.
We compete primarily with ammonia shipped by rail carriers, but we believe
we have a distinct advantage over rail carriers because ammonia is a gas under
normal atmospheric conditions and must be either placed under pressure or cooled
to -33 degrees Celsius to be shipped or stored. Because the transportation and
storage of ammonia requires specialized handling, we believe that pipeline
transportation is the safest and most cost-effective method for transporting
bulk quantities of ammonia.
We also compete to a limited extent in the areas served by the far northern
segment of our ammonia pipeline and terminals system with the other United
States ammonia pipeline, which originates on the Gulf Coast and transports
domestically produced and imported ammonia.
TARIFF REGULATION
Interstate Regulation
The Surface Transportation Board, a part of the United States Department of
Transportation, has jurisdiction over interstate pipeline transportation of
ammonia. The Surface Transportation Board succeeded the Interstate Commerce
Commission which previously regulated pipeline transportation of ammonia.
The Surface Transportation Board is responsible for rate regulation of
pipeline transportation of commodities other than water, gas or oil. These
transportation rates must be reasonable, and a pipeline carrier may not
unreasonably discriminate among its shippers. If the Surface Transportation
Board finds that a carrier's rates violate these statutory commands, it may
prescribe a reasonable rate. In determining a reasonable rate, the Surface
Transportation Board will consider, among other factors, the effect of the rate
on the volumes transported by that carrier, the carrier's revenue needs and the
availability of other economic transportation alternatives.
The Surface Transportation Board does not need to provide rate relief
unless shippers lack effective competitive alternatives. If the Surface
Transportation Board determines that effective competitive alternatives are not
available and a pipeline holds market power, then it must determine whether the
pipeline rates are reasonable. The Board generally applies constrained market
pricing principles in its economic analysis. Constrained market pricing provides
two alternative methodologies for examining the reasonableness of a carrier's
rates. The first approach examines a carrier's existing system to determine
whether the carrier is already earning sufficient funds to cover its costs and
provide a sufficient return on investment, or would earn
9
sufficient funds after eliminating unnecessary costs from specifically
identified inefficiencies and cross-subsidies in its operations. The second
approach calculates the revenue requirements that a hypothetical, new and
optimally efficient carrier would need to meet in order to serve the complaining
shippers.
Customers that protest rates in Surface Transportation Board proceedings
may use any methodology they choose that is consistent with constrained market
pricing principles. When addressing revenue adequacy, a complainant must provide
more than a single period snapshot of a carrier's costs and revenues. The
complainant must measure whether a carrier earns adequate revenues over a period
of time, as measured by a multi-period discounted cash flow analysis.
The Surface Transportation Board has held that unreasonable discrimination
occurs when (1) there is a disparity in rates, (2) the complaining party is
competitively injured, (3) the carrier is the common source of both the
allegedly prejudicial and preferential treatment and (4) the disparity in rates
is not justified by transportation conditions.
Intrastate Regulation
Because in some instances we transport ammonia between two terminals in the
same state, our pipeline operations are subject to regulation by the state
regulatory authorities in Iowa, Nebraska, Oklahoma and Texas. Although the
Oklahoma Corporation Commission and the Texas Railroad Commission have the
authority to regulate our rates, the state commissions have generally not
investigated the rates or practices of ammonia pipelines in the absence of
shipper complaints.
SAFETY AND MAINTENANCE
We monitor our marine terminals, inland terminals and ammonia pipeline and
terminals system on a regular basis to ensure reliability, safety and efficiency
of our assets. We believe that our assets have been constructed and are
maintained in all material respects in accordance with applicable federal, state
and local laws, including, where applicable, the regulations of the Department
of Transportation, and accepted industry standards.
ENVIRONMENTAL
General
Our operation of terminals and associated facilities in connection with the
storage and transportation of crude oil and other liquid hydrocarbons, together
with our operation of an ammonia pipeline, are subject to stringent and complex
laws and regulations governing the discharge of materials into the environment
or otherwise relating to environmental protection. As an owner or lessee and
operator of these facilities, we must comply with these laws and regulations at
the federal, state and local levels. As with the industry generally, our
compliance with existing and anticipated laws and regulations increases the cost
of planning, constructing and operating our terminals, pipeline and other
facilities. Included in our construction and operation costs are cost items
necessary to maintain or upgrade our equipment and facilities. Failure to comply
with these laws and regulations may result in the assessment of administrative,
civil and criminal penalties, imposition of remedial actions and issuance of
injunctions or construction bans or delays on ongoing operations. We believe
that our operations are in material compliance with applicable environmental
laws and regulations. However, these laws and regulations are subject to
frequent change and we cannot provide assurance that the cost to comply with
these laws and regulations in the future will not have a material adverse effect
on our financial position or results of operations.
Indemnification
Williams Energy Services, LLC has agreed to indemnify us for up to $15.0
million for environmental liabilities that exceed the amounts covered by the
seller indemnities and insurance coverage described below. The indemnity applies
to environmental liabilities arising from conduct prior to February 9, 2001 and
10
discovered within three years of February 9, 2001. Liabilities resulting from a
change in law after February 9, 2001 are excluded from this indemnity.
In accordance with our acquisition agreement with Amerada Hess Corporation,
Hess will indemnify us for environmental and other liabilities related to the
three Gulf Coast marine terminals we acquired from them in August 1999,
including:
- Indemnification for specified cleanup actions of pre-acquisition releases
of hazardous substances. This indemnity is capped at a maximum of $15.0
million. Hess, however, has no liability until the aggregate amount of
initial losses is in excess of a $2.5 million deductible, and then Hess
is liable only for the succeeding $12.5 million in losses. This indemnity
will remain in effect until July 30, 2004.
- Indemnification for already known and required cleanup actions at the
Corpus Christi, Texas and Galena Park, Texas terminals. This indemnity
has no limit and will remain in effect until July 30, 2014.
- Indemnification for a variety of pre-acquisition fines and claims that
may be imposed or asserted under the Superfund Law and federal Resource
Conservation and Recovery Act ("RCRA") or analogous state laws. This
indemnity is not subject to any limit or deductible amount.
In addition to these indemnities, Hess retained liability for the
performance of corrective actions associated with a cooling tower at the Corpus
Christi, Texas terminal and a vapor recovery unit and process safety management
compliance matter at the Galena Park, Texas terminal.
We have insurance against the first $2.5 million of environmental
liabilities related to the Hess terminals that arose prior to closing of the
acquisition from Hess, with a deductible of $0.3 million, and any environmental
liabilities in excess of $15.0 million up to an aggregate of $50.0 million.
In connection with the acquisition of the New Haven, Connecticut marine
terminal facility acquired from Wyatt Energy, Incorporated and the acquisitions
of our inland terminals, the sellers of those terminals agreed to indemnify us
against specified environmental liabilities. We also have insurance until August
31, 2005 for up to $25.0 million of environmental liabilities for the New Haven
marine terminal facility, with a deductible of $0.3 million.
Hazardous Substances and Wastes
In most instances, the environmental laws and regulations affecting our
operations relate to the release of hazardous substances or solid wastes into
the water or soils, and include measures to control pollution of the
environment. For instance, the Comprehensive Environmental Response,
Compensation and Liability Act, also known as the Superfund law, and comparable
state laws impose liability, without regard to fault or the legality of the
original conduct, on certain classes of persons who are considered to be
responsible for the release of a hazardous substance into the environment. These
persons include the owner or operator of the disposal site or sites where the
release occurred and companies that disposed or arranged for the disposal of the
hazardous substances. Under the Superfund law, these persons may be subject to
joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment, for damages to natural
resources and for the costs of certain health studies. The Superfund law also
authorizes the Environmental Protection Agency, or EPA, and in some instances,
third parties to act in response to threats to the public health or the
environment and to seek to recover from the responsible classes of persons the
costs they incur. It is not uncommon for neighboring landowners and other third
parties to file claims for personal injury and property damage allegedly caused
by hazardous substances or other pollutants released into the environment. In
the course of our ordinary operations, we may generate waste that falls within
the Superfund law's definition of a hazardous substance and as a result, we may
be jointly and severally liable under the Superfund law for all or part of the
costs required to clean up sites at which those hazardous substances have been
released into the environment.
Our operations also generate wastes, including hazardous wastes, that are
subject to the requirements of the RCRA and comparable state statutes. We are
not currently required to comply with a substantial portion of the RCRA
requirements because our operations routinely generate only small quantities of
hazardous
11
wastes, and we do not hold ourselves out as a hazardous waste treatment, storage
or disposal facility operator that is required to obtain a RCRA hazardous waste
permit. While RCRA currently exempts a number of wastes, including many oil and
gas exploration and production wastes, from being subject to hazardous waste
requirements, the EPA from time to time will consider the adoption of stricter
disposal standards for non-hazardous wastes. Moreover, it is possible that
additional wastes, which could include non-hazardous wastes currently generated
during operations, will in the future be designated as hazardous wastes.
Hazardous wastes are subject to more rigorous and costly storage and disposal
requirements than are non-hazardous wastes. Changes in the regulations could
have a material adverse effect on our capital expenditures or operating
expenses.
We currently own or lease properties where hydrocarbons are being or have
been handled for many years. Although we have utilized operating and disposal
practices that were standard in the industry at the time, hydrocarbons or other
wastes may have been disposed of or released on, under or from the properties
owned or leased by us or on or under other locations where these wastes have
been taken for disposal. In addition, many of these properties have been
operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under our control. These properties and
wastes disposed thereon may be subject to the Superfund law, RCRA and analogous
state laws. Under these laws, we could be required to remove or remediate
previously disposed wastes, including wastes disposed of or released by prior
owners or operators, to clean up contaminated property, including groundwater
contaminated by prior owners or operators, or to make capital improvements to
prevent future contamination.
We are currently evaluating soil and groundwater conditions at a number of
our properties where historical operations conducted primarily by former site
owners or operators or more recent operations conducted by us may have resulted
in releases of hydrocarbons or other wastes. These investigations and possible
cleanup activities are either under consideration or already have been or will
be initiated at our petroleum products terminals in Mobile, Alabama; New Haven,
Connecticut; Doraville and South Albany, Georgia; Gibson, Louisiana; St.
Charles, Missouri; Greensboro and Selma, North Carolina; North Augusta, South
Carolina; Nashville, Tennessee; Dallas and Galena Park, Texas; and Montvale and
Richmond, Virginia. Similar operations are also being conducted at an ammonia
terminal facility in Early, Iowa and along our ammonia pipeline in Valley,
Nebraska and Noble County, Oklahoma. We expect to conduct a number of these
investigatory and cleanup activities at an estimated cost of $5.4 million, and
we have recognized a liability for that amount. Of that liability, $5.1 million
is expected to be recoverable from affiliates or third parties pursuant to
contractual requirements. In other instances, prior owners or operators of these
properties are performing or are expected to perform these activities pursuant
to contractual requirements that make these prior owners or operators
responsible for performing the activities.
Aboveground Storage Tanks
States in which we operate typically have laws and regulations governing
above ground tanks containing liquid substances. Generally, these laws and
regulations require that these tanks include secondary containment systems or
that the operators take alternative precautions to ensure that no contamination
results from any leaks or spills from the tanks. Although there is not currently
a federal statute dedicated to regulating these above ground tanks, there is a
possibility that a law could one day be passed in the United States. We believe
we are in material compliance with all applicable above ground storage tank laws
and regulations. As part of our assessment of facility operations, we have
identified some above ground tanks at our terminals in Charlotte and Selma,
North Carolina and Nashville, Tennessee that either are, or are suspected of
being, coated with lead-based paints. The removal and disposal of any paints
that are found to be lead-based, whenever such activities are conducted in the
future as part of our day-to-day maintenance activities, will require increased
handling by us. However, we do not expect the costs associated with this
increased handling to be significant. We believe that the future implementation
of above ground storage tank laws or regulations will not have a material
adverse effect on our financial condition or results of operations.
12
Water Discharges
Our operations can result in the discharge of pollutants, including oil.
The Oil Pollution Act was enacted in 1990 and amends provisions of the Federal
Water Pollution Control Act of 1972 or the Water Pollution Control Act and other
statutes as they pertain to prevention and response to oil spills. The Oil
Pollution Act subjects owners of facilities to strict, joint and potentially
unlimited liability for removal costs and certain other consequences of an oil
spill such as natural resource damages, where the spill is into navigable
waters, along shorelines or in the exclusive economic zone of the United States.
In the event of an oil spill from one of our facilities into navigable waters,
substantial liabilities could be imposed upon us. States in which we operate
have also enacted similar laws. Regulations have been or are being developed
under the Oil Pollution Act and comparable state laws that may also impose
additional regulatory burdens on our operations. We have determined that the
secondary containment surrounding above ground tanks at our Galena Park, Texas,
terminal requires upgrading to comply with the law, at an estimated cost of $0.1
million. We do not expect these expenditures to have a material adverse effect
on our financial condition or results of operations.
The Federal Water Pollution Control Act imposes restrictions and strict
controls regarding the discharge of pollutants into navigable waters. This law
and comparable state laws require that permits be obtained to discharge
pollutants into state and federal waters and impose substantial potential
liability for the costs of noncompliance and damages. Where required, we hold
discharge permits that were issued under the Federal Water Pollution Control Act
or a state-delegated program, and we believe that we are in material compliance
with the terms of those permits. While we have experienced permit discharge
exceedances at our terminals in Selma, North Carolina and North Augusta, South
Carolina, we are resolving these exceedances by electing to make capital
improvements to the wastewater handling system at Selma at an estimated cost of
$0.1 million and by discontinuing wastewater discharges at the North Augusta
terminal. In addition, similar capital expenditures to improve wastewater
handling systems are expected to be made to comply with applicable laws at our
terminal in Galena Park, Texas, at an estimated cost of $0.4 million. We do not
expect our compliance with existing permits and foreseeable new permit
requirements, nor any of the estimated capital expenditures to upgrade or
replace existing wastewater handling systems to have a material adverse effect
on our financial position or results of operations.
Air Emissions
Our operations are subject to the federal Clean Air Act and comparable
state and local laws. Under such laws, permits are typically required to emit
pollutants into the atmosphere. Amendments to the federal Clean Air Act enacted
in 1990, as well as recent or soon to be proposed changes to state
implementation plans, or SIPs, for controlling air emissions in regional,
non-attainment areas require or will require most industrial operations in the
United States to incur capital expenditures in order to meet air emission
control standards developed by the EPA and state environmental agencies. As a
result of these amendments, our facilities that emit volatile organic compounds
or nitrogen oxides are subject to increasingly stringent regulations, including
requirements that some sources install maximum or reasonably available control
technology. In addition, the amendments include an operating permit for major
sources of volatile organic compounds, which applies to some of our facilities.
We also expect that changes to the state implementation plans pertaining to air
quality in regional, non-attainment areas will have an impact on our terminals
in Doraville, Georgia and Galena Park and Dallas, Texas, possibly resulting in
the need to upgrade air pollution control equipment. We believe that we
currently hold or have applied for all necessary air permits and that we are in
material compliance with applicable air laws and regulations. Nevertheless, we
anticipate making capital improvements involving modification or repair of roofs
and seals on certain of our tanks at Galena Park, Texas and Corpus Christi,
Texas to comply with applicable law, at a total estimated cost of $0.5 million.
In addition, we previously received a notice of violation for air permitting
issues relating to operation of a vapor recovery unit at our terminal in Galena
Park, Texas. The alleged violation commenced while the property was operated by
Hess and continued after The Williams Companies, Inc.'s acquisition of the
property. In order to optimize our vapor recovery compliance, we have acquired a
vapor combustion unit which is in the final stages of testing. If any penalties
are imposed on us as a result of the assessed notice of violation that relates
to ownership or operation of the vapor recovery unit, then Hess has agreed to
reimburse us for costs arising prior to December 19, 2000.
13
Although we can give no assurances, we believe implementation of the 1990
federal Clean Air Act Amendments and any changes to the SIPs pertaining to air
quality in regional non-attainment areas will not have a material adverse effect
on our financial condition or results of operations.
EMPLOYEE SAFETY
We are subject to the requirements of the federal Occupational Safety and
Health Act, or OSHA, and comparable state statutes that regulate the protection
of the health and safety of workers. In addition, the OSHA hazard communication
standard requires that certain information be maintained about hazardous
materials used or produced in operations and that this information be provided
to employees, state and local government authorities and citizens. We believe
that our operations are in material compliance with OSHA requirements, including
general industry standards, record keeping requirements and monitoring of
occupational exposure to regulated substances.
TITLE TO PROPERTIES
Substantially all of our pipelines are constructed on rights-of-way granted
by the apparent record owners of this property. The rights-of-way for our
ammonia pipelines are shared with other pipelines owned by affiliates of The
Williams Companies, Inc. In some instances these rights-of-way are revocable at
the election of the grantor. In many instances, lands over which rights-of-way
have been obtained are subject to prior liens which have not been subordinated
to the right-of-way grants. In some cases, not all of the apparent record owners
have joined in the right-of-way grants. We have obtained permits from public
authorities to cross over or under, or to lay facilities in or along water
courses, county roads, municipal streets and state highways, and in some
instances, these permits are revocable at the election of the grantor. We have
also obtained permits from railroad companies to cross over or under lands or
rights-of-way, many of which are also revocable at the grantor's election. In
some cases, property for pipeline purposes was purchased in fee. We have the
right of eminent domain to acquire rights-of-way and lands necessary for our
ammonia pipeline. However, the original owner of the pipeline may not have
concluded eminent domain proceedings for some rights-of-way.
Some of the leases, easements, rights-of-way, permits and licenses
transferred to us, upon the completion of our initial public offering in
February 2001, required the consent of the grantor to transfer these rights,
which in some instances is a governmental entity. We have obtained substantially
all required third-party consents, permits and authorizations sufficient for the
transfer to us of the assets necessary for us to operate our business in all
material respects. Failure to obtain such consents, permits or authorizations
should not have a material adverse effect on the operation of our business.
We have sufficient title to all of our assets subject to the limitations
described in this section, or we are entitled to indemnification from affiliates
of The Williams Companies, Inc. for right-of-way defects or failures under the
omnibus agreement. Although title to these properties is subject to encumbrances
in some cases, such as customary interests generally retained in connection with
acquisition of real property, liens related to environmental liabilities
associated with historical operations, liens for current taxes and other burdens
and minor easements, restrictions and other encumbrances to which the underlying
properties were subject at the time of acquisition by our predecessor or us,
none of these burdens should materially detract from the value of our properties
or from our interest in them or materially interfere with their use in the
operation of our business.
EMPLOYEES
To carry out our operations, our general partner or its affiliates employ
approximately 195 people who provide direct support to our operations. Other
than at our Galena Park marine terminal facility, none of these employees are
represented by labor unions. The employees at our Galena Park marine terminal
facility are currently represented by a union, but have indicated their
unanimous desire to terminate their union affiliation. Nevertheless, the
National Labor Relations Board has ordered us to bargain with the union as the
exclusive collective bargaining representative of the employees at the facility.
We are appealing this decision. If our
14
appeal is unsuccessful, we will bargain with the union as ordered by the
National Labor Relations Board. Our general partner considers its employee
relations to be good.
FORWARD-LOOKING STATEMENTS
Certain matters discussed in this report, excluding historical information,
include forward-looking statements -- statements that discuss our expected
future results based on current and pending business operations. We make these
forward-looking statements in reliance on the safe harbor protections provided
under the Private Securities Litigation Reform Act of 1995.
Forward-looking statements can be identified by words such as anticipates,
believes, expects, planned, scheduled or similar expressions. Although we
believe these forward-looking statements are based on reasonable assumptions,
statements made regarding future results are subject to numerous assumptions,
uncertainties and risks that may cause future results to be materially different
from the results stated or implied in this document.
The following are among the important factors that could cause actual
results to differ materially from any results projected, forecasted, estimated
or budgeted:
- Changes in demand for refined petroleum products that we store and
distribute;
- Changes in demand for storage in our petroleum product terminals;
- Changes in the throughput on petroleum product pipelines owned and
operated by third parties and connected to our petroleum product
terminals;
- Loss of Williams Energy Marketing & Trading and/or Williams Refining &
Marketing, L.L.C. as customers;
- Loss of one or all of our three customers on our ammonia pipeline and
terminals system;
- An increase in the price of natural gas, which increases ammonia
production costs and reduces the amount of ammonia transported through
our ammonia pipeline and terminals system;
- Changes in the federal government's policy regarding farm subsidies,
which negatively impact the demand for ammonia and reduce the amount of
ammonia transported through our ammonia pipeline and terminals system;
- An increase in the competition our petroleum products terminals and
ammonia pipeline and terminals system encounter;
- The occurrence of an operational hazard or unforeseen interruption for
which we are not adequately insured;
- Changes in general economic conditions in the United States;
- Changes in laws and regulations to which we are subject, including tax,
environmental and employment laws and regulations;
- The cost and effects of legal and administrative claims and proceedings
against us or our subsidiaries;
- The ability to raise capital in a cost-effective way;
- The effect of changes in accounting policies;
- The ability to manage rapid growth;
- The ability to control costs;
- Supply disruption; and
- Global and domestic economic repercussions from terrorist activities and
the government's response thereto.
15
(d) FINANCIAL INFORMATION ABOUT GEOGRAPHICAL AREAS
We have no revenue or segment profit or loss attributable to international
activities.
ITEM 2. PROPERTIES
See Item 1(c) for a description of the locations and general character of
our material properties.
ITEM 3. LEGAL PROCEEDINGS
We are a party to various legal actions that have arisen in the ordinary
course of our business. We do not believe that the resolution of these matters
will have a material adverse effect on our financial condition or results of
operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the unitholders, through
solicitation of proxies or otherwise, during the fiscal year covered by this
report.
16
PART II
ITEM 5.MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common units are listed on the New York Stock Exchange under the symbol
"WEG". At the close of business on February 28, 2002, we had 51 holders of
record of our common units. The high and low closing sales price ranges
(composite transactions) and distributions declared by quarter for 2001 since
the close of our initial public offering on February 9, 2001 are as follows:
2001
--------------------------------
QUARTER HIGH LOW DISTRIBUTIONS*
------- ------ ------ --------------
1st.................................................... $31.00 $23.00 $.2920
2nd.................................................... $33.42 $28.45 $.5625
3rd.................................................... $40.40 $29.40 $.5775
4th.................................................... $44.00 $37.00 $.5900
---------------
* Distributions declared associated with each respective quarter. Distributions
were declared and paid within 45 days following the close of each quarter. The
distribution for the first quarter of 2001 was pro-rated for the period from
February 10, 2001 through March 31, 2001.
We have also issued subordinated units, all of which are held by two
affiliates of our general partner, for which there is no established public
trading market.
During the subordination period, the holders of our common units are
entitled to receive each quarter a minimum quarterly distribution of $0.525 per
unit ($2.10 annualized) prior to any distribution of available cash to holders
of our subordinated units. The subordination period is defined generally as the
period that will end on the first day of any quarter beginning after December
31, 2005 if (1) we have distributed at least the minimum quarterly distribution
on all outstanding units with respect to each of the immediately preceding three
consecutive, non-overlapping four-quarter periods and (2) our adjusted operating
surplus, as defined in our partnership agreement, during such periods equals or
exceeds the amount that would have been sufficient to enable us to distribute
the minimum quarterly distribution on all outstanding units on a fully diluted
basis and the related distribution on the 2 percent general partner interest
during those periods. In addition, one-quarter of the subordinated units may
convert to common units on a one-for-one basis after December 31, 2003 and
one-quarter of the subordinated units may convert to common units on a
one-for-one basis after December 31, 2004 if we meet the tests set forth in our
partnership agreement. If the subordination period ends, the rights of the
holders of subordinated units will no longer be subordinated to the rights of
the holders of common units and the subordinated units may be converted into
common units.
During the subordination period, our cash is distributed first 98 percent
to the holders of common units and 2 percent to our general partner until there
has been distributed to the holders of common units an amount equal to the
minimum quarterly distribution and arrearages in the payment of the minimum
quarterly distribution on the common units for any prior quarter. Any additional
cash is distributed 98 percent to the holders of subordinated units and 2
percent to our general partner until there has been distributed to the holders
of subordinated units an amount equal to the minimum quarterly distribution.
Our general partner is entitled to incentive distributions if the amount we
distribute with respect to any quarter exceeds specified target levels shown
below:
PERCENTAGE OF DISTRIBUTIONS
-----------------------------
QUARTERLY DISTRIBUTION AMOUNT PER UNIT UNITHOLDERS GENERAL PARTNER
-------------------------------------- ----------- ---------------
Up to $.578................................................. 98 2
Above $.578 up to $.656..................................... 85 15
Above $.656 up to $.788..................................... 75 25
Above $.788................................................. 50 50
17
We must distribute all of our cash on hand at the end of each quarter, less
reserves established by our general partner. We refer to this cash as available
cash as defined in our partnership agreement. The amount of available cash may
be greater than or less than the minimum quarterly distribution. We currently
pay quarterly cash distributions of $0.59 per unit. In general, we intend to
continue to pay comparable cash distributions in the future assuming no adverse
change in our operations, economic conditions and other factors. We cannot
guarantee that future distributions, if any, will continue at such levels.
USE OF PROCEEDS
On February 5, 2001, our Registration Statement on Form S-1 (Registration
No. 333-48866) with the Securities and Exchange Commission became effective. The
managing underwriter for this transaction was Lehman Brothers Inc. Under the
registration statement, we issued 5,679,694 common units and 5,679,694
subordinated units, of which 1,679,694 common units and all of the subordinated
units were issued to affiliates of our general partner.
The closing date of our initial public offering was February 9, 2001, and
on that date we sold 4,000,000 common units to the public at a price of $21.50
per unit, or $86.0 million. Underwriter commissions on this sale were $5.6
million. In addition, concurrent with the closing of the initial public
offering, we borrowed $90.1 million under a credit facility with Bank of America
and incurred $0.9 million of debt issuance costs. Subsequent to the initial
public offering, the underwriters exercised in full their over-allotment option
and purchased an additional 600,000 common units for $12.9 million. Underwriter
commissions on this sale were $0.8 million. The aggregate offering price of the
common units (including the over-allotment) was $98.9 million.
Net proceeds from the sale of common units, after underwriter commissions,
were $92.5 million, and net proceeds from the borrowings under the credit
facility with Bank of America were $89.2 million, for total net proceeds of
$181.7 million. We used $3.1 million of the net proceeds to pay legal,
accounting and other professional services costs associated with the initial
public offering. Another $12.1 million of the proceeds was used to redeem
600,000 common units from Williams Energy Services, LLC, an affiliate of our
general partner, to partially reimburse it for capital expenditures related to
our assets. This partial reimbursement related to Williams Energy Services,
LLC's September 2000 acquisition of a petroleum products terminal facility in
New Haven, Connecticut from Wyatt Energy Incorporated for approximately $30.8
million. The remaining proceeds of $166.5 million were used to reduce affiliate
note balances with Williams.
18
ITEM 6.
SELECTED FINANCIAL AND OPERATING DATA
(IN THOUSANDS, EXCEPT OPERATING STATISTICS AND PER UNIT AMOUNTS)
The historical financial information presented below for Williams Energy
Partners L.P. was derived from our audited consolidated financial statements as
of December 31, 2001 and 2000 and for the three years ended December 31, 2001.
These financial data are an integral part of, and should be read in conjunction
with, the consolidated financial statements and notes thereto. 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 on pages 20 through 33 of this report.
YEAR ENDED DECEMBER 31,
---------------------------------------------------
2001 2000 1999 1998 1997
-------- -------- --------- ------- -------
INCOME STATEMENT DATA:
Operating revenues....................... $ 86,054 $ 72,492 $ 44,388 $20,846 $19,526
Operating expenses....................... 37,314 33,489 18,635 7,618 7,176
Depreciation and amortization............ 11,748 9,333 4,610 1,190 1,100
General and administrative............... 8,955 11,963 5,458 3,950 4,603
-------- -------- --------- ------- -------
Total costs and expenses............ $ 58,017 $ 54,785 $ 28,703 $12,758 $12,879
-------- -------- --------- ------- -------
Operating profit......................... $ 28,037 $ 17,707 $ 15,685 $ 8,088 $ 6,647
Interest expense (income)(a)............. 6,932 12,827 4,775 (1,371) (1,149)
Minority interest expense................ 229 -- -- -- --
Other (income) expense, net.............. (1,058) 33 -- 27 (41)
-------- -------- --------- ------- -------
Income before income taxes............... $ 21,934 $ 4,847 $ 10,910 $ 9,432 $ 7,837
Income taxes............................. 187 1,842 4,144 3,589 2,920
-------- -------- --------- ------- -------
Net income............................... $ 21,747 $ 3,005 $ 6,766 $ 5,843 $ 4,917
======== ======== ========= ======= =======
Basic and diluted net income per limited
partner unit........................... $ 1.87
========
BALANCE SHEET DATA:
Working capital.......................... $ 4,098 $ 7,380 $ 9,240 $24,997 $24,890
Working capital less affiliate note
receivable(b).......................... 4,098 7,380 9,240 203 1,262
Total assets............................. 399,444 318,505 283,339 73,002 65,316
Long-term debt........................... 139,500 -- -- -- --
Affiliate long-term note payable(b)...... -- 226,188 197,165 -- --
Partners' capital........................ 224,910 69,856 66,851 60,085 54,242
CASH FLOW DATA:
Net cash flow provided by (used in):
Operating activities................ $ 42,508 $ 15,635 $ 5,659 $ 8,844 $ 9,279
Investing activities................ (63,270) (41,749) (237,733) (8,844) (9,279)
Financing activities................ 34,593 26,114 232,074 -- --
Cash distributions declared per
unit(c)................................ $ 2.02
OTHER DATA:
Operating margin:
Petroleum product terminals............ $ 38,240 $ 31,286 $ 17,141 $ 3,599 $ 3,568
Ammonia pipeline and terminals
system.............................. 10,500 7,717 8,612 9,629 8,782
EBITDA(d)................................ 40,614 27,007 20,295 9,251 7,788
Maintenance capital...................... 9,211 7,474 2,236 1,666 1,472
Maintenance capital to be reimbursed to
Partnership by affiliate............... (3,929) -- -- -- --
19
YEAR ENDED DECEMBER 31,
---------------------------------------------------
2001 2000 1999 1998 1997
-------- -------- --------- ------- -------
OPERATING STATISTICS:
Petroleum product terminals:
Marine terminal average storage
capacity utilized per month
(million barrels)(e).............. 15.7 14.7 10.1 N/A N/A
Marine terminal throughput (million
barrels)(f)....................... 11.5 3.7 N/A N/A N/A
Inland terminal throughput (million
barrels).......................... 56.7 56.1 58.1 26.8 21.3
Ammonia pipeline and terminals system:
Volume shipped (thousand tons)...... 763 713 795 896 893
---------------
(a) From 1999 to February 9, 2001, interest income and expense was allocated to
the terminal and ammonia operations based upon their actual affiliate note
receivable or payable balance. After February 9, 2001, interest expense is
based on our outstanding debt balance.
(b) Management believes that excluding the affiliate note receivable, but not
the affiliate accounts receivable, from working capital provides a more
appropriate comparative representation of working capital. The affiliate
note receivable and payable result from our long-term involvement in
Williams' cash management program. The notes were due on demand; however,
in February 2001, we borrowed $90.1 million under a credit facility, which
expires in February 2004 and issued 4,000,000 common units in our
Partnership in an initial public offering for net proceeds, after
underwriter commissions, of $80.4 million. An additional 600,000 common
units were sold subsequent to the initial public offering when the
underwriters exercised their over-allotment option. Net proceeds of $12.1
million from this sale were used to redeem 600,000 common units held by
Williams Energy Services, LLC to reimburse it for capital expenditures
related to our assets. The remaining affiliate note payable was contributed
to us as a capital contribution by an affiliate of Williams. As a result,
the affiliate note payable at December 31, 2000 and 1999, have been
classified as long-term.
(c) Cash distributions declared for 2001 include a pro-rated distribution for
the first quarter which included the period from February 10, 2001 through
March 31, 2001. The cash distribution associated with the fourth quarter of
2001 was declared on January 22, 2002 and paid on February 14, 2002.
(d) EBITDA is defined as earnings before interest expense, income taxes and
depreciation and amortization expense.
(e) For the year ended December 31, 1999, represents the average storage
capacity utilized per month for the Gulf Coast marine terminals for the
five months that we owned these assets in 1999. For the year ended December
31, 2000, represents the twelve month average storage capacity utilized for
the Gulf Coast facilities (11.8 million barrels) and the four months that
we owned the New Haven, Connecticut facility in 2000 (2.9 million barrels).
For the year ended December 31, 2001, represents the average storage
capacity utilized for the Gulf Coast facilities (12.7 million barrels) and
the New Haven, Connecticut facility (3.0 million barrels).
(f) For the year ended December 31, 2000, represents activity at the New Haven,
Connecticut facility, which was acquired in September 2000. 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, Louisiana facility (2.2 million barrels), which was acquired on
October 31, 2001.
20
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
Williams Energy Partners L.P. is a Delaware limited partnership formed by
The Williams Companies, Inc. in August 2000 to own, operate and acquire a
diversified portfolio of complementary energy assets. We are principally engaged
in the storage, transportation and distribution of refined petroleum products
and ammonia. Our current asset portfolio consists of:
- five marine terminal facilities;
- 25 inland terminals (some of which are partially owned); and
- an ammonia pipeline and terminals system.
Most of these assets were acquired and owned by several wholly-owned
subsidiaries of The Williams Companies, Inc. prior to our initial public
offering ("IPO"). Upon the closing of our initial public offering on February 9,
2001, these assets were transferred to Williams Energy Partners L.P., including
the related liabilities. The following discussion has been prepared as if the
assets were operated as a stand-alone business throughout the periods presented.
OVERVIEW
Our marine terminal facilities, which are large product storage facilities,
generate revenues primarily from fees that we charge customers for storage and
throughput services. Our inland terminals earn revenues primarily from fees that
we charge based on the volumes of refined petroleum products distributed from
our terminals. Our inland terminals also earn ancillary revenues from injecting
additives into gasoline and jet fuel, from filtering jet fuel and from rental
income. Also included in ancillary revenues is the gain or loss resulting from
differences in metered-versus-physical volumes of refined petroleum products
received at our terminals. Our ammonia pipeline and terminals system earns the
majority of its revenue from transportation tariffs that we charge for
transporting ammonia through our pipeline.
Operating costs and expenses 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 fuel and power, fluctuate with storage
capacity or throughput levels. Generally, most of the operating costs for our
ammonia pipeline and terminals system fluctuate with the volume of ammonia
transported through our pipeline.
The Williams Companies, Inc. allocates both indirect and direct general and
administrative expenses to its subsidiaries. Indirect expenses, including legal,
accounting, treasury, engineering, information technology and other corporate
services, are based on a calculation that compares a combination of operating
margins, payroll costs and property, plant and equipment to The Williams
Companies, Inc. and its subsidiaries. Historically, the amount of indirect
general and administrative expenses allocated to us increased as the relative
size of our operations compared to The Williams Companies, Inc.'s operations
increased. Direct expenses allocated by The Williams Companies, Inc. are
primarily salaries and benefits of employees, officers and directors associated
with the business activities of the subsidiary. We will reimburse our general
partner and its affiliates for indirect and direct expenses they incur on our
behalf. We agreed with our general partner, subject to future acquisitions or
other changes in the business, that the general and administrative expenses to
be reimbursed will not exceed $6.0 million for 2001, excluding expenses
associated with the Partnership's Long-Term Incentive Plan, even though the
direct and allocated general and administrative costs incurred by the general
partner were significantly higher. As a result of the acquisitions made during
2001, the amount of general and administrative expenses charged to us increased
to $6.3 million. Including the 7 percent escalation amount, the annual general
and administrative expense charge increased to $6.7 million beginning in January
2002.
21
We have little direct exposure to commodity price fluctuations since we do
not trade commodities. However, our operations can be indirectly affected by
overall price trends for the products we handle. During periods when the price
of a product is lower today than the price available through the forward pricing
market, the market for that product is said to be in "contango." A contango
market is favorable to our marine terminal facilities because this market
condition incentivizes customers to store product in the near term to take
advantage of expected higher future prices. Conversely, when the price of a
product today is higher than the price available through the forward pricing
market, the market is said to be "backwardated." In a backwardated market,
customers are less likely to store product because market conditions incentivize
them to sell as much product as possible to take advantage of higher current
prices. The forward pricing market for petroleum products became backwardated in
the second quarter of 1999 and remained so through second quarter 2001,
contributing to reduced storage revenues during that time. The market reversed
to contango during the latter half of 2001 and remained so through 2001,
contributing to increased storage revenues. We cannot predict whether the
current contango market will continue.
ACQUISITION HISTORY
We are principally engaged in the storage, transportation and distribution
of refined petroleum products and ammonia. We materially increased our
operations through a series of transactions, including:
- in December 2001, the acquisition of a natural gas liquids pipeline in
Illinois from Aux Sable Liquid Products L.P.;
- in October 2001, the acquisition of one marine crude oil terminal
facility located in Gibson, Louisiana from Geonet Gathering, Inc.;
- in June 2001, the acquisition of two inland refined petroleum product
terminals in Little Rock, Arkansas from TransMontaigne, Inc.;
- in April 2001, the acquisition of a refined petroleum product pipeline
located in Dallas, Texas from Equilon Pipeline Company LLC;
- in September 2000, the acquisition of one marine refined petroleum
product terminal facility located in New Haven, Connecticut from Wyatt
Energy, Incorporated;
- in March 2000, the acquisition of a 50.0 percent ownership interest in
one inland refined petroleum product terminal in Southlake, Texas from
CITGO Petroleum Corporation;
- in August 1999, the acquisition of three marine refined petroleum product
terminal facilities, located in Galena Park and Corpus Christi, Texas and
Marrero, Louisiana from Amerada Hess Corporation;
- in February 1999, the acquisition of an additional 10.0 percent interest
in eight inland refined petroleum product terminals located in Georgia,
North Carolina, South Carolina, Tennessee and Virginia from Murphy Oil
USA, Inc., which increased our ownership percentage in these terminals to
78.9 percent; and
- in January 1999, the acquisition of 12 inland refined petroleum product
terminals, located in Alabama, Florida, Mississippi, North Carolina,
Ohio, South Carolina and Tennessee from Amoco Oil Company.
22
RESULTS OF OPERATIONS
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
FINANCIAL HIGHLIGHTS
YEAR ENDED
DECEMBER 31,
-------------
2001 2000
----- -----
(MILLIONS)
Revenues:
Petroleum product terminals............................... $71.5 $60.8
Ammonia pipeline and terminals system..................... 14.6 11.7
----- -----
Total revenues......................................... 86.1 72.5
Operating expenses:
Petroleum product terminals............................... 33.3 29.5
Ammonia pipeline and terminals system..................... 4.0 4.0
----- -----
Total operating expenses............................... 37.3 33.5
----- -----
Total operating margin................................. $48.8 $39.0
===== =====
OPERATING STATISTICS
Petroleum product terminals:
Marine terminal facilities:
Average storage capacity utilized per month (barrels in
millions)(a).......................................... 15.7 14.7
Throughput (barrels in millions)(b).................... 11.5 3.7
Inland terminals:
Throughput (barrels in millions)....................... 56.7 56.1
Ammonia pipeline and terminals system:
Volume shipped (tons in thousands)........................ 763 713
---------------
(a) For the year ended December 31, 2000, represents the twelve-month average
storage capacity utilized for the Gulf Coast marine terminal facilities
(11.8) and the four months that we owned the New Haven, Connecticut
facility in 2000 (2.9). For the year ended December 31, 2001, represents
the average storage capacity utilized for the Gulf Coast facilities (12.7)
and the New Haven facility (3.0).
(b) For the year ended December 31, 2000, represents four months of activity at
the New Haven, Connecticut facility, which was acquired in September 2000.
For the year ended December 31, 2001, represents a full year of activity at
the New Haven facility (9.3) and two months of activity at the Gibson,
Louisiana facility (2.2), which was acquired on October 31, 2001.
Our combined revenues for the year ended December 31, 2001 were $86.1
million compared to $72.5 million for the year ended December 31, 2000, an
increase of $13.6 million, or 19 percent. This increase was a result of:
- an increase in petroleum product terminals revenues of $10.7 million, or
18 percent, due to the following:
- an increase in the marine terminal facilities revenues of $11.2 million,
from $44.1 million to $55.3 million. This increase reflects increased
volumes as a result of our acquisitions of the New Haven, Connecticut
facility in September 2000 and the Gibson, Louisiana facility in October
2001. In addition, the increase was due to a 0.9 million barrel per
month higher utilization at our Gulf Coast marine facilities due to an
improved marketing environment. Included in 2001 revenue is a $0.5
million decrease from $9.9 million in 2000 to $9.4 million in 2001 from
Williams Energy Marketing & Trading, an affiliate of our general
partner, which utilizes our facilities in connection with their trading
business; and
23
- a decrease in inland terminal revenues of $0.5 million, from $16.7
million to $16.2 million primarily due to the December 2000 expiration
of a customer's contractual commitment to utilize a specific amount of
throughput capacity. The customer contract that expired was executed in
January 1999 in conjunction with the acquisition of 12 inland terminals.
These revenue decreases were partially offset by additional revenues
from the acquisition of two inland terminals in Little Rock, Arkansas on
June 30, 2001. Included in this revenue is a $1.0 million decrease from
$7.5 million in 2000 to $6.5 million in 2001 from Williams Refining &
Marketing and Williams Energy Marketing & Trading; affiliates of our
general partner, which utilize our facilities in connection with their
trading business;
- an increase in ammonia pipeline and terminals system revenues of $2.9
million, or 25 percent. Part of the increase is due to a $1.3 million
throughput deficiency billing resulting from a shipper not meeting its
minimum annual throughput commitment for the contract year ended June
2001. However, favorable conditions were experienced primarily during the
fourth quarter of 2001 for the application of ammonia, resulting in a
50,000 ton, or 7 percent, increase in pipeline volume shipped compared to
2000. Unusually warm weather during the fall season resulted in higher
demand for ammonia application on agricultural fields. In addition, the
price of natural gas, the primary component for the production of
ammonia, declined to more historical levels, resulting in our customers
electing to produce and ship more ammonia through our pipeline to meet
increased demand and replenish inventories. Tariffs also increased by
$0.71 per ton, from a weighted-average tariff of $15.50 per ton for 2000
compared to a tariff of $16.21 per ton for 2001. The increase in the
weighted-average tariff resulted from the annual mid-year indexing
adjustments allowed under the transportation agreements.
Operating expenses for the year ended December 31, 2001 were $37.3 million
compared to $33.5 million for the year ended December 31, 2000, an increase of
$3.8 million, or 11 percent. This increase was a result of:
- an increase in petroleum product terminals expenses of $3.8 million, or
13 percent, due to:
- an increase in marine terminal facilities expenses of $3.0 million, from
$21.2 million to $24.2 million, primarily due to the acquisition and
assimilation of the New Haven, Connecticut facility which was acquired
in September 2000 and the Gibson, Louisiana facility which was acquired
in late October 2001. Expenses at the Gulf Coast facilities increased
slightly due to higher utility costs, partially offset by lower
environmental and maintenance expenses; and
- an increase in inland terminal expenses of $0.8 million, from $8.3
million to $9.1 million. Expenses primarily increased due to the
acquisition of the Little Rock, Arkansas terminals in June 2001 as well
as increased property taxes at some of our other inland terminal
locations;
- ammonia pipeline and terminals system operating costs were unchanged, as
reduced property taxes offset slightly higher environmental accruals.
Depreciation expense for the year ended December 31, 2001 was $11.7 million
compared to $9.3 million for the year ended December 31, 2000, an increase of
$2.4 million, or 26 percent. This increase primarily resulted from a full year
of depreciation related to the New Haven, Connecticut marine facility acquired
in September 2000, the acquisitions of the two Little Rock, Arkansas inland
terminals in June 2001 and the Gibson, Louisiana marine facility in October
2001.
General and administrative expenses for the year ended December 31, 2001
were $9.0 million compared to $12.0 million for the year ended December 31,
2000, a decrease of $3.0 million, or 25 percent. This decrease is a result of
the general and administrative expense limit of $6.0 million per year
established in the Omnibus Agreement at the time of the initial public offering.
General and administrative expense for the current year includes the established
limit plus additional general and administrative costs associated with
businesses acquired during 2001 and incentive compensation expenses related to
the Partnership's performance. Costs associated with the Long-Term Incentive
Plan were $2.0 million in 2001 and are specifically excluded from the $6.0
million annual general and administrative expense. The limit on general and
administrative expense that can be charged by our general partner to the
Partnership will continue to be adjusted in the future to
24
reflect inflation and additional direct general and administrative expenses
associated with completed acquisitions.
Interest expense for the year ended December 31, 2001 was $6.9 million
compared to $12.8 million for the year ended December 31, 2000. The decline in
interest was primarily related to the partial payment and cancellation of an
affiliate note in connection with the closing of the initial public offering of
Williams Energy Partners on February 9, 2001, and lower interest rates.
Concurrent with the closing of our offering, we borrowed $90.1 million under our
term loan facility and revolving credit facility. At the end of 2001, $90.0
million was still outstanding under the term loan as well as $49.5 million under
the revolving credit facility due to the acquisition of the Little Rock,
Arkansas terminals and the Gibson, Louisiana facility.
We do not pay income taxes because we are a partnership. We based our
income tax provision for the pre-initial public offering earnings upon the
effective income tax rate for The Williams Companies, Inc. for those periods of
38.0 percent. 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, 2001 was $21.7 million compared
to $3.0 million for the year ended December 31, 2000, an increase of $18.7
million, or 623 percent. Our operating margin increased by $9.8 million during
the period, primarily as a result of the acquisitions of the New Haven, Little
Rock and Gibson terminal facilities. Operating margin further increased due to
enhanced utilization of our Gulf Coast marine facilities and increased revenues
from our ammonia pipeline and terminals system. While depreciation increased by
$2.4 million, general and administrative expenses and interest declined by $8.9
million. In addition, other income of $1.0 million was reported to recognize the
gain on the sale of the Meridian, Mississippi inland terminal in October 2001.
Minority interest expense increased by $0.2 million but income taxes declined by
$1.6 million as a result of the Partnership not paying taxes after the initial
public offering closing on February 9, 2001.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
FINANCIAL HIGHLIGHTS
YEAR ENDED
DECEMBER 31,
-------------
2000 1999
----- -----
(MILLIONS)
Revenues:
Petroleum product terminals............................... $60.8 $32.3
Ammonia pipeline and terminals system..................... 11.7 12.1
----- -----
Total revenues......................................... 72.5 44.4
Operating expenses:
Petroleum product terminals............................... 29.5 15.1
Ammonia pipeline and terminals system..................... 4.0 3.5
----- -----
Total operating expenses............................... 33.5 18.6
----- -----
Total operating margin................................. $39.0 $25.8
===== =====
OPERATING STATISTICS
Petroleum product terminals:
Marine terminal facilities:
Average storage capacity utilized per month (barrels in
millions)(a).......................................... 14.7 10.1
Throughput (barrels in millions)(b).................... 3.7 N/A
Inland terminals:
Throughput (barrels in millions)....................... 56.1 58.1
Ammonia pipeline and terminals system:
Volume shipped (tons in thousands)........................ 713 795
---------------
(a) For the year ended December 31, 1999, represents the average storage
capacity utilized per month for the Gulf Coast marine terminal facilities
for the five months that we owned these assets in 1999. For the year
25
ended December 31, 2000, represents the twelve-month average storage
capacity utilized for the Gulf Coast facilities (11.8) and the four months
that we owned the New Haven, Connecticut facility in 2000 (2.9).
(b) Represents four months of activity at the New Haven, Connecticut facility,
which was acquired in September 2000.
Our combined revenues for the year ended December 31, 2000 were $72.5
million compared to $44.4 million for the year ended December 31, 1999, an
increase of $28.1 million, or 63 percent. This increase was a result of:
- an increase in petroleum product terminals revenues of $28.5 million, or
88 percent, due to the following:
- an increase in the marine terminal facilities revenues of $28.3 million,
from $15.8 million to $44.1 million. This increase reflects increased
volumes as a result of our acquisition of the Gulf Coast facilities in
August 1999, a 1.7 million barrel per month increase in utilization of
the Gulf Coast facilities and the acquisition of the New Haven,
Connecticut facility in September 2000. Slightly offsetting these
increases was a storage revenue rate decline at the Gulf Coast
facilities of approximately $.015 per barrel as a result of a revenue
deficiency billing associated with the purchase of the Gulf Coast
terminal facilities from Amerada Hess ending in July 2000. Included in
the 2000 revenue is a $7.5 million increase from $2.4 million in 1999 to
$9.9 million in 2000 from Williams Energy Marketing & Trading, an
affiliate of our general partner, which utilizes our facilities in
connection with its trading business; and
- an increase in inland terminal revenues of $0.2 million, from $16.5
million to $16.7 million, as increased ancillary revenues more than
offset reduced throughput revenues resulting from a decline in
throughput volumes of 2.0 million barrels. Our throughput volume
decreased primarily because of the gradual reduction, beginning in
January 2000, of a customer's contractual commitment to utilize a
specific amount of throughput capacity. This contract was entered into
in January 1999 in connection with our acquisition of 12 inland
terminals. This volume reduction was partially offset by a volume
increase resulting from the Southlake, Texas terminal acquisition in
March 2000 and increased marketing activity by Williams Energy Marketing
& Trading. Included in this revenue is a $3.0 million increase from $4.5
million in 1999 to $7.5 million in 2000 from Williams Energy Marketing &
Trading.
- ammonia pipeline and terminals system revenues declined by $0.4 million,
or 3 percent, primarily due to a 82,000 ton, or 10 percent, reduction of
ammonia shipped through our pipeline. This decline was due to lower
product demand as well as the continuing impact of higher prices for
natural gas, the primary component for the production of ammonia. Wet
weather during the 2000 spring planting season resulted in reduced farm
demand for ammonia. Further, due to higher natural gas prices, our
customers elected to produce and transport lower quantities of ammonia
and to draw more ammonia from their existing inventories to meet demand.
This volume decline was partially offset by a higher weighted average
tariff of $15.50 per ton for 2000 compared to a tariff of $14.74 per ton
for 1999. The increase in the weighted average tariff resulted from the
2000 mid-year indexing adjustment allowed under the transportation
agreements as well as the expiration of a discount received by one of our
customers.
Operating expenses for the year ended December 31, 2000 were $33.5 million
compared to $18.6 million for the year ended December 31, 1999, an increase of
$14.9 million, or 80 percent. This increase was a result of:
- an increase in petroleum product terminals expenses of $14.4 million, or
95 percent, due to:
- an increase in marine terminal facilities expenses of $15.2 million,
from $6.0 million to $21.2 million, due to the acquisition and
assimilation of the Gulf Coast facilities, which were acquired in August
1999 and the New Haven, Connecticut facility which was acquired in
September 2000; and
26
- a decrease in inland terminal expenses of $0.8 million, from $9.1
million to $8.3 million, primarily resulting from a decrease in
environmental expenses associated with a system-wide environmental
evaluation in 1999, decreases in employee relocation expenses associated
with 12 terminals acquired in 1999 and a decrease in utility expenses as
a result of lower throughput volumes. These reductions were slightly
offset by increased costs related to our Southlake, Texas terminal
acquired in March, 2000;
- ammonia pipeline and terminals system operating costs increased $0.5
million, or 14 percent, primarily due to increased utility costs as a
result of higher natural gas prices.
Depreciation expense for the year ended December 31, 2000 was $9.3 million
compared to $4.6 million for the year ended December 31, 1999, an increase of
$4.7 million, or 102 percent. This increase primarily resulted from a full year
of depreciation related to the Gulf Coast marine facilities acquired in August
1999 and the acquisition of the New Haven, Connecticut marine facility in
September 2000.
General and administrative expenses for the year ended December 31, 2000
were $12.0 million compared to $5.5 million for the year ended December 31,
1999, an increase of $6.5 million, or 118 percent. This increase resulted
principally from the acquisition of the Gulf Coast marine facilities and the New
Haven, Connecticut marine facility. As a result of these acquisitions, the
percentage increase of our asset growth was greater than the percentage increase
of the growth in assets of The Williams Companies, Inc. and its subsidiaries.
Therefore, The Williams Companies, Inc. allocated more general and
administrative expenses to us.
Affiliate interest expense for the year ended December 31, 2000 was $12.8
million compared to $4.8 million for the year ended December 31, 1999. A
significant portion of this increase can be attributed to carrying twelve months
of debt in 2000 related to the acquisition of the Gulf Coast marine facilities
in August 1999 and the acquisition of the New Haven, Connecticut facility in
September 2000.
We based our income tax provision for 2000 and 1999 upon the effective
income tax rate for The Williams Companies, Inc. for those periods of 38.0
percent. 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, 2000 was $3.0 million compared
to $6.8 million for the year ended December 31, 1999, a decrease of $3.8
million, or 56 percent. While the operating margin increased by $13.2 million
during the period, this was more than offset by an $11.2 million increase in
depreciation and general and administrative expenses and an $8.0 million
increase in interest expense, all of which are principally a result of the
acquisitions of the Gulf Coast and New Haven, Connecticut marine terminal
facilities in August 1999 and September 2000, respectively. In addition, income
tax expense decreased $2.2 million due to the decline in earnings in 2000 as
compared to 1999.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows and Capital Expenditures
Net cash provided by operating activities for the year ended December 31,
2001 was $42.5 million compared to $15.6 million for the year ended December 31,
2000 and $5.7 million for the year ended December 31, 1999. The increase from
2000 to 2001 was primarily attributable to increased net income before
depreciation and deferred compensation costs. Acquisitions and enhanced
operations of our initial assets increased operating margins significantly. In
addition, our initial public offering in 2001 resulted in reduced general and
administrative costs and interest expense as well as the elimination of income
taxes. The increase from 1999 to 2000 was primarily attributable to a reduction
in the account receivable due from our affiliate, Williams Energy Marketing &
Trading. During this period, acquisitions also added significantly to operating
margins, but these increases were offset by an increase in general and
administrative expense allocations, higher depreciation and increased interest
expense.
Net cash used by investing activities for the years ended December 31,
2001, 2000 and 1999 was $63.3 million, $41.7 million and $237.7 million,
respectively. We increased capital expenditures during these
27
years primarily to make acquisitions of petroleum product terminals. In 2001, we
acquired two inland terminals in Little Rock, Arkansas and a marine terminal
facility in Gibson, Louisiana. In 2000, we acquired one inland terminal and the
New Haven, Connecticut marine terminal facility. In 1999, we acquired 12 inland
terminals, the Gulf Coast marine facilities and an additional ownership interest
in eight existing inland terminals.
Net cash provided by financing activities for the years ended December 31,
2001, 2000 and 1999 was $34.6 million, $26.1 million and $232.1 million,
respectively. The cash flow for 2001 is primarily comprised of proceeds from our
equity and debt proceeds at the time of our initial public offering and $49.5
million associated with additional borrowings for the acquisitions of the Little
Rock, Arkansas terminals and Gibson, Louisiana marine terminal facility. The
1999 and 2000 amounts represent loans received from The Williams Companies, Inc.
to fund our terminal acquisitions.
Capital Requirements
The storage, transportation 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
business have consisted, and we expect them to continue to consist, primarily
of:
- maintenance capital expenditures, such as those required to maintain
equipment reliability and safety and to address environmental
regulations; and
- expansion capital expenditures to acquire additional complementary assets
to grow our business and to expand or upgrade our existing facilities,
such as projects that increase storage or throughput volumes.
According to the Omnibus Agreement between Williams Energy Partners L.P.
and The Williams Companies, Inc., Williams will reimburse us for maintenance
capital in excess of $4.9 million per year during 2001 and 2002 on the assets
initially included in the initial public offering up to a combined maximum
reimbursement of $15.0 million. We incurred $3.9 million of maintenance capital
costs in 2001 in excess of the $4.9 million limit agreed to with Williams. We
received reimbursement of $2.0 million of these during 2001, with the remaining
$1.9 million reimbursement made in January 2002. The total amount we expect to
spend on maintenance capital for these assets in 2002 will exceed $4.9 million.
As a result, Williams will continue to make capital contributions to Williams
Energy Partners L.P. during 2002. In addition to maintenance capital, we are
also planning to incur expansion and upgrade capital expenditures at our
existing facilities, including pipeline connections. The total amount we plan to
spend for expansion is approximately $11.0 million in 2002, not including
capital needs associated with acquisition opportunities. We expect to fund our
capital expenditures, including any acquisitions, from cash provided by
operations and, to the extent necessary, from the proceeds of:
- borrowings under the revolving credit facility discussed below and other
borrowings; and
- issuance of additional common units.
If capital markets tighten and we are unable to fund these expenditures,
our business may be adversely affected and we may not be able to acquire
additional assets and businesses.
Liquidity
Subsequent to the closing of our initial public offering on February 9,
2001, we have relied on cash generated from internal operations as our primary
source of funding. To review the risks associated with our cash flows generated
from operations, refer to Risks Related to our Business discussed beginning on
page 30. Additional funding requirements are being served by a $175.0 million
credit facility that expires on February 5, 2004. This credit facility is
comprised of a $90.0 million term loan and an $85.0 million revolving credit
facility. The revolving credit facility is comprised of a $73.0 million
acquisition sub-facility and a $12.0 million working capital sub-facility.
Immediately after the closing of the offering, our Partnership borrowed the
entire $90.0 million term loan and $0.1 million under the revolving credit
facility. As of December 31, 2001, $23.5 million was available
28
under the acquisition sub-facility after borrowing $49.5 million to fund the
Little Rock, Arkansas and Gibson, Louisiana acquisitions. Borrowings for the Aux
Sable transaction occurred during January 2002. In addition, $12.0 million was
available under the working capital sub-facility at December 31, 2001.
The credit facility contains various operational and financial covenants.
Management believes that we are in compliance with all of these covenants.
ENVIRONMENTAL
Our operations are subject to environmental laws and regulations adopted by
various governmental authorities in the jurisdictions in which these operations
are conducted. We have accrued liabilities for estimated site restoration costs
to be incurred in the future at our facilities and properties, including
liabilities for environmental remediation obligations at various sites where we
have been identified as a potentially responsible party. Under our accounting
policies, liabilities are recorded when site restoration and environmental
remediation and cleanup obligations are either known or considered probable and
can be reasonably estimated.
In conjunction with our initial public offering, Williams Energy Services,
LLC, a subsidiary of The Williams Companies, Inc., agreed to indemnify us
against any covered environmental losses, up to $15.0 million, relating to
assets it contributed to Williams Energy Partners L.P. that arose prior to
February 9, 2001, that become known within three years after February 9, 2001
and that exceed all amounts recovered or recoverable by us under contractual
indemnities from third parties or under any applicable insurance policies.
As of December 31, 2001 we had accrued environmental liabilities of $5.4
million. Management estimates that these expenditures for environmental
remediation liabilities will be paid over the next five to ten years.
Receivables associated with environmental liabilities of $5.1 million have been
recognized as recoverable from affiliates and third parties.
IMPACT OF INFLATION
Although the impact of inflation has slowed in recent years, it is still a
factor in the United States economy and may increase the cost to acquire or
replace property, plant and equipment and may increase the costs of labor and
supplies. To the extent permitted by competition, regulation and our existing
agreements, we have and will continue to pass along increased costs to our
customers in the form of higher fees.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results could differ from
those estimates. We deem the following accounting policies to be critical:
- Revenues are recognized in the month that services are rendered. Changes
in the available tankage for storage and demand for petroleum and
anhydrous ammonia products could have a material impact on our revenues.
- Depreciation expense is calculated based on management's best estimate of
the remaining useful lives of our assets. Because of the expected long
useful lives of our assets, we depreciate terminals and pipelines over a
30-year to 67-year period for financial statement purposes. Changes in
the estimated lives of our assets could have a material effect on results
of operations.
- Incentive compensation expense is recorded for the restricted unit
compensation program for Williams' employees who directly support the
Partnership. The expense associated with the one-time initial public
offering award is based on the price of the units on the date of grant.
The expense associated with the annual incentive compensation plan is
computed based on the estimated number of units that will ultimately vest
adjusted by the current market value of the units at each period end. The
Partnership is accruing costs for these units based on management's
estimate that the maximum
29
number of units will vest. Any changes in those assumptions would result
in lower compensation expense to the Partnership.
- Environmental liabilities are recorded when site restoration,
environmental remediation and cleanup obligations are either known or
considered probable and can be reasonably estimated. Environmental
liabilities are recorded independently of any potential claim for
recovery. Receivables are recognized in cases where reimbursements for
remediation costs are considered probable. During 2001, we recorded a
$2.6 million environmental liability associated with our New Haven
facility. The amount of the liability was based on third-party
engineering estimates developed as part of our Phase II environmental
assessment, required by the State of Connecticut. This environmental
liability could change materially upon finalization of the more
comprehensive Phase III assessment, scheduled to be completed in the
summer of 2002. This environmental liability is covered by the
Partnership's indemnifications from Williams Energy Services, LLC up to a
maximum amount of $15.0 million; hence, any adjustments to the liability
should not impact the Partnership's results of operations.
- With the adoption of Statement of Financial Accounting Standards No. 142,
goodwill will no longer be amortized beginning January 1, 2002 but will
be tested periodically for impairment. Management's judgments and
assumptions relative to estimating the future cash flows of our various
assets will be critical in determining whether an impairment exists and,
if so, the financial impact of such impairment. Changes in market
conditions, customers and/or industry financial conditions, technology
and other factors could materially impact the future assessment of
goodwill values, which could have a material impact on our results of
operations, financial condition and cash flows.
NEW ACCOUNTING PRONOUNCEMENTS
In August 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets." This Statement supersedes SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of" and amends Accounting Principles Board Opinion No. 30,
"Reporting the Results of Operations -- Reporting the Effects of Disposal of a
Segment of a Business and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions." The Statement retains the basic framework of SFAS No.
121, resolves certain implementation issues of SFAS No. 121, extends
applicability to discontinued operations and broadens the presentation of
discontinued operations to include a component of an entity. The Statement is to
be applied prospectively and is effective for financial statements issued for
fiscal years beginning after December 15, 2001. The Statement is not expected to
have any initial impact on our results of operations or financial position.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This Statement addresses financial accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs and amends FASB Statement No.
19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The
Statement requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made and that the associated asset retirement
costs be capitalized as part of the carrying amount of the long-lived asset. The
Statement is effective for financial statements issued for fiscal years
beginning after June 15, 2002. We plan to adopt this standard in January 2003,
and we are evaluating its effect on our results of operations and financial
position.
In June 2001, the FASB issued SFAS No. 141, "Business Combinations" and
SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 establishes
accounting and reporting standards for business combinations and requires all
business combinations to be accounted for by the purchase method. The Statement
is effective for all business combinations for which the date of acquisition is
July 1, 2001 or later. SFAS No. 142 addresses accounting and reporting standards
for goodwill and other intangible assets. Under this Statement, goodwill and
intangible assets with indefinite useful lives will no longer be amortized but
will be tested annually for impairment. The Statement becomes effective for all
fiscal years beginning after December 15, 2001. We will apply the new rules on
accounting for goodwill and other intangible assets
30
beginning January 1, 2002. Based on the amount of goodwill recorded as of
December 31, 2001, application of the non-amortization provision of the
Statement will result in a decrease to amortization expense in future years of
approximately $1.1 million.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This was followed in June 2000 by the
issuance of SFAS No. 138, "Accounting for Certain Derivative Instruments and
Certain Hedging Activities," which amends SFAS No. 133. SFAS No. 133 and No. 138
establish accounting and reporting standards for derivative financial
instruments. The standards require that all derivative financial instruments be
recorded on the balance sheet at their fair value. Changes in fair value of
derivatives will be recorded each period in earnings if the derivative is not a
hedge. If a derivative qualifies for special hedge accounting, changes in the
fair value of the derivative will either be recognized in earnings as an offset
against the change in fair value of the hedged assets, liabilities or firm
commitments also recognized in earnings, or the changes in fair value will be
deferred on the balance sheet until the hedged item is recognized in earnings.
The ineffective portion of a derivative's change in fair value will be
recognized immediately in earnings. These standards were adopted on January 1,
2001. There was no impact to our financial position, results of operations or
cash flows from adopting these standards.
The FASB issued SFAS No. 140, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities." The Statement provides
guidance for determining whether a transfer of financial assets should be
accounted for as a sale or a secured borrowing and whether a liability has been
extinguished. The Statement is effective for recognition and reclassification of
collateral and for disclosures ending after December 15, 2000. The Statement
became effective for transfers and servicing of financial assets and
extinguishments of liabilities occurring after March 31, 2001. The initial
application of SFAS No. 140 had no impact on our results of operations and
financial position.
RELATED PARTY TRANSACTIONS
We estimate that approximately $15.9 million of our revenues in 2001 were
generated from agreements with affiliates. Williams Energy Marketing & Trading
Company and Williams Refining & Marketing, L.L.C., subsidiaries of The Williams
Companies, Inc. and affiliates of us, are significant customers at our petroleum
products terminals, representing 11.0 percent and 7.2 percent, respectively, of
our total revenues for the year ended December 31, 2001. The principal business
of Williams Energy Marketing & Trading Company is energy marketing and trading.
Williams Refining & Marketing L.L.C. primarily owns and operates a refinery in
Memphis, Tennessee, but also engages in the purchase and sale of crude and
refined petroleum products. We have entered into a number of commercial
agreements with affiliates. These agreements vary depending upon location and
the types of services provided. A summary of the significant agreements follows:
Inland Terminal Use and Access Agreements. We have entered into several
agreements with Williams Energy Marketing & Trading and William Refining &
Marketing for the access and utilization of our inland terminals. The services
provided under these agreements include the receipt and delivery of refined
petroleum products via connecting pipelines, tank trucks or transport terminals.
Additional services include product handling, storage and additive injection.
These agreements establish a fixed fee at which these services are provided at
the rates consistent with those charged to non-affiliated entities. A majority
of these contracts have a term of one year and are renewed on an annual basis.
The revenue associated with these agreements in 2001 was approximately $6.5
million.
Products Terminalling Agreement for our Galena Park, Texas Marine Terminal
Facility. We entered into an agreement with Williams Energy Marketing & Trading
to provide approximately 2.5 million barrels of storage capacity and to provide
other ancillary services at our Galena Park, Texas marine terminal facility.
Because the storage fees are fixed and the storage capacity is already
committed, revenues only fluctuate to the extent other ancillary services are
utilized. The primary services provided include receipt and delivery of refined
petroleum products and blendstocks via marine vessel, pipeline, tank truck or
other transfers from customers within the terminal facility. Upon the request of
Williams Energy Marketing & Trading, we provide gasoline-blending services to
their product at an additional cost. The prices we charge under this agreement
are consistent with those charged to non-affiliated entities. The agreement
generated approximately $7.4 mil-
31
lion of revenue in 2001 and extends until September 30, 2004, at which time it
may be renewed monthly.
Products Terminalling Agreement for Marrero, Louisiana and Galena Park,
Texas Marine Terminal Facilities. We entered an agreement with Williams Energy
Marketing & Trading to provide up to 0.4 million barrels of storage at our
Marrero and 0.1 million barrels of storage capacity at Galena Park. We also
agreed to provide other ancillary services including blending and tank heating
services. The primary services provided include receipt and delivery of refined
petroleum products and blendstocks at Galena Park and heavy oils and feedstocks
at Marrero. The prices charged under this agreement are consistent with those
charged to non-affiliated entities. The agreement generated approximately $1.4
million of revenue during 2001. This contract has been canceled and replaced
with the contract described immediately above.
Products Terminalling Agreement for the Gibson, Louisiana Marine Terminal
Facility. We entered an agreement to provide Williams Energy Marketing & Trading
with capacity utilization rights to substantially all of the capacity of the
Gibson, Louisiana facility for nine years starting November 1, 2001. This
agreement allows for the delivery of crude oil and condensate to our facility by
barge, truck and pipeline where we then provide storage, blending and throughput
services. We ship the majority of the crude oil and condensate received through
our pipelines to Ship Shoal Pipeline. Williams Energy Marketing & Trading has
committed to utilize substantially all of the capacity at our facility at a
fixed rate which is consistent with rates charged by other service providers for
similar services at other locations. As a result, the revenues we receive should
not vary as long as the services we provide do not fall below certain
performance standards. This contract expires after nine years and we expect to
generate approximately $4.0 million in revenue in 2002. This contract generated
approximately $0.6 million in revenue for the two months that we owned the
facility in 2001.
ENRON EXPOSURE
We have a crude storage contract with an affiliate of Enron. Following
Enron's voluntary bankruptcy petition, the Enron affiliate failed to pay
approximately $200,000 of the amount due to us under this contract. Under the
terms of our agreement, we seized assets from Enron's affiliate in an amount
sufficient to settle the obligation. As a result, we did not incur any loss
exposure associated with Enron or its affiliates at December 31, 2001. We have
continued our business dealings with Enron's affiliate but the terms have been
changed such that the crude storage services are on a pre-paid basis.
Through a variety of energy commodity and derivative contracts, our
affiliate Williams Energy Marketing & Trading has credit exposure to various
Enron entities. During the fourth-quarter 2001, Williams Energy Marketing &
Trading recorded a reduction in trading revenues of approximately $130 million
as a part of its valuation of energy commodity and derivative tracking contracts
with Enron entities. Approximately $91 million of this reduction in revenues was
recorded pursuant to events immediately preceding and following Enron's
announced bankruptcy. At December 31, 2001, The Williams Companies, Inc. had
reduced its exposure to accounts receivable from Enron, net of margin deposits,
to expected recoverable amounts.
RISKS RELATED TO OUR BUSINESS
WE MAY NOT BE ABLE TO GENERATE SUFFICIENT CASH FROM OPERATIONS TO ALLOW US TO
PAY THE MINIMUM QUARTERLY DISTRIBUTION FOLLOWING ESTABLISHMENT OF CASH RESERVES
AND PAYMENT OF FEES AND EXPENSES, INCLUDING PAYMENTS TO OUR GENERAL PARTNER.
The amount of cash we can distribute on our common units principally
depends upon the cash we generate from our operations. Because the cash we
generate from operations will fluctuate from quarter to quarter, we may not be
able to pay the minimum quarterly distribution for each quarter. Our ability to
pay the minimum quarterly distribution each quarter depends primarily on cash
flow, including cash flow from financial reserves and working capital
borrowings, and not solely on profitability, which is affected by non-cash
items. As a result, we may make cash distributions during periods when we record
losses and may not make cash distributions during periods when we record net
income.
32
POTENTIAL FUTURE ACQUISITIONS AND EXPANSIONS, IF ANY, MAY AFFECT OUR BUSINESS BY
SUBSTANTIALLY INCREASING THE LEVEL OF OUR INDEBTEDNESS AND CONTINGENT
LIABILITIES AND INCREASING OUR RISKS OF BEING UNABLE TO EFFECTIVELY INTEGRATE
THESE NEW OPERATIONS.
From time to time, we evaluate and acquire assets and businesses that we
believe complement our existing assets and businesses. Acquisitions may require
substantial capital or the incurrence of substantial indebtedness. If we
consummate any future acquisitions, our capitalization and results of operations
may change significantly, and you will not have the opportunity to evaluate the
economic, financial and other relevant information that we will consider in
determining the application of these funds and other resources.
Acquisitions and business expansions involve numerous risks, including
difficulties in the assimilation of the assets and operations of the acquired
businesses, inefficiencies and difficulties that arise because of unfamiliarity
with new assets and the businesses associated with them and new geographic areas
and the diversion of management's attention from other business concerns.
Further, unexpected costs and challenges may arise whenever businesses with
different operations or management are combined, and we may experience
unanticipated delays in realizing the benefits of an acquisition. Following an
acquisition, we may discover previously unknown liabilities associated with the
acquired business for which we have no recourse under applicable indemnification
provisions.
OUR FINANCIAL RESULTS DEPEND ON THE DEMAND FOR THE REFINED PETROLEUM PRODUCTS
THAT WE STORE AND DISTRIBUTE.
Any sustained decrease in demand for refined petroleum products in the
markets served by our terminals could result in a significant reduction in the
volume of products that we store at our marine terminal facilities and in the
throughput in our inland terminals, and therefore reduce our cash flow and our
ability to pay cash distributions to you. Factors that could lead to a decrease
in market demand include:
- an increase in the market price of crude oil that leads to higher refined
product prices, which may reduce demand for gasoline and other petroleum
products. Market prices for refined petroleum products are subject to
wide fluctuation in response to changes in global and regional supply
over which we have no control;
- a recession or other adverse economic condition that results in lower
spending by consumers and businesses on transportation fuels such as
gasoline, jet fuel and diesel;
- higher fuel taxes or other governmental or regulatory actions that
increase the cost of gasoline;
- an increase in fuel economy, whether as a result of a shift by consumers
to more fuel-efficient vehicles or technological advances by
manufacturers; and
- the increased use of alternative fuel sources, such as fuel cells and
solar, electric and battery-powered engines. Several state and federal
initiatives mandate this increased use.
WHEN PRICES FOR THE FUTURE DELIVERY OF PETROLEUM PRODUCTS THAT WE STORE IN OUR
MARINE TERMINALS FALL BELOW CURRENT PRICES, CUSTOMERS ARE LESS LIKELY TO STORE
THESE PRODUCTS, THEREBY REDUCING OUR STORAGE REVENUES.
This market condition is commonly referred to as "backwardation." When the
petroleum product market is in backwardation, the demand for storage capacity at
our marine terminal facilities may decrease. The forward pricing market for
petroleum products moved to backwardation in the second quarter of 1999 and
continued for a majority of 2000. This market condition contributed to reduced
storage revenues in 1999 and 2000. In 2001, the forward pricing market remained
backwardated during the first half of the year, reversing during the latter half
of 2001. If this market becomes strongly backwardated for an extended period of
time, it may affect our ability to pay cash distributions to you.
WE DEPEND ON PETROLEUM PRODUCT PIPELINES OWNED AND OPERATED BY OTHERS TO SUPPLY
OUR TERMINALS.
Most of our inland and marine terminal facilities depend on connections
with petroleum product pipelines owned and operated by third parties. Reduced
throughput on these pipelines because of testing, line repair, damage to
pipelines, reduced operating pressures or other causes could result in our being
unable to deliver
33
products to our customers from our terminals or receive products for storage and
could adversely affect our ability to pay cash distributions to you.
COLLECTIVELY, OUR AFFILIATES WILLIAMS ENERGY MARKETING & TRADING AND WILLIAMS
REFINING & MARKETING ARE OUR LARGEST CUSTOMER, AND ANY REDUCTION IN THEIR USE OF
OUR TERMINAL FACILITIES COULD REDUCE OUR ABILITY TO PAY CASH DISTRIBUTIONS TO
YOU.
For the year ended December 31, 2001, our affiliates Williams Energy
Marketing & Trading and Williams Refining & Marketing collectively accounted for
approximately 18 percent of our revenues. If Williams Energy Marketing & Trading
and Williams Refining & Marketing were to decrease the throughput volume they
allocate to our terminals for any reason, we could experience difficulty in
replacing those lost volumes. Because our operating costs are primarily fixed, a
reduction in throughput would result in not only a reduction of revenues, but
also a decline in net income and cash flow of a similar magnitude, which would
reduce our ability to pay cash distributions to you. Either Williams Energy
Marketing & Trading or Williams Refining & Marketing could reduce the volume of
throughput it allocates to us because of market conditions or because of factors
that specifically affect Williams Energy Marketing & Trading or Williams
Refining & Marketing, including a decrease in demand for products in the markets
served by our terminals or a loss of customers in those markets. For additional
information relating to our commercial agreements with The Williams Companies,
Inc. and its affiliates, please read "Management's Discussion & Analysis of
Financial Condition and Results of Operations -- Related Party Transactions,"
which begins on page 31.
OUR AMMONIA PIPELINE AND TERMINALS SYSTEM IS DEPENDENT ON THREE CUSTOMERS.
Three customers ship all of the ammonia on our pipeline and utilize the six
terminals that we own and operate on the pipeline. We have contracts with
Farmland Industries, Inc., Agrium U.S. Inc. and Terra Nitrogen, L.P. through
June 2005 that obligate them to ship-or-pay for specified minimum quantities of
ammonia. Two of these customers have credit ratings below investment grade. The
loss of any one of these three customers or their failure or inability to pay us
would adversely affect our ability to pay cash distributions to you.
HIGH NATURAL GAS PRICES CAN INCREASE AMMONIA PRODUCTION COSTS AND REDUCE THE
AMOUNT OF AMMONIA TRANSPORTED THROUGH OUR AMMONIA PIPELINE AND TERMINALS SYSTEM.
The profitability of our customers that produce ammonia partially depends
on the price of natural gas, which is the principal raw material used in the
production of ammonia. From 1999 through the first half of 2001, natural gas
prices were substantially higher than historical averages. As a result, our
customers substantially curtailed their production of ammonia and shipped lower
volumes of ammonia on our pipeline. Because of this, our ammonia business
realized reduced revenues and cash flows in 1999, 2000 and the first six months
of 2001. Our ammonia pipeline and terminals system revenues increased during the
second half of 2001 with the return of high natural gas prices to lower
historical levels. An extended period of high natural gas prices may cause our
customers to produce and ship lower volumes of ammonia, which could adversely
affect our ability to pay cash distributions to you.
CHANGES IN THE FEDERAL GOVERNMENT'S POLICY REGARDING FARM SUBSIDIES COULD
NEGATIVELY IMPACT THE DEMAND FOR AMMONIA AND RESULT IN DECREASED SHIPMENTS
THROUGH OUR AMMONIA PIPELINE AND TERMINALS SYSTEM.
Our customers who ship ammonia through our pipeline primarily market the
ammonia to corn farmers in the Midwest. The government's Freedom to Farm program
enacted by the 1996 Farm Bill has provided these farmers with increased
incentives to grow corn, resulting in large corn crops over the last few years.
This program, however, ends in 2002 and is under legislative consideration at
this time. If the program is revised or terminated, it could reduce farmers'
incentive to grow corn and reduce the demand for the ammonia used to fertilize
the crops. In addition, the federal government and state governments have been
providing tax credits related to the production of ethanol, for which corn is
the essential element. If these tax incentives are reduced or repealed, the
demand for ammonia would be reduced and our customers might reduce the volumes
transported through our pipeline.
34
OUR MARINE AND INLAND TERMINALS ENCOUNTER COMPETITION FROM OTHER TERMINAL
COMPANIES AND OUR AMMONIA PIPELINE AND TERMINALS SYSTEM ENCOUNTERS COMPETITION
FROM RAIL CARRIERS AND ANOTHER AMMONIA PIPELINE.
Our marine and inland terminals face competition from large, generally
well-financed companies that own many terminals, as well as from small
companies. Our marine and inland terminals also encounter competition from
integrated refining and marketing companies that own their own terminal
facilities. Our customers demand delivery of products on tight time schedules
and in a number of geographic markets. If our quality of service declines or we
cannot meet the demands of our customers, they may use our competitors.
We compete primarily with rail carriers for the transportation of ammonia.
If our customers elect to transport ammonia by rail rather than pipeline, we may
realize lower revenues and cash flows and our ability to pay cash distributions
may be adversely affected. Our ammonia pipeline also competes with the Koch
Pipeline Company LP ammonia pipeline in Iowa and Nebraska.
OUR BUSINESS IS SUBJECT TO FEDERAL, STATE AND LOCAL LAWS AND REGULATIONS THAT
GOVERN THE ENVIRONMENTAL AND OPERATIONAL SAFETY ASPECTS OF OUR OPERATIONS.
Our marine and inland terminal facilities and ammonia pipeline and
terminals system are subject to the risk of incurring substantial costs and
liabilities under environmental and safety laws. These costs and liabilities
arise under increasingly strict environmental and safety laws, including
regulations and governmental enforcement policies, and as a result of claims for
damages to property or persons arising from our operations. Failure to comply
with these laws and regulations may result in assessment of administrative,
civil and criminal penalties, imposition of cleanup and site restoration costs
and liens and, to a lesser extent, issuance of injunctions to limit or cease
operations. If we were unable to recover these costs through increased revenues,
our ability to pay cash distributions to you could be adversely affected.
We own a number of properties that have been used for many years to
distribute or store petroleum products by third parties not under our control.
In some cases, owners, tenants or users of these properties have disposed of or
released hydrocarbons or solid wastes on or under these properties. In addition,
some of our terminals are located on or near current or former refining and
terminal operations, and there is a risk that contamination is present on these
sites. The transportation of ammonia by our pipeline is hazardous and may result
in environmental damage, including accidental releases that may cause death or
injuries to humans and farm animals and damage to crops.
TERRORIST ATTACKS AIMED AT OUR FACILITIES COULD ADVERSELY AFFECT OUR BUSINESS.
On September 11, 2001, the United States was the target of terrorist
attacks of unprecedented scale. Since the September 11 attacks, the U.S.
government has issued warnings that energy assets, specifically our nation's
pipeline infrastructure, may be the future target of terrorist organizations.
These developments have subjected our operations to increased risks. Any future
terrorist attack on our facilities, those of our customers and, in some cases,
those of other pipelines, could have a material adverse effect on our business.
OUR BUSINESS INVOLVES MANY HAZARDS AND OPERATIONAL RISKS, SOME OF WHICH MAY NOT
BE COVERED BY INSURANCE.
Our operations are subject to the many hazards inherent in the
transportation of refined petroleum products and ammonia, including ruptures,
leaks and fires. These risks could result in substantial losses due to personal
injury or loss of life, severe damage to and destruction of property and
equipment and pollution or other environmental damage and may result in
curtailment or suspension of our related operations. We are not fully insured
against all risks incident to our business. In addition, as a result of market
conditions, premiums for our insurance policies have increased substantially and
could escalate further. In some instances, insurance could become unavailable or
available only for reduced amounts of coverage. For example, insurance carriers
are now requiring broad exclusions for losses due to war risk and terrorist and
sabotage acts. If a significant accident or event occurs that is not fully
insured, it could adversely affect our financial position or results of
operations.
35
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Williams Energy Partners currently does not engage in interest rate,
foreign currency exchange rate or commodity price-hedging transactions.
Market risk is the risk of loss arising from adverse changes in market
rates and prices. The principal market risk to which we are exposed is interest
rate risk. Debt we incur under our credit facility bears variable interest based
on LIBOR. If the LIBOR changed by 0.125 percent, our annual debt coverage
obligations associated with the $139.5 million of outstanding borrowings under
the term loan and revolving credit facility at December 31, 2001 would change by
approximately $0.2 million. Unless interest rates change significantly in the
future, our exposure to interest rate market risk is minimal.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT AUDITORS
The Board of Directors of Williams GP LLC,
General Partner of Williams Energy Partners L.P.
We have audited the accompanying consolidated balance sheets of Williams
Energy Partners L.P. as of December 31, 2001 and 2000, and the related
consolidated statements of income, partners' capital and cash flows for each of
the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Partnership's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Williams Energy
Partners L.P. at December 31, 2001 and 2000, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States.
ERNST & YOUNG LLP
Tulsa, Oklahoma
March 4, 2002
36
WILLIAMS ENERGY PARTNERS L.P.
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
---------------------------
2001 2000 1999
------- ------- -------
Revenues:
Third party............................................... $70,155 $55,077 $37,469
Affiliate................................................. 15,899 17,415 6,919
------- ------- -------
Total revenues......................................... 86,054 72,492 44,388
Costs and expenses:
Operating................................................. 37,314 33,489 18,635
Depreciation and amortization............................. 11,748 9,333 4,610
Affiliate general and administrative...................... 8,955 11,963 5,458
------- ------- -------
Total costs and expenses............................... 58,017 54,785 28,703
------- ------- -------
Operating profit............................................ 28,037 17,707 15,685
Interest expense:
Affiliate interest expense................................ 1,843 12,827 4,775
Other interest expense.................................... 5,089 -- --
Minority interest expense................................... 229 -- --
Other (income) expense...................................... (1,058) 33 --
------- ------- -------
Income before income taxes.................................. 21,934 4,847 10,910
Provision for income taxes.................................. 187 1,842 4,144
------- ------- -------
Net income.................................................. $21,747 $ 3,005 $ 6,766
======= ======= =======
Allocation of 2001 net income:
Portion applicable to the period January 1 through
February 9, 2001....................................... $ 304
Portion applicable to the period after February 9, 2001... 21,443
-------
Net income............................................. $21,747
=======
General partner's interest in income applicable to the
period after February 9, 2001............................. $ 226
=======
Limited partners' interest in income applicable to the
period after February 9, 2001............................. $21,217
=======
Basic and diluted net income per limited partner unit....... $ 1.87
=======
Weighted average number of units outstanding for the period
after February 9, 2001.................................... 11,359
=======
See accompanying notes.
37
WILLIAMS ENERGY PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
DECEMBER 31,
-------------------
2001 2000
-------- --------
ASSETS
Current assets:
Cash and cash equivalents................................. $ 13,831 $ --
Accounts receivable (less allowance for doubtful
accounts -- $285 in 2001).............................. 13,822 10,645
Affiliate accounts receivable............................. 2,874 1,875
Prepaid insurance......................................... -- 903
Other current assets...................................... 330 685
-------- --------
Total current assets................................. 30,857 14,108
Property, plant and equipment, at cost...................... 380,706 340,975
Less: accumulated depreciation............................ 51,326 40,127
-------- --------
Net property, plant and equipment.................... 329,380 300,848
Deferred equity offering costs.............................. -- 2,539
Goodwill (less amortization of $145)........................ 22,282 --
Other intangibles (less amortization of $310)............... 2,639 --
Long-term affiliate receivables............................. 4,459 --
Long-term receivables....................................... 8,809 262
Other noncurrent assets..................................... 1,018 748
-------- --------
Total assets.............................................. $399,444 $318,505
======== ========
LIABILITIES & PARTNERS' CAPITAL
Current liabilities:
Accounts payable.......................................... $ 5,795 $ 3,640
Affiliate accounts payable................................ 6,681 --
Accrued affiliate payroll and benefits.................... 797 1,169
Accrued taxes other than income........................... 2,314 1,919
Accrued interest payable.................................. 277 --
Environmental liabilities................................. 905 --
Other current liabilities................................. 1,136 --
Acquisition payable....................................... 8,854 --
-------- --------
Total current liabilities............................ 26,759 6,728
Long-term debt.............................................. 139,500 --
Long-term affiliate payable................................. 1,262 --
Other deferred liabilities.................................. 284 --
Affiliate note payable...................................... -- 226,188
Deferred income taxes....................................... -- 13,789
Environmental liabilities................................... 4,479 1,944
Minority interest........................................... 2,250 --
Commitments and contingencies
Partners' capital:
Common unitholders (5,680 units outstanding at December
31, 2001).............................................. 101,452 69,856
Subordinated unitholders (5,680 units outstanding at
December 31, 2001)..................................... 121,237 --
General partner........................................... 2,221 --
-------- --------
Total partners' capital................................ 224,910 69,856
-------- --------
Total liabilities and partners' capital................ $399,444 $318,505
======== ========
See accompanying notes.
38
WILLIAMS ENERGY PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
--------------------------------
2001 2000 1999
--------- -------- ---------
Operating Activities:
Net income.............................................. $ 21,747 $ 3,005 $ 6,766
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization...................... 11,748 9,333 4,610
Debt issuance costs amortization................... 253 -- --
Minority interest expense.......................... 229 -- --
Deferred compensation expense...................... 2,048 -- --
Bad debt expense................................... 285 -- --
Deferred income taxes.............................. 187 1,842 4,144
Gain on sale of assets............................. (1,058) -- --
Changes in components of operating assets and
liabilities:
Accounts receivable................................ (3,155) (1,417) (6,130)
Affiliate accounts receivable...................... (999) 2,870 (3,927)
Prepaid insurance.................................. 903 (544) --
Accounts payable................................... 2,155 (303) 2,825
Affiliate accounts payable......................... 6,184 -- --
Accrued income taxes due affiliate................. -- -- (2,315)
Accrued affiliate payroll and benefits............. (372) 509 630
Accrued taxes other than income.................... 391 1,679 (55)
Accrued interest payable........................... 277 -- --
Current and noncurrent environmental liabilities... 3,338 (346) 172
Other current and noncurrent assets and
liabilities...................................... (1,653) (993) (1,061)
--------- -------- ---------
Net cash provided by operating activities.......... 42,508 15,635 5,659
Investing Activities:
Additions to property, plant & equipment................ (15,511) (10,649) (4,318)
Purchases of businesses................................. (49,409) (31,100) (223,300)
Proceeds from sale of business.......................... 1,650 -- --
Advances on affiliate note receivable................... -- -- (10,115)
--------- -------- ---------
Net cash used by investing activities................. (63,270) (41,749) (237,733)
Financing Activities:
Distributions paid...................................... (16,599) -- --
Borrowings under credit facility........................ 139,500 -- --
Capital contributions by affiliate...................... 1,792 -- --
Sales of Common Units to public (less underwriters'
commissions and payment of formation costs)............ 89,362 -- --
Debt placement costs.................................... (909) -- --
Redemption of 600,000 Common Units from affiliate....... (12,060) -- --
Payments on affiliate note payable...................... (166,493) (5,955) --
Proceeds from affiliate note payable.................... -- 32,069 232,074
--------- -------- ---------
Net cash provided by financing activities............. 34,593 26,114 232,074
--------- -------- ---------
Change in cash and cash equivalents......................... 13,831 -- --
Cash and cash equivalents at beginning of period............ -- -- --
--------- -------- ---------
Cash and cash equivalents at end of period.................. $ 13,831 $ -- $ --
========= ======== =========
Supplemental non-cash investing and financing transactions:
Contributions by affiliate of predecessor company deferred
income tax liability.................................... $ 13,976 -- --
Contribution of long-term debt to Partnership capital..... 59,695 -- --
Purchase of Aux Sable pipeline............................ 8,854 -- --
Deferred equity offering costs............................ -- 2,539 --
--------- -------- ---------
Total................................................... $ 82,525 $ 2,539 $ --
========= ======== =========
See accompanying notes.
39
WILLIAMS ENERGY PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(IN THOUSANDS, EXCEPT UNIT AMOUNTS)
NUMBER OF LIMITED PARTNER
UNITS TOTAL
-------------------------- GENERAL PARTNERS'
COMMON SUBORDINATED COMMON SUBORDINATED PARTNER CAPITAL
---------- ------------- -------- ------------ ------- ---------
Balance -- January 1, 1999............... -- -- $ 60,085 $ -- $ -- $ 60,085
Net income............................... 6,766 6,766
--------- --------- -------- -------- ------ --------
Balance -- December 31, 1999............. -- -- 66,851 -- -- 66,851
Net income............................... 3,005 3,005
--------- --------- -------- -------- ------ --------
Balance -- December 31, 2000............. -- -- 69,856 -- -- 69,856
Portion of net income applicable to
period Jan. 1, 2001 through Feb. 9,
2001................................... -- -- 304 -- -- 304
--------- --------- -------- -------- ------ --------
Balance -- February 9, 2001.............. -- -- 70,160 -- -- 70,160
Issuance of units to public.............. 4,600,000 -- 89,362 -- -- 89,362
Contribution of net assets of predecessor
companies.............................. 1,679,694 5,679,694 (48,484) 118,762 2,326 72,604
Redemption of common units............... (600,000) -- (12,060) -- -- (12,060)
Distributions............................ -- -- (8,134) (8,134) (331) (16,599)
Portion of net income applicable to
period Feb. 10 through Dec. 31, 2001... -- -- 10,608 10,609 226 21,443
--------- --------- -------- -------- ------ --------
Balance -- December 31, 2001............. 5,679,694 5,679,694 $101,452 $121,237 $2,221 $224,910
========= ========= ======== ======== ====== ========
See accompanying notes.
40
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND PRESENTATION
Williams Energy Partners L.P. (the "Partnership") is a Delaware limited
partnership that was formed in August 2000, to acquire, own and operate: (a)
selected petroleum product terminals owned by Williams Energy Ventures, Inc.
("WEV"), and (b) an ammonia pipeline and terminals system, Williams Ammonia
Pipeline, Inc., ("WAPI"), owned by Williams Natural Gas Liquids, Inc. ("WNGL").
Prior to the closing of the Partnership's initial public offering in February
2001, WEV was owned by Williams Energy Services, LLC ("WES"). Both WES and WNGL
are wholly-owned subsidiaries of The Williams Companies, Inc. ("Williams").
Williams GP LLC (the "Managing GP" or "General Partner"), a Delaware limited
liability company, was also formed in August 2000, to serve as managing general
partner for the Partnership.
On February 9, 2001, the Partnership completed its initial public offering
of 4,000,000 common units representing limited partner interests in the
Partnership at a price of $21.50 per unit. The proceeds of $86.0 million were
used to pay underwriter commissions of $5.6 million and legal, professional fees
and costs associated with the initial public offering of $3.1 million, with the
remainder used to reduce affiliate note balances with Williams.
On October 28, 2000, the Partnership and the Managing GP formed a limited
operating partnership named Williams OLP, L.P. ("OLP") to serve as limited
partner of the operating limited partnerships. Concurrent with the closing of
the initial public offering and pursuant to the Contribution and Conveyance
Agreement dated February 9, 2001, WEV converted itself into Williams Terminals
Holdings, L.P. ("WTH LP"). Williams Pipeline Holdings, LLC, a subsidiary of WTH
LP, converted itself into Williams Pipeline Holdings, LP ("WPH LP") and Williams
Ammonia Pipeline, Inc. converted itself into Williams Ammonia Pipeline, L.P.
("WAP LP"). All three converted entities are Delaware limited partnerships. WNGL
contributed 3.05 percent of its ownership in WAP LP and WES contributed 2.05
percent of its ownership in WTH LP to the Managing GP in exchange for 19.2
percent and 80.8 percent ownership interest in the Managing GP, respectively.
WNGL contributed the remainder of its interest in WAP LP to the OLP and WES
contributed the remainder of its interest in WTH LP and all of its interest in
WPH LP to the OLP in exchange for ownership interests in the OLP. The Managing
GP contributed all of its interest in WAP LP, WTH LP and WPH LP in exchange for:
(a) a 1.0 percent managing general partner interest in the Partnership and (b) a
1.0101 percent managing general partner interest in the OLP. WNGL contributed to
the Partnership all of its limited partner interest in OLP in exchange for
322,501 common units and 1,090,501 subordinated units, and WES contributed all
of its limited partner interest in OLP to the Partnership in exchange for
1,357,193 common units and 4,589,193 subordinated units.
Subsequent to the initial public offering, the underwriters exercised their
over-allotment option and purchased 600,000 common units, also at a price of
$21.50 per unit. The net proceeds of $12.1 million, after underwriter
commissions of $0.8 million, from this over-allotment option were used to redeem
600,000 of the common units held by WES to reimburse it for capital expenditures
related to the Partnership's assets. Upon completion of this transaction,
Williams owned 60 percent of the equity units of the Partnership. The
Partnership maintained the historical costs of the net assets received under the
Contribution Agreement. Following the exercise of the underwriters
over-allotment, 40.09 percent of the Partnership is owned by the public and
59.91 percent, including the general partners ownership, is owned by affiliates
of Williams Energy Partners L.P.
On February 26, 2002, the Partnership formed a wholly-owned Delaware
corporation named Williams GP Inc. ("GP Inc.") The Partnership then contributed
a 0.001 percent limited partner interest in OLP to GP Inc. as a capital
contribution. The OLP agreement was then amended to convert GP Inc.'s OLP
limited partner interest to a general partner interest and to convert the
General Partner's existing interest to a limited partner interest. The General
Partner then contributed its 1.0101 percent OLP limited partner interest to the
Partnership in exchange for an additional 1.0 percent general partner interest
in the Partnership.
41
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The resulting structure is as follows: Williams GP LLC serves as the
managing general partner for the Partnership. OLP is the limited partner of the
operating limited partnerships and GP Inc. serves as its general partner. The
operating limited partnerships are comprised of WTH LP, WPH LP and WAP LP.
Williams NGL LLC was established to serve as general partner of the operating
limited partnerships and is owned by OLP. Under the resulting structure, the
limited partners' liability in each of the limited partnerships is limited to
their investment.
Pro Forma Results of Operations (Unaudited):
2000
--------------
(IN THOUSANDS,
EXCEPT PER
UNIT AMOUNTS)
Revenues.................................................... $77,560
Operating expenses.......................................... 36,106
Depreciation................................................ 9,992
Affiliate general and administrative expense................ 6,000
-------
Operating profit............................................ 25,462
Interest expense............................................ (7,784)
Minority interest expense................................... (178)
Other income (expense)...................................... (33)
-------
Net income.................................................. $17,467
General partner's interest in net income.................... 175
-------
Limited partners' interest in net income.................... $17,292
=======
Net income per limited partner unit......................... $ 1.52
=======
Weighted average number of units outstanding................ 11,359
=======
The pro forma results of operations for the year ended December 31, 2000,
are derived from the historical financial statements of the Partnership. The pro
forma results of operations reflect certain pro forma adjustments to the
historical results of operations as if the MLP had been formed on January 1,
2000. Significant pro forma adjustments include: (a) pro forma interest on debt
outstanding on February 9, 2001, (b) reductions in general and administrative
expenses to $6.0 million per year, (c) additional revenues and expenses from
acquisitions as though the acquisitions had occurred as of January 1, 2000, (d)
reductions of $0.7 million in 2000 for additional revenues recognized as a
result of a revenue guarantee provided by Amerada Hess Corporation for a
specified period after the acquisition of the Gulf Coast marine terminals and
(e) the elimination of income tax expense as income taxes are the responsibility
of the unitholders and not the MLP.
2. DESCRIPTION OF BUSINESSES
Williams Energy Partners L.P. owns and operates certain petroleum product
terminal operations and an interstate common carrier ammonia pipeline.
Petroleum Product Terminals
Most of the Partnership's 30 petroleum product terminals are strategically
located along or near third party pipelines or petroleum refineries. The
terminal network consists of marine terminals and inland terminals. The
petroleum product terminals provide a variety of services such as distribution,
storage, blending, inventory management and additive injection to a diverse
customer group including governmental customers and end-users in the downstream
refining, retail, commercial trading, industrial and petrochemical
42
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
industries. Products stored in and distributed through the petroleum product
terminal network include refined petroleum products, blendstocks and heavy oils
and feedstocks. The inland terminals are located primarily in the southeastern
United States. Four marine terminal facilities are located along the Gulf Coast
and one marine terminal facility is located in Connecticut near the New York
harbor. Other than at our Galena Park marine terminal facility, none of the
employees assigned to the petroleum product terminal operations are covered by
collective bargaining agreements. The employees at the Galena Park marine
terminal facility are currently represented by a union, but have indicated their
unanimous desire to terminate their union affiliation. Nevertheless, the
National Labor Relations Board has ordered the Partnership to bargain with the
union as the exclusive collective bargaining representative of the employees at
the facility. The Partnership is appealing this decision.
Ammonia Pipeline and Terminals System
The ammonia pipeline and terminals system consists of an ammonia pipeline
and six company-owned terminals. Shipments on the pipeline primarily originate
from ammonia production plants located in Borger, Texas and Enid and Verdigris,
Oklahoma for transport to terminals throughout the Midwest for ultimate
distribution to end-users in Iowa, Kansas, Minnesota, Missouri, Nebraska,
Oklahoma and South Dakota. The ammonia transported through the system is used
primarily as nitrogen fertilizer. Approximately 94 percent of ammonia system
revenues are generated from transportation tariffs received from three
customers, who are obligated under "ship or pay" contracts to ship an aggregate
minimum of 700,000 tons per year but have historically shipped an amount in
excess of the required minimum. The current ammonia transportation contracts
extend through June 2005. The tariffs charged by the interstate ammonia pipeline
are regulated by the Surface Transportation Board of the U.S. Department of
Transportation.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The petroleum product terminal operations consist of 30 independent
petroleum product terminal facilities and associated storage, located across 12
states primarily in the South, Southeast and Gulf Coast areas of the United
States. For 11 of these petroleum product terminals, Williams Energy Partners
L.P. owns varying undivided ownership interests. From inception, ownership of
these assets has been structured as an ownership of an undivided interest in
assets, not as an ownership interest in a partnership, limited liability
company, joint venture or other form of entity. Marketing and invoicing are
controlled separately by each owner, and each owner is responsible for any loss,
damage or injury that may occur to their own customers. As a result, Williams
Energy Partners L.P. applies proportionate consolidation for their interests in
these assets. All of the remaining terminal facilities and the ammonia pipeline
are wholly-owned subsidiaries and are fully consolidated.
Reclassifications
Certain previously reported balances have been classified differently to
conform with current year presentation.
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results could differ from
those estimates.
43
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Cash Equivalents
Cash and cash equivalents include demand and time deposits and other
marketable securities with maturities of three months or less when acquired.
Property, Plant and Equipment
Property, plant and equipment are stated at cost. Expenditures for
maintenance and repairs are charged to operations in the period incurred. The
costs of property, plant and equipment sold or retired and the related
accumulated depreciation is removed from the accounts, and any associated gains
or losses are recorded in the income statement, in the period of sale or
disposition. Depreciation of property, plant and equipment is provided on the
straight-line basis.
Goodwill and Other Intangible Assets
Goodwill, which represents the excess of cost over fair value of assets of
businesses acquired, was amortized on a straight-line basis over a period of 20
years for those assets acquired prior to July 1, 2001. Other intangible assets
are amortized on a straight-line basis over a period of up to 25 years.
Impairment of Long-Lived Assets
Williams Energy Partners L.P. evaluates its long-lived assets of
identifiable business activities for impairment when events or changes in
circumstances indicate, in management's judgment, that the carrying value of
such assets may not be recoverable. The determination of whether an impairment
has occurred is based on management's estimate of undiscounted future cash flows
attributable to the assets as compared to the carrying value of the assets. If
an impairment has occurred, the amount of the impairment recognized is
determined by estimating the fair value for the assets and recording a provision
for loss if the carrying value is greater than fair value.
For assets identified to be disposed of in the future, the carrying value
of these assets is compared to the estimated fair value less the cost to sell to
determine if an impairment is required. Until the assets are disposed of, an
estimate of the fair value is redetermined when related events or circumstances
change.
Revenue Recognition
Revenues are recognized in the month that services are rendered.
Income Taxes
Prior to February 9, 2001, Williams Energy Partners L.P.'s operations wee
included in Williams' consolidated federal income tax return. Williams Energy
Partners L.P. income tax provisions were computed as though separate returns
were filed. Deferred income taxes were computed using the liability method and
were provided on all temporary differences between the financial basis and tax
basis of Williams Energy Partners L.P.'s assets and liabilities.
Effective with the closing of the Partnership's initial public offering on
February 9, 2001 (See Note 1), the Partnership is not a taxable entity for
federal and state income tax purposes. Accordingly, no recognition has been
given to income taxes for financial reporting purposes. The tax on Partnership
net income is borne by the individual partners through the allocation of taxable
income. Net income for financial statement purposes may differ significantly
from taxable income of unitholders as a result of differences between the tax
basis and financial reporting basis of assets and liabilities and the taxable
income allocation requirements under the Partnership Agreement. The aggregate
difference in the basis of the Partnership's net assets for financial and
44
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
tax reporting purposes cannot be readily determined because information
regarding each partner's tax attributes in the Partnership is not available to
the Partnership.
Employee Stock-Based Awards
Williams' employee stock-based awards are accounted for under provisions of
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," and related interpretations. Williams' fixed plan common stock
options do not result in compensation expense because the exercise price of the
stock options equals the market price of the underlying stock on the date of
grant.
The Partnership's General Partner has issued incentive awards to Williams'
employees assigned to the Partnership. These awards are also accounted for under
provisions of Accounting Principles Board Opinion No. 25. Since the exercise
price of the unit awards is less than the market price of the underlying units
on the date of grant, compensation expense is recognized by the General Partner
and directly allocated to the Partnership.
Environmental
Environmental expenditures that relate to current or future revenues are
expensed or capitalized based upon the nature of the expenditures. Expenditures
that relate to an existing condition caused by past operations that do not
contribute to current or future revenue generation are expensed. Environmental
liabilities are recorded independently of any potential claim for recovery.
Receivables are recognized in cases where the realization of reimbursements of
remediation costs are considered probable. Accruals related to environmental
matters are generally determined based on site-specific plans for remediation,
taking into account prior remediation experience of Williams Energy Partners
L.P. and Williams.
Earnings Per Unit
Basic earnings per unit are based on the average number of common and
subordinated units outstanding. Diluted earnings per unit include any dilutive
effect of restricted unit grants.
Recent Accounting Standards
In August 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets." This Statement supersedes SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of" and amends Accounting Principles Board Opinion No. 30,
"Reporting the Results of Operations -- Reporting the Effects of Disposal of a
Segment of a Business and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions." The Statement retains the basic framework of SFAS No.
121, resolves certain implementation issues of SFAS No. 121, extends
applicability to discontinued operations and broadens the presentation of
discontinued operations to include a component of an entity. The Statement is to
be applied prospectively and is effective for financial statements issued for
fiscal years beginning after December 15, 2001. The Statement is not expected to
have any initial impact on the Partnership's results of operations or financial
position.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This Statement addresses financial accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs and amends FASB Statement No.
19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The
Statement requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made and that the associated asset retirement
costs be capitalized as part of the carrying amount of the long-lived asset. The
Statement is effective for financial statements
45
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
issued for fiscal years beginning after June 15, 2002. The Partnership plans to
adopt this standard in January 2003, and we are evaluating its effect on the
Partnership's results of operations and financial position.
In June 2001, the FASB issued SFAS No. 141, "Business Combinations" and
SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 establishes
accounting and reporting standards for business combinations and requires all
business combinations to be accounted for by the purchase method. The Statement
is effective for all business combinations for which the date of acquisition is
July 1, 2001 or later. SFAS No. 142 addresses accounting and reporting standards
for goodwill and other intangible assets. Under this Statement, goodwill and
intangible assets with indefinite useful lives will no longer be amortized, but
will be tested annually for impairment. The Statement becomes effective for all
fiscal years beginning after December 15, 2001. The Partnership will apply the
new rules on accounting for goodwill and other intangible assets beginning
January 1, 2002. Based on the amount of goodwill recorded as of December 31,
2001 application of the non-amortization provision of the Statement will result
in a decrease to amortization expense in future years of approximately $1.1
million.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This was followed in June 2000 by the
issuance of SFAS No. 138, "Accounting for Certain Derivative Instruments and
Certain Hedging Activities," which amends SFAS No. 133. SFAS No. 133 and No. 138
establish accounting and reporting standards for derivative financial
instruments. The standards require that all derivative financial instruments be
recorded on the balance sheet at their fair value. Changes in fair value of
derivatives will be recorded each period in earnings if the derivative is not a
hedge. If a derivative qualifies for special hedge accounting, changes in the
fair value of the derivative will either be recognized in earnings as an offset
against the change in fair value of the hedged assets, liabilities or firm
commitments also recognized in earnings, or the changes in fair value will be
deferred on the balance sheet until the hedged item is recognized in earnings.
The ineffective portion of a derivative's change in fair value will be
recognized immediately in earnings. These standards were adopted on January 1,
2001. There was no impact to Williams Energy Partners L.P.'s financial position,
results of operations or cash flows from adopting these standards.
The FASB issued SFAS No. 140, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities." The Statement provides
guidance for determining whether a transfer of financial assets should be
accounted for as a sale or a secured borrowing and whether a liability has been
extinguished. The Statement is effective for recognition and reclassification of
collateral and for disclosures ending after December 15, 2000. The Statement
became effective for transfers and servicing of financial assets and
extinguishments of liabilities occurring after March 31, 2001. The initial
application of SFAS No. 140 had no impact on our results of operations and
financial position.
4. ACQUISITIONS AND DIVESTITURES
Petroleum product terminal facilities and partial ownership interests in
several petroleum product terminals were acquired for cash during the periods
presented and are described below. All acquisitions, except the Aux Sable
transaction, were accounted for as purchases of businesses and the results of
operations of the acquired petroleum product terminals are included with the
combined results of operations from their acquisition dates.
On December 31, 2001, the Partnership purchased an 8.5-mile, 8-inch natural
gas liquids pipeline in northeastern Illinois from Aux Sable Liquid Products
L.P. ("Aux Sable") for $8.9 million. The Partnership then entered into a
long-term lease arrangement under which Aux Sable is the sole lessee of these
assets. The Partnership has accounted for this transaction as a capital lease.
The lease expires in December 2016 and has a purchase option after the first
year. The minimum lease payments to be made by Aux Sable are $19.2 million in
total and $1.3 million per year over each of the next five years. Aux Sable has
the right to re-acquire the pipeline at the end of the lease for a de minimis
amount. The fair value of the lease at December 31, 2001, approximates its
carrying value.
46
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In October 2001, the Partnership acquired the crude oil storage and
distribution assets of Geonet Gathering, Inc. ("Geonet") located in Gibson,
Louisiana. The Partnership acquired these assets with the intent to use the
facility as a crude storage and distribution facility with an affiliate company
as its primary customer. The purchase price was approximately $21.1 million,
consisting of $20.3 million in cash and $0.9 million in assumed liabilities. The
purchase price and allocation to assets acquired and liabilities assumed was as
follows (in thousands):
Purchase price:
Cash paid, including transaction costs.................... $20,261
Liabilities assumed....................................... 856
-------
Total purchase price...................................... $21,117
=======
Allocation of purchase price:
Current assets............................................ $ 62
Property, plant and equipment............................. 4,607
Goodwill.................................................. 13,719
Intangible assets......................................... 2,729
-------
Total allocation.......................................... $21,117
=======
Factors contributing to the recognition of goodwill are the market in which
the facility is located and the opportunity to enter into a throughput agreement
with an affiliate company, combined with the affiliate company's ability to
trade around those assets. Of the amount allocated to intangible assets, $2.0
million represents the value of the leases associated with this facility, which
have amortization periods of up to 25 years. The remaining $0.7 million
allocated to intangible assets represents covenants not-to-compete and has an
amortization period of five years. Total weighted average amortization period of
intangible assets is approximately 16 years. Of the consideration paid for the
facility, $1.0 million is held in escrow, pending final evaluation of necessary
repairs by the Partnership.
In June 2001, the Partnership purchased two petroleum product terminals
located in Little Rock, Arkansas from TransMontaigne, Inc. ("TransMontaigne") at
a cost of $29.1 million, of which $20.2 million was allocated to property, plant
and equipment and $8.9 million to goodwill and other intangibles. Goodwill
resulting from this acquisition is being amortized over a 20-year period. The
final purchase price allocation has not been determined pending assessment of
the environmental liabilities assumed.
In April 2001, the Partnership purchased a 6-mile pipeline for $0.3 million
from Equilon Pipeline Company LLC, enabling connection of its existing Dallas,
Texas area petroleum storage and distribution facility to Dallas Love Field. The
acquisition was made in conjunction with an agreement for the Partnership to
provide jet fuel delivery services into Dallas Love Field for Southwest
Airlines. In December 2001, the Partnership completed construction of additional
jet fuel storage tanks at its distribution facility in Dallas to support
delivery of jet fuel to the airport. Total cost of the pipeline and construction
of the additional jet fuel storage tanks totaled $5.5 million.
In September 2000, a northeast petroleum product terminal facility in New
Haven, Connecticut was acquired from Wyatt Energy, Incorporated ("Wyatt") and
its affiliates for approximately $30.8 million.
In March 2000, a 50 percent ownership interest in CITGO Petroleum
Corporation's petroleum product terminal located in Southlake, Texas was
acquired for approximately $0.3 million.
In August 1999, three storage and distribution petroleum product terminals
and Terminal Pipeline Company ("TPC"), a wholly owned subsidiary of Amerada Hess
Corporation ("Hess"), were acquired from Hess for approximately $212 million.
The petroleum product terminals are located in Galena Park and Corpus Christi,
Texas and Marrero, Louisiana. TPC owned a common carrier pipeline that began at
a connection east
47
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
of the Houston Ship Channel and terminated at the Galena Park terminal. The
pipeline acquired from Hess was converted to private pipeline status during
2001.
In February 1999, an additional 10 percent ownership interest in eight
petroleum product terminals was acquired from Murphy Oil USA, Inc. for
approximately $3.4 million, which increased the Partnership's ownership interest
to 78.9 percent from 68.9 percent. The petroleum product terminals, which are
now operated by the Partnership, are located in Georgia, North Carolina, South
Carolina, Tennessee and Virginia.
In January 1999, 11 petroleum product terminals owned by Amoco Oil Company
("Amoco") were acquired. The petroleum product terminals, located in Alabama,
Florida, Mississippi, North Carolina, Ohio, South Carolina and Tennessee, were
acquired for approximately $6.9 million. In addition, Amoco's 60 percent
interest in a twelfth petroleum product terminal, located in Greensboro, North
Carolina, was acquired for approximately $1.0 million.
The following summarized unaudited pro forma financial information for the
years ended December 31, 2001 and 2000 assumes each acquisition had occurred on
January 1 of the year immediately preceding the year of the acquisition (in
thousands):
2001 2000
------- -------
Revenues:
Williams Energy Partners L.P.............................. $86,054 $72,492
Acquired businesses....................................... 5,552 14,354
------- -------
Combined............................................... $91,606 $86,846
======= =======
Net income:
Williams Energy Partners L.P.............................. $21,747 $ 3,005
Acquired businesses....................................... 659 1,083
------- -------
Combined............................................... $22,406 $ 4,088
======= =======
Basic net income per limited partner unit................... $ 1.95
=======
The pro forma results include operating results prior to the acquisitions
and adjustments to interest expense, depreciation expense and income taxes. The
pro forma consolidated results do not purport to be indicative of results that
would have occurred had the acquisitions been in effect for the periods
presented, nor do they purport to be indicative of results that will be obtained
in the future.
Except where stated above, the purchase prices of the above acquisitions
were allocated to various categories of property, plant and equipment and
liabilities based upon the fair value of the assets acquired and liabilities
assumed.
In October 2001, the Meridian, Mississippi terminal, previously reported
with the Terminals business segment, was sold for $1.7 million. The Partnership
recognized a gain of $1.1 million associated with the sale of the terminal,
which is included in other income.
48
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of the following (in thousands):
DECEMBER 31, ESTIMATED
------------------- DEPRECIABLE
2001 2000 LIVES
-------- -------- -----------
Construction work-in-progress...................... $ 5,618 $ 4,931
Land and right-of-way.............................. 27,162 26,977
Buildings.......................................... 7,828 7,404 30 years
Storage tanks...................................... 162,451 147,858 30 years
Pipeline and station equipment..................... 52,822 42,529 30-67 years
Processing equipment............................... 122,161 110,214 30 years
Other.............................................. 2,664 1,062 10-30 years
-------- --------
Total.................................... $380,706 $340,975
======== ========
Depreciation expense for the years ended December 31, 2001, 2000 and 1999
was $11.2 million, $9.3 million and $4.6 million, respectively.
6. MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK
Williams Energy Marketing & Trading, an affiliate customer, Farmland
Industries, Inc. and BP are major customers of the Partnership. No other
customer accounted for more than 10 percent of total revenues during 2001, 2000
and 1999. Williams Energy Marketing & Trading and BP are customers of the
petroleum product terminals segment. Farmland Industries, Inc. is a customer of
the ammonia pipeline segment. The percentage of revenues derived by customer is
provided below:
2001 2000 1999
---- ---- ----
Customer A.................................................. 10.3% 8.7% 15.1%
Customer B.................................................. 0.8% 4.5% 13.9%
Williams Energy Marketing & Trading......................... 11.0% 24.0% 15.6%
---- ---- ----
Total..................................................... 22.1% 37.2% 44.6%
==== ==== ====
The accounts receivable balance of Williams Energy Marketing & Trading
accounted for 8.2 percent and 15.0 percent of total accounts and affiliate
receivables at December 31, 2001 and 2000, respectively.
Any issues impacting these industries could impact the Partnership's
overall exposure to credit risk. While sales to petroleum product terminal and
ammonia pipeline customers are generally unsecured, the financial condition and
creditworthiness of customers are routinely evaluated. The Partnership has the
ability with many of its contracts to sell stored customer products to recover
unpaid receivable balances, if necessary.
Demand for nitrogen fertilizer has typically followed a combination of
weather patterns and growth in population, acres planted and fertilizer
application rates. Because natural gas is the primary feedstock for the
production of ammonia, the profitability of our customers is impacted by high
natural gas prices. To the extent they are unable to pass on higher costs to
their customers, they may reduce shipments through the pipeline.
During 2001, the Partnership reserved $0.3 million for potential bad debt
losses. However, no accounts were written off during 2001.
7. EMPLOYEE BENEFIT PLANS
All employees dedicated to, or otherwise supporting, Williams Energy
Partners L.P. are employees of The Williams Companies, Inc. and substantially
all of these employees are covered by Williams' noncontribu-
49
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
tory defined benefit pension plans and health care plan that provides
postretirement medical benefits to certain retired employees. Contributions for
pension and postretirement medical benefits related to Williams Energy Partners
L.P.'s participation in the Williams' plans were $0.3 million, $0.2 million and
$0.2 million in 2001, 2000 and 1999, respectively.
Williams maintains various defined contribution plans in which employees
supporting Williams Energy Partners L.P. are included. Williams Energy Partners
L.P.'s costs related to these plans were $0.5 million, $0.4 million and $0.2
million in 2001, 2000 and 1999, respectively.
8. RELATED PARTY TRANSACTIONS
Williams Energy Marketing & Trading Company and Williams Refining &
Marketing, L.L.C., subsidiaries of The Williams Companies, Inc. and affiliates
of the Partnership, are significant customers at our petroleum product
terminals, representing 11.0 percent and 7.2 percent, respectively, of our total
revenues for the year ended December 31, 2001. The accounts receivable balance
of Williams Energy Marketing & Trading Company accounted for 8.2 percent and
15.0 percent of total accounts and affiliate receivables at December 31, 2001
and 2000, respectively. The accounts receivable balance of Williams Refining &
Marketing, L.L.C. was 2.4 percent and 0 percent of total accounts and affiliate
receivables at December 31, 2001 and 2000, respectively. The services we provide
them are conducted pursuant to various contracts between them and the
Partnership. As of December 31, 2001, 3 percent of the revenues from these
affiliates were generated under contracts renewing on a monthly basis, while 97
percent were generated under contracts with remaining terms in excess of one
year or that are renewed on an annual basis.
Williams allocates its affiliates, including the Partnership, for certain
corporate administrative expenses, which are directly identifiable or allocable
to the affiliates. Prior to the initial public offering, allocated general
corporate expenses were based on a three-factor formula that considered
operating margins, property, plant and equipment and payroll. Beginning with the
closing date of the initial public offering, the general partner, through
provisions included in the Omnibus Agreement, has limited the amount of general
and administrative costs allocated to the Partnership. The additional general
and administrative costs incurred by the general partner, but not charged to the
Partnership, totaled $10.4 million for the period February 10, 2001 through
December 31, 2001. A summary of the general and administrative expenses charged
to the Partnership is as follows (in thousands):
YEAR ENDED DECEMBER 31,
-------------------------
2001 2000 1999
------ ------- ------
Direct costs.............................................. $ 562 $ 5,239 $3,351
Allocated costs........................................... 8,393 6,724 2,107
------ ------- ------
Total general and administrative expenses....... $8,955 $11,963 $5,458
====== ======= ======
The above costs are reflected in affiliate general and administrative
expenses in the accompanying consolidated statements of income. In management's
estimation, the allocation methodologies used are reasonable and the direct and
allocated expenses represent amounts that would have been incurred on a stand-
alone basis.
The affiliate payable primarily represents amounts owed to affiliates for
general and administrative expenses and operational costs incurred on the
Partnership's behalf. Affiliate payroll and benefit costs are amounts due to
affiliate companies for salary and wages and associated charges for employees
directly assigned to the Partnership. Long-term affiliate payables represent
amounts due to an affiliate for certain non-compete agreements and for amounts
associated with long-term incentive compensation.
Prior to February 9, 2001, the Partnership was a participant in Williams'
cash management program. As of December 31, 2000, the Partnership's affiliate
note payable consisted of an unsecured promissory note
50
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
agreement with Williams for advances from Williams. The advances were due on
demand; however, in February 2001, a portion of the advances was refinanced with
debt and equity offerings (see Note 1). Williams contributed the remaining
advances in exchange for equity of the Partnership. Therefore, the affiliate
note payable was classified as noncurrent at December 31, 2000.
Affiliate interest income or expense is calculated at the London Interbank
Offered Rate ("LIBOR") plus a spread based on the outstanding balance of the
note receivable or note payable with Williams. The spread is equivalent to the
spread above LIBOR rates on Williams' revolving credit facility. The interest
rate of the note with Williams was 7.6 percent at December 31, 2000. As the
interest rate on the affiliate note payable is variable, the carrying value of
the affiliate note payable at December 31, 2000 approximates its fair value.
9. INCOME TAXES
The provision for income taxes is as follows (in thousands):
YEAR ENDED DECEMBER 31,
-------------------------
2001 2000 1999
----- ------- -------
Current:
Federal................................................... $ -- $ -- $ --
State..................................................... -- -- --
Deferred:
Federal................................................... 163 1,617 3,646
State..................................................... 24 225 498
---- ------ ------
$187 $1,842 $4,144
==== ====== ======
Reconciliations from the provision for income taxes at the U.S. federal
statutory rate to the effective tax rate for the provision for income taxes are
as follows (in thousands):
YEAR ENDED DECEMBER 31,
-------------------------
2001 2000 1999
----- ------- -------
Income taxes at statutory rate.............................. $172 $1,696 $3,819
Increase resulting from:
State taxes, net of federal income tax benefit............ 15 146 324
Other..................................................... -- -- 1
---- ------ ------
Provision for income taxes.................................. $187 $1,842 $4,144
==== ====== ======
Significant components of deferred tax liabilities and assets as of
December 31, 2000, are as follows (in thousands):
Deferred tax liabilities:
Property, plant and equipment............................. $39,798
Deferred tax assets:
Net operating loss carryforward........................... 25,270
Environmental liability................................... 739
-------
Total deferred tax assets............................ $26,009
-------
Net deferred tax liabilities......................... $13,789
=======
Williams Energy Partners L.P. recognized a pre-initial public offering
federal net operating loss for income tax purposes of $3.9 million and $57.0
million for the years 2001 and 2000, respectively. The $3.9 million federal net
operating loss expires in 2021. The $57.0 million federal net operating loss
carryforward expires in 2020. Payments to Williams in lieu of income taxes were
$2.3 million in 1999.
51
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As a result of the initial public offering and the concurrent transactions
on February 9, 2001 (see Note 1), the net deferred tax liability on that date
was assumed by Williams, in exchange for an additional equity investment in
Williams Energy Partners L.P.
10. LONG-TERM DEBT
Long-term debt and available borrowing capacity at December 31, 2001, were
$139.5 million and $35.5 million, respectively. At December 31, 2001, the
Partnership had a $175.0 million bank credit facility, led by Bank of America.
The credit facility was comprised of a $90.0 million term loan facility and an
$85.0 million revolving credit facility, which includes a $73.0 million
acquisition sub-facility and a $12.0 million working capital sub-facility. On
February 9, 2001, the OLP borrowed $90.0 million under the term loan facility
and $0.1 million under the acquisition sub-facility. The $0.1 million borrowed
under the acquisition sub-facility was repaid in July 2001. In June 2001, the
Partnership borrowed $29.5 million under the acquisition facility to fund the
purchase of two terminals in Little Rock, Arkansas from TransMontaigne. In
October 2001, the Partnership borrowed $20.0 million to fund the acquisition of
the Gibson, Louisiana terminal from Geonet. The credit facility's term extends
through February 5, 2004, with all amounts due at that time. Borrowings under
the credit facility carry an interest rate equal to the LIBOR plus a spread from
1.0 percent to 1.5 percent, depending on the OLP's leverage ratio. Interest is
also assessed on the unused portion of the credit facility at a rate from 0.2
percent to 0.4 percent, depending on the OLP's leverage ratio. The OLP's
leverage ratio is defined as the ratio of consolidated total debt to
consolidated earnings before interest, income taxes, depreciation and
amortization for the period of the four fiscal quarters ending on such date.
Closing fees associated with the initiation of the credit facility were $0.9
million, which are being amortized over the life of the facility. Average
interest rates at December 31, 2001 were 3.1 percent for the term loan facility
and 3.3 percent for the acquisition sub-facility. Cash paid for interest for the
twelve months ended December 31, 2001 was $6.7 million. Interest capitalized was
$0.1 million in 2001. The fair value of the long-term debt approximates its
carrying value, because of the floating interest rate applied to the debt
facility.
11. LONG-TERM INCENTIVE PLAN
In February 2001, the general partner adopted the Williams Energy Partners'
Long-Term Incentive Plan for Williams' employees who perform services for
Williams Energy Partners L.P. and directors of the general partner. The
Long-Term Incentive Plan consists of two components, phantom units and unit
options. The Long-Term Incentive Plan permits the grant of awards covering an
aggregate of 700,000 common units. The Long-Term Incentive Plan is administered
by the compensation committee of the general partner's board of directors.
In April 2001, the general partner issued grants of 92,500 phantom units to
certain key employees associated with the Partnership's initial public offering
in February 2001. These one-time initial public offering phantom units will vest
over a 34-month period ending on February 9, 2004, and are subject to forfeiture
if employment is terminated prior to vesting. These units are subject to early
vesting if the Partnership achieves certain performance measures. The
Partnership recognized $0.7 million of compensation expense associated with
these grants in 2001. The fair market value of the phantom units associated with
this grant was $2.7 million on the grant date.
In April 2001, the general partner issued grants of 64,200 phantom units
associated with the annual incentive compensation plan. The actual number of
units that will be awarded under this grant will be determined by the
Partnership on February 9, 2004. At that time, the Partnership will assess
whether certain performance criteria have been met and determine the number of
units that will be awarded, which could range from zero units up to a total of
128,400 units. These units are also subject to forfeiture if employment is
terminated prior to February 9, 2004. These awards do not have an early vesting
feature. The Partnership recognized $1.3 million of deferred compensation
expense associated with these awards in 2001. The fair market value of the
phantom units associated with this grant was $5.4 million on December 31, 2001.
52
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Certain employees of Williams dedicated to or otherwise supporting Williams
Energy Partners L.P. receive stock-based compensation awards from Williams.
Williams has several plans providing for common-stock-based awards to employees
and to nonemployee directors. The plans permit the granting of various types of
awards including, but not limited to, stock options, stock-appreciation rights,
restricted stock and deferred stock. Awards may be granted for no consideration
other than prior and future services or based on certain financial performance
targets being achieved. The purchase price per share for stock options and the
grant price for stock-appreciation rights may not be less than the market price
of the underlying stock on the date of grant. Depending upon terms of the
respective plans, stock options generally become exercisable in one-third
increments each year from the date of the grant or after three or five years,
subject to accelerated vesting if certain future Williams' stock prices or
specific Williams' financial performance targets are achieved. Stock options
expire 10 years after grant.
The following summary reflects Williams' stock option activity for 2001,
2000 and 1999, for those employees principally supporting Williams Energy
Partners L.P. operations:
2001 2000 1999
------------------- ------------------- -------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
------- --------- ------- --------- ------- ---------
Outstanding -- beginning of year... 73,302 $34.58 54,002 $29.79 39,402 $24.72
Granted............................ 31,439 34.77 20,800 45.76 16,600 40.26
Forfeited.......................... (3,000) 43.14 -- -- -- --
Exercised.......................... (2,500) 30.14 (1,500) 17.31 (2,000) 16.69
------ ------ ------
Outstanding -- ending of year...... 99,241 34.49 73,302 34.58 54,002 29.79
====== ====== ======
Exercisable at end of year......... 67,802 34.36 73,302 34.58 54,002 29.79
====== ====== ======
The following summary provides information about outstanding and
exercisable Williams' stock options, held by employees principally supporting
Williams Energy Partners L.P. operations, at December 31, 2001:
WEIGHTED-
WEIGHTED- AVERAGE
AVERAGE REMAINING
EXERCISE CONTRACTUAL
RANGE OF EXERCISE PRICES OPTIONS PRICE LIFE
------------------------ ------- --------- -----------
$16.13 to $23.00....................................... 17,168 $19.81 5.0 years
$27.38 to $34.77....................................... 47,673 33.40 8.2 years
$39.94 to $46.06....................................... 34,400 43.32 8.0 years
------
Total........................................ 99,241 34.49 7.6 years
======
The estimated fair value at the date of grant of options for Williams'
common stock granted in 2001, 2000 and 1999, using the Black-Scholes option
pricing model, is as follows:
2001 2000 1999
------ ------ ------
Weighted-average grant date fair value of options for
Williams' common stock granted during the year........... $10.93 $15.44 $11.90
Assumptions:
Dividend yield........................................ 1.9% 1.5% 1.5%
Volatility............................................ 35.0% 31.0% 28.0%
Risk-free interest rate............................... 4.8% 6.5% 5.6%
Expected life (years)................................. 5.0 5.0 5.0
53
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Pro forma net income, assuming Williams Energy Partners L.P. had applied
the fair-value method of SFAS No. 123, "Accounting for Stock-Based Compensation"
in measuring compensation costs beginning with 1999 employee stock-based awards,
are as follows (in thousands, except per unit amounts):
2001 2000 1999
-------------------- -------------------- --------------------
PRO FORMA REPORTED PRO FORMA REPORTED PRO FORMA REPORTED
--------- -------- --------- -------- --------- --------
Net income................. $21,683 $21,747 $2,861 $3,005 $6,579 $6,766
======= ======= ====== ====== ====== ======
Net income per limited
partner unit............. $ 1.86 $ 1.87
======= =======
Pro forma amounts for 2000 include the total compensation expense from the
awards made in 2000, as these awards fully vested in 2000 as a result of the
accelerated vesting provisions. Pro forma amounts for 1999 include the remaining
total compensation expense from Williams' awards made in 1998 and the total
compensation expense from Williams' awards made in 1999 as a result of the
accelerated vesting provisions. Since compensation expense from stock options is
recognized over the future years' vesting period for pro forma disclosure
purposes, and additional awards generally are made each year, pro forma amounts
may not be representative of future years' amounts.
12. SEGMENT DISCLOSURES
Management evaluates performance based upon segment profit or loss from
operations, which includes revenues from affiliate and external customers,
operating expenses, depreciation and affiliate general and administrative
expenses. The accounting policies of the segments are the same as those
described in Note 3 -- Summary of Significant Accounting Policies. Affiliate
revenues are accounted for as if the sales were to unaffiliated third parties.
The Partnership's reportable segments are strategic business units that
offer different products and services. The segments are managed separately
because each segment requires different marketing strategies and business
knowledge.
YEAR ENDED DECEMBER 31, 2001 YEAR ENDED DECEMBER 31, 2000 YEAR ENDED DECEMBER 31, 1999
------------------------------- ------------------------------- -------------------------------
PETROLEUM PETROLEUM PETROLEUM
PRODUCT AMMONIA PRODUCT AMMONIA PRODUCT AMMONIA
TERMINALS PIPELINE TOTAL TERMINALS PIPELINE TOTAL TERMINALS PIPELINE TOTAL
--------- -------- -------- --------- -------- -------- --------- -------- --------
(IN THOUSANDS)
Revenues:
Third party
customers........ $ 55,611 $14,544 $ 70,155 $ 43,367 $11,710 $ 55,077 $ 25,330 $12,139 $ 37,469
Affiliate
customers........ 15,899 -- 15,899 17,415 -- 17,415 6,919 -- 6,919
-------- ------- -------- -------- ------- -------- -------- ------- --------
Total revenues... 71,510 14,544 86,054 60,782 11,710 72,492 32,249 12,139 44,388
Operating expenses... 33,270 4,044 37,314 29,496 3,993 33,489 15,108 3,527 18,635
Depreciation and
amortization....... 11,099 649 11,748 8,688 645 9,333 3,969 641 4,610
Affiliate general and
administrative
expenses........... 7,641 1,314 8,955 10,351 1,612 11,963 3,915 1,543 5,458
-------- ------- -------- -------- ------- -------- -------- ------- --------
Segment profit....... $ 19,500 $ 8,537 $ 28,037 $ 12,247 $ 5,460 $ 17,707 $ 9,257 $ 6,428 $ 15,685
======== ======= ======== ======== ======= ======== ======== ======= ========
Total assets......... $368,409 $31,035 $399,444 $296,819 $21,686 $318,505 $261,425 $21,914 $283,339
Goodwill............. $ 22,282 $ -- $ 22,282 $ -- $ -- $ -- $ -- $ -- $ --
Additions to
long-lived
assets............. $ 64,590 $ 330 $ 64,920 $ 41,348 $ 401 $ 41,749 $227,234 $ 384 $227,618
54
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Non-cash charges for incentive compensation costs, included in 2001
affiliate general and administrative expenses, were $1.7 million for the
petroleum product terminal operations and $0.3 million for the ammonia pipeline
operations.
13. COMMITMENTS AND CONTINGENCIES
The Partnership leases land, tanks and related terminal equipment at the
Gibson terminal facility. Minimum future lease payments for these leases as of
December 31, 2001, are $0.1 million for each of the next five years and $1.7
million thereafter. The lease payments can be canceled after 2006 and include
provisions for renewal of the lease at five-year increments which can extend the
lease for a total of 25 years.
In conjunction with the 1999 acquisition of the Gulf Coast marine terminals
from Hess, Hess has disclosed to the Partnership all suits, actions, claims,
arbitrations, administrative, governmental investigation or other legal
proceedings pending or threatened, against or related to the assets acquired by
the Partnership, which arise under environmental law. Hess agreed to indemnify
the Partnership against all environmental claims and losses arising from any
matters related to the pre-acquisition period through July 30, 2014. In the
event that any pre-acquisition releases of hazardous substances are identified
by the Partnership prior to July 20, 2004, the Partnership will be liable for
the first $2.5 million of environmental liabilities, Hess will be liable for the
next $12.5 million of losses, and the Partnership will assume responsibility for
any losses in excess of $15.0 million. Hess has indemnified the Partnership
against any pre-acquisition fines and claims that may be imposed or asserted
against the Partnership under environmental laws. At both December 31, 2001 and
December 31, 2000, the Partnership had accrued $0.6 million for costs that may
not be recoverable under Hess' indemnification.
WES has agreed to indemnify the Partnership against any covered
environmental losses, up to $15.0 million, relating to assets it contributed to
the Partnership that arose prior to February 9, 2001, that become known within
three years after February 9, 2001, and that exceed all amounts recovered or
recoverable by the Partnership under contractual indemnities from third parties
or under any applicable insurance policies. Covered environmental losses are
those non-contingent environmental losses, costs, damages and expenses suffered
or incurred by the Partnership arising from correction of violations of, or
performance of remediation required by, environmental laws in effect at February
9, 2001, due to events and conditions associated with the operation of the
assets and occurring before February 9, 2001.
Estimated liabilities for environmental costs were $5.4 million and $1.9
million at December 31, 2001 and 2000, respectively. Management estimates that
expenditures associated with these environmental remediation liabilities will be
paid over the next five to ten years. Receivables associated with these
environmental liabilities of $5.1 million and $0.3 million at December 31, 2001
and 2000, respectively, have been recognized as recoverable from WES and third
parties. These estimates, provided on an undiscounted basis, were determined
based primarily on data provided by a third-party environmental evaluation
service. These liabilities have been classified as current or non-current based
on management's estimates regarding the timing of actual payments.
During 2001, the Partnership recorded an environmental liability of $2.6
million at its New Haven, Connecticut facility, which was acquired in September
2000. This liability was based on third-party environmental engineering
estimates completed as part of a Phase II environmental assessment, routinely
required by the State of Connecticut to be conducted by the purchaser following
the acquisition of a petroleum storage facility. The Partnership will complete a
Phase III environmental assessment at this facility during the second or third
quarter of 2002, and the environmental liability could change materially based
on this more thorough analysis. The environmental liabilities at this location
are covered by the WES environmental indemnifications to the Partnership.
55
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
WNGL will indemnify the Partnership for right-of-way defects or failures in
our ammonia pipeline easements for 15 years after the initial public offering
closing date. WES has also indemnified the Partnership for right-of-way defects
or failures associated with the marine terminal facilities at Galena Park,
Corpus Christi and Marrero for 15 years after the initial public offering
closing date.
The Partnership is party to various other claims, legal actions and
complaints arising in the ordinary course of business. In the opinion of
management, the ultimate resolution of all claims, legal actions and complaints
after consideration of amounts accrued, insurance coverage or other
indemnification arrangements will not have a material adverse effect upon the
Partnership's future financial position, results of operations or cash flows.
14. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data is as follows (in thousands, except per
unit amounts).
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
2001
Revenues....................................... $20,286 $21,646 $21,778 $22,344
Operating and depreciation and amortization
expenses..................................... 11,226 11,126 12,060 14,650
Net income..................................... 3,904 7,394 5,663 4,786
Basic and diluted net income per limited
partner unit................................. 0.31 0.64 0.49 0.42
2000
Revenues....................................... $17,856 $18,764 $16,988 $18,884
Operating and depreciation expenses............ 8,887 11,052 9,582 13,301
Net income..................................... 2,168 669 587 (419)
Basic and diluted net income for the first quarter of 2001 is calculated on
the Limited Partners' interest in net income applicable for the period after
February 9, 2001, through the end of the quarter. Revenues and expenses in 2001
were impacted by the acquisition of two terminals from TransMontaigne in June
2001 and the Gibson terminal from Geonet in October 2001. See Note
4 -- Acquisitions. Second quarter 2001 revenues were impacted by a $1.0 million
throughput deficiency billing to an ammonia pipeline customer. Fourth quarter
net income included a gain of $1.1 million on the sale of the Meridian,
Mississippi terminal. Interest expense for 2001 reflects the payment and
forgiveness of the predecessor company's affiliate debt and new borrowings by
the Partnership. Net income was also impacted by incentive compensation costs of
$2.0 million during 2001.
Revenues and expenses in 2000 were impacted by the Southlake terminal
acquisition in March 2000 and the marine terminal acquisition from Wyatt Energy
in September 2000. Second quarter 2000 expenses included a $0.5 million charge
from the write-off of an unsuccessful business transaction. Third quarter 2000
expenses included a $0.6 million environmental accrual. A throughput revenue
deficiency billing related to the August 1999 acquisition of certain assets from
Amerada Hess resulted in adjustments to revenues of $0.7 million impacting the
first and second quarters of 2000.
15. DISTRIBUTIONS
On May 15, 2001, the Partnership paid cash distributions of $0.292 per unit
on its outstanding common and subordinated units to unitholders of record at the
close of business on May 1, 2001. This distribution represented the minimum
quarterly distribution for the 50-day period following the initial public
offering closing date, which included February 10, 2001 through March 31, 2001.
The total distributions paid were $3.4 million.
56
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
On August 14, 2001, the Partnership paid cash distributions of $0.5625 per
unit on its outstanding common and subordinated units to unitholders of record
at the close of business on August 2, 2001. The total distributions paid were
$6.5 million.
On November 14, 2001, the Partnership paid cash distributions of $0.5775
per unit on its outstanding common and subordinated units to unitholders of
record at the close of business on November 1, 2001. The total distributions
paid were $6.7 million.
Total distributions paid during 2001 were as follows (in thousands except
per unit amounts):
AMOUNT DISTRIBUTION
PER UNIT AMOUNT
-------- ------------
Common Unitholders.......................................... $1.43 $ 8,134
Subordinated Unitholders.................................... $1.43 8,134
General Partner............................................. $1.43 331
-------
Total............................................. $16,599
=======
16. EARNINGS PER UNIT
The following table provides details of the basic and diluted earnings per
unit computations (in thousands, except per unit amounts):
FOR THE YEAR ENDED DECEMBER 31, 2001
--------------------------------------
INCOME UNITS PER UNIT
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- --------
Limited partners' interest in income applicable to
the period after February 9, 2001............... $21,217
Basic earnings per common and subordinated unit... $21,217 11,359 $1.87
Effect of dilutive restrictive unit grants........ -- 11 --
------- ------ -----
Diluted earnings per common and subordinated
unit............................................ $21,217 11,370 $1.87
======= ====== =====
Units reported as dilutive securities are related to restricted unit grants
associated with the one-time initial public offering award (see Note 11).
17. PARTNERS' CAPITAL
Of the 5,679,694 common units outstanding at December 31, 2001, 4,600,000
are held by the public, with the remaining 1,079,694 held by affiliates of the
Partnership. All of the 5,679,694 subordinated units are held by affiliates of
the Partnership.
During the subordination period, the Partnership can issue up to 2,839,847
additional common units without obtaining unitholder approval. In addition, the
general partner can issue an unlimited number of common units as follows:
- Upon exercise of the underwriters' over-allotment option;
- Upon conversion of the subordinated units;
- Under employee benefit plans;
- Upon conversion of the general partner interest and incentive
distribution rights as a result of a withdrawal of the general partner;
- In the event of a combination or subdivision of common units;
- In connection with an acquisition or a capital improvement that increases
cash flow from operations per unit on a pro forma basis; or
57
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- If the proceeds of the issuance are used exclusively to repay up to $40.0
million of our indebtedness.
The subordination period will end when the Partnership meets certain
financial tests provided for in the Partnership agreement but it generally
cannot end before December 31, 2005.
The limited partners holding common units of the Partnership have the
following rights, among others:
- Right to receive distributions of the Partnership's available cash within
45 days after the end of each quarter;
- Right to transfer common unit ownership to substitute limited partners;
- Right to receive an annual report, containing audited financial
statements and a report on those financial statements by our independent
public accountants within 120 days after the close of the fiscal year
end;
- Right to receive information reasonably required for tax reporting
purposes within 90 days after the close of the calendar year;
- Right to vote according to the limited partners' percentage interest in
the Partnership on any meeting that may be called by the general partner.
However, if any person or group other than the general partner and its
affiliates acquires beneficial ownership of 20 percent or more of any
class of units, that group or person loses voting rights on all of its
units; and
- Right to inspect our books and records at the unitholders' own expense.
Net income is allocated to the general partner and limited partners based
on their proportionate share of cash distributions for the period. Cash
distributions to the general partner and limited partners are made based on the
following table:
PERCENTAGE OF DISTRIBUTIONS
-----------------------------
ANNUAL DISTRIBUTION AMOUNT (PER UNIT) UNITHOLDERS GENERAL PARTNER
------------------------------------- ----------- ---------------
Up to $2.31................................................. 98 2
Above $2.31 up to $2.62..................................... 85 15
Above $2.62 up to $3.15..................................... 75 25
Above $3.15................................................. 50 50
In the event of a liquidation, all property and cash in excess of that
required to discharge all liabilities will be distributed to the Partners in
proportion to the positive balances in their respective tax-basis capital
accounts.
18. REGISTRATION STATEMENT (UNAUDITED)
The Partnership plans to file a shelf registration statement to register
common units representing limited partner interests and debt securities,
including guarantees. The Partnership, exclusive of its investment in all of its
wholly-owned operating limited partnerships and subsidiaries, has no independent
assets or operations. If a series of debt securities is guaranteed, such series
will be guaranteed by all of the Partnership's operating limited partnerships
and subsidiaries on a full and unconditional and joint and several basis.
19. OTHER EVENTS
On February 14, 2002, the Partnership paid cash distributions of $0.59 per
unit on its outstanding common and subordinated units to unitholders of record
at the close of business on February 1, 2002. The total distribution, including
distributions paid to the general partner on its equivalent units, was $6.9
million.
With the payment of the $0.59 per unit distribution on February 14, 2002,
the first early vesting performance measure of the one-time initial public
offering grant was achieved, and 46,250 units associated
58
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
with this grant vested on that date. The Partnership recognized additional
compensation expense of $1.0 million with the vesting of these units in February
2002.
In January 2002, the Partnership borrowed $8.5 million to finance the
acquisition of a pipeline from Aux Sable and remitted those funds to complete
the transaction. The Partnership entered into a long-term lease arrangement with
Aux Sable under which Aux Sable is the sole lessee of these assets. The
transaction will be accounted for as a capital lease.
59
ITEM 9. CHANGES IN AND DISAGREEMENT WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None
PART III
ITEM 10. PARTNERSHIP MANAGEMENT
Our general partner manages our operations and activities. Unitholders do
not directly or indirectly participate in our management or operations. Our
general partner owes a fiduciary duty to the unitholders. Our general partner is
liable, as a general partner, for all of our debts (to the extent not paid from
our assets), except for specific non-recourse indebtedness or other obligations.
Whenever possible, our general partner intends to incur indebtedness or other
obligations that are non-recourse.
Three members of the board of directors of our general partner serve on a
conflicts committee to review specific matters, which the board of directors
believes may involve conflicts of interest. When a conflict arises, the
conflicts committee will determine if the resolution of the conflict of interest
is fair and reasonable to us. The members of the conflicts committee are not
officers or employees of our general partner or directors, officers or employees
of its affiliates. Any matters approved by the conflicts committee are
conclusively deemed to be fair and reasonable to us, approved by all of our
partners, and not a breach by our general partner of any duties it may owe us or
our unitholders. In addition, the members of the conflicts committee also serve
on an audit committee, which reviews our external financial reporting,
recommends engagement of our independent auditors and reviews procedures for
internal auditing and the adequacy of our internal accounting controls and on
the compensation committee that oversees compensation decisions for the officers
of Williams GP LLC as well as the compensation plans described below.
As is commonly the case with publicly-traded limited partnerships, we are
managed and operated by the officers and are subject to the oversight of the
directors of our general partner. All of our personnel are employees of our
affiliates.
Some officers of our general partner may spend a substantial amount of time
managing the business and affairs of The Williams Companies, Inc. and its
affiliates. These officers may face a conflict regarding the allocation of their
time between our business and the other business interests of The Williams
Companies, Inc. Our general partner causes its officers to devote as much time
as is necessary for the proper conduct of our business and affairs. Steven J.
Malcolm and Phillip D. Wright devote approximately three percent of their time
to Williams Energy Partners. Craig R. Rich devotes approximately fifty percent
of his time to our operations and Don R. Wellendorf, our Senior Vice President,
Chief Financial Officer and Treasurer, devotes approximately seventy-five
percent of his time to our operations. Jay A. Wiese devotes ninety-five percent
of his time to our operations. The board of directors of the general partner is
presently composed of seven directors.
60
DIRECTORS AND EXECUTIVE OFFICERS OF WILLIAMS GP LLC
The following table sets forth certain information with respect to the
executive officers and members of the board of directors of our general partner.
Executive officers and directors are elected for one-year terms.
NAME AGE POSITION WITH GENERAL PARTNER
---- --- -----------------------------
Steven J. Malcolm......................... 53 Chief Executive Officer and Chairman of the Board
Phillip D. Wright......................... 46 President and Chief Operating Officer, Director
Don R. Wellendorf......................... 49 Senior Vice President, Chief Financial Officer and
Treasurer, Director
Jay A. Wiese.............................. 44 Vice President, Terminal Services and Development
Craig R. Rich............................. 50 General Counsel
Keith E. Bailey........................... 58 Director
William A. Bruckmann, III................. 50 Director
Don J. Gunther............................ 63 Director
William W. Hanna.......................... 65 Director
Steven J. Malcolm serves as the Chief Executive Officer and Chairman of the
Board of Directors of our general partner and was elected as Chief Executive
Officer on January 7, 2001, and Director on February 9, 2001. He is currently
President and Chief Executive Officer of The Williams Companies, Inc. and has
served in the capacity as President since September 2001, and as Chief Executive
Officer since January 2002. From 1998 to September 2001, he served as President
and Chief Executive Officer of Williams Energy Services, LLC. From 1994 to 1998,
he served as Senior Vice President for The Williams Companies, Inc.'s midstream
gas and liquids division, and from 1993 to 1994, worked as Senior Vice President
of the mid-continent region for Williams Field Services. From 1984 to 1993, he
held various positions with Williams Natural Gas Company, including director of
business development, director of gas management and vice president of gas
management and supply.
Phillip D. Wright serves as President, Chief Operating Officer and Director
of our general partner and was elected as President and Chief Operating Officer
on January 7, 2001, and Director on February 9, 2001. He is currently President
and Chief Executive Officer for Williams Energy Services, LLC and has served in
that capacity since September 2001. From 1996 to September 2001, he served as
Senior Vice President of Enterprise Development and Planning for Williams Energy
Services, LLC. From 1989 to 1996 he held various senior management positions
with The Williams Companies, Inc.'s primary refined product pipeline, Williams
Pipe Line Company, Williams Energy Ventures, Inc. and Williams Energy Services
Company. Prior to 1989, he spent 13 years working for Conoco, Inc.
Don R. Wellendorf serves as Senior Vice President, Chief Financial Officer,
Treasurer and Director of our general partner and was elected as Senior Vice
President, Chief Financial Officer and Treasurer on January 7, 2001, and as
Director on February 9, 2001. Since 1998, he has served as Vice President of
Strategic Development and Planning for Williams Energy Services, LLC. Prior to
The Williams Companies, Inc.'s merger with MAPCO Inc. in 1998, he was Vice
President and Treasurer for MAPCO from 1995 to 1998. From 1994 to 1995, he
served as Vice President and Corporate Controller for MAPCO. He began his career
in 1979 as an accountant with MAPCO and held various accounting positions with
MAPCO from 1979 to 1994.
Jay A. Wiese serves as Vice President, Terminal Services and Development of
our general partner and was elected on January 7, 2001. He is currently Managing
Director, Terminal Services and Commercial Development for Williams Energy
Services, LLC and has served in that capacity since 2000. From 1995 to 2000, he
served as Director, Terminal Services and Commercial Development of The Williams
Companies, Inc.'s terminal distribution business. Prior to 1995, Mr. Wiese held
various operations, marketing and business development positions with Williams
Pipe Line Company, Williams Energy Ventures, Inc. and Williams Energy Services
Company. He joined Williams Pipe Line Company in 1982.
Craig R. Rich serves as General Counsel of our general partner and was
elected on January 7, 2001. He is currently Associate General Counsel of
Williams Energy Services, LLC and has served in that capacity since 1996. From
1993 to 1996, he served as General Counsel of The Williams Companies, Inc.'s
midstream gas
61
and liquids division. Prior to that time, Mr. Rich was a Senior Attorney
representing Williams Gas Pipeline-West. He joined Williams in 1985.
Keith E. Bailey serves as a Director of the general partner and was elected
on February 9, 2001. He is currently Chairman of the Board of The Williams
Companies, Inc. and served in that capacity since 1994. He served as President
of The Williams Companies, Inc. from 1992 to 1994 and served as its Chief
Executive Officer from 1994 to January 2002. He served as Executive Vice
President of The Williams Companies, Inc. from 1986 to 1992.
William A. Bruckmann, III serves as a director of our general partner and
was elected on May 9, 2001. He is a former managing director at Chase
Securities, Inc. He has more than 25 years of banking experience, starting with
Manufacturers Hanover Trust Company, where he became a senior officer in 1985.
Mr. Bruckmann later served as managing director, sector head of the
Manufacturers Hanover's gas pipeline and midstream practices through the
acquisition of Manufacturers Hanover by Chemical Bank and the acquisition of
Chemical Bank by Chase Bank.
Don J. Gunther serves as a director of our general partner and was elected
May 9, 2001. He is a retired vice chairman of Bechtel Group Inc. He began his
career with Bechtel in 1961 and was promoted to a variety of positions,
including Bechtel's executive committee in 1989; president of Bechtel Petroleum
in 1984; president of Europe, Africa, Middle East and southwest Asia operations
in 1992; and president of Bechtel Americas in 1995. He was named vice chairman
in July 1997, retiring from the position in 1998.
William W. Hanna serves as a director of our general partner and was
elected on January 18, 2002. He is a retired vice chairman of Koch Industries
where he held management and leadership positions since he commenced employment
in 1968. In his first year, he established a gas and gas liquids group. In 1981,
he became executive vice president of energy products for Koch. In 1984, he was
elected to the board of directors, and in 1987, was named president and chief
operating officer. In 1999, he was named vice chairman.
COMPLIANCE WITH SECTION 16(a) OF THE SECURITIES EXCHANGE ACT OF 1934
Section 16(a) of the Securities Exchange Act of 1934 requires directors,
executive officers and persons who beneficially own more than 10 percent of our
units to file certain reports with the Securities and Exchange Commission and
the New York Stock Exchange concerning their beneficial ownership of our equity
securities. The Securities and Exchange Commission regulations also require that
a copy of all such Section 16(a) forms filed must be furnished to us by the
executive officers, directors and greater than 10 percent unitholders. Based on
a review of the copies of such forms and amendments thereto received by us with
respect to 2001, we are not aware of any late filings.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
We have no employees. We are managed by the officers of our general
partner. We reimburse The Williams Companies, Inc. for indirect and direct
expenses incurred on our behalf, as discussed in Part II, Item 7. A percentage
of the compensation expense of each executive officer is allocated by The
Williams Companies, Inc. to us as follows: Mr. Malcolm, three percent; Mr. Rich,
fifty percent; Mr. Wellendorf, seventy-five percent; Mr. Wiese, ninety-five
percent; and Mr. Wright, three percent. The following table represents
compensation expense allocated to us by The Williams Companies, Inc. for the
fiscal year ended
62
December 31, 2001, for the CEO and each of the four other most highly
compensated executive officers of our general partner.
ALLOCATED SUMMARY COMPENSATION TABLE
ALLOCATED
LONG-TERM
COMPENSATION
ALLOCATED ANNUAL COMPENSATION -------------
------------------------------ WMB STOCK ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS OPTION SHARES COMPENSATION(1)
--------------------------- ----- --------- -------- ------------- ---------------
Steven J. Malcolm................... 2001 $ 15,360 $19,089 5,248 $ 337
Chief Executive Officer &
Chairman of the Board
Craig R. Rich....................... 2001 77,765 41,793 4,550 4,556
General Counsel
Don R. Wellendorf................... 2001 149,004 86,964 4,289 1,585
Sr. Vice President, Chief
Financial Officer, Treasurer and
Director
Jay A. Wiese........................ 2001 139,474 66,861 3,881 2,383
Vice President, Terminal
Services & Development
Phillip D. Wright................... 2001 8,156 6,104 819 235
President & Chief
Operating Officer, Director
---------------
(1) Represents expense allocated by our general partner to us on behalf of each
executive officer for contributions made by the general partner to the
Investment Plus Plan, a defined contribution plan.
63
ALLOCATED STOCK OPTION GRANTS IN THE LAST FISCAL YEAR
The following table provides certain information concerning the grant of
Williams' stock options during the last fiscal year to the named executive
officers. The number of options granted, percent of total options granted and
the grant date present values reported below represent The Williams Companies,
Inc. allocation to us as follows: Mr. Malcolm, three percent; Mr. Rich, fifty
percent; Mr. Wellendorf, seventy-five percent; Mr. Wiese, ninety-five percent;
and Mr. Wright, three percent.
ALLOCATED WILLIAMS OPTION GRANTS IN LAST FISCAL YEAR
INDIVIDUAL GRANTS(1)
-----------------------------------------------------------------------------
PERCENT OF
TOTAL
OPTIONS
NUMBER OF GRANTED TO
WMB WILLIAMS EXERCISE GRANT DATE
DATE OPTIONS EMPLOYEES IN PRICE (PER EXPIRATION PRESENT
NAME GRANTED GRANTED(2) FISCAL YEAR SHARE) DATE VALUE(2)
---- -------- ----------- ------------ ----------- ---------- ----------
Steven J. Malcolm................... 01/18/01 3,431 0.05% $34.7712 01/18/11 $45,701
04/02/01 817 0.01% $39.9812 04/02/11 $12,508
09/19/01 1,000 0.01% $26.7900 09/19/11 $10,070
-------- ----- -------
5,248 0.07% $68,279
Craig R. Rich....................... 01/18/01 4,550 0.06% $34.7712 01/18/11 $60,606
-------- ----- -------
4,550 0.06% $60,606
Don R. Wellendorf................... 01/18/01 4,289 0.06% $34.7712 01/18/11 $57,129
-------- ----- -------
4,289 0.06% $57,129
Jay A. Wiese........................ 01/18/01 3,881 0.05% $34.7712 01/18/11 $51,695
-------- ----- -------
3,881 0.05% $51,695
Phillip D. Wright................... 01/18/01 294 0.004% $34.7712 01/18/11 $ 3,916
09/19/01 525 0.007% $26.7900 09/19/11 $ 5,287
-------- ----- -------
819 0.011% $ 9,203
---------------
(1) Options granted in 2001 were granted subject to accelerated vesting if
certain future Williams' stock prices or specific Williams' financial
performance targets are achieved. The Williams Companies, Inc. granted these
options under its 1996 Stock Plan and its Stock Plan for Nonofficer
Employees. Williams' stock option shares granted prior to the April 23, 2001
spinoff of Williams Communications Group, Inc. were adjusted as a result of
the spinoff using a factor of 1.089263 per share.
(2) The grant date present value is determined using the Black-Scholes option
pricing model and is based on assumptions about future stock price
volatility and dividend yield. The model does not take into account that the
stock options are subject to vesting restrictions and that executives cannot
sell their options. The following weighted-average values were determined
based on the above grants. The weighted-average volatility of the expected
market price of Williams common stock is 29.6 percent. The weighted-average
risk-free rate of return is 5.3 percent. The model assumes a dividend yield
of 1.9 percent and an exercise date at the end of the contractual term in
2011. The actual value, if any, that may be realized by an executive will
depend on the market price of Williams' Common Stock on the date of
exercise. The dollar amounts shown are not intended to forecast possible
future appreciation in Williams' stock price.
64
ALLOCATED OPTION EXERCISES AND FISCAL YEAR-END VALUES
The following table provides certain information on stock option exercises
of Williams' stock options during the last fiscal year by the named executive
officers and the value of such officers' unexercised options at December 31,
2001. This table represents the allocated value of option exercises of Williams'
stock.
ALLOCATED OPTION EXERCISES OF WILLIAMS' STOCK IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION VALUES
NUMBER OF UNEXERCISED VALUE OF UNEXERCISED
OPTIONS AT IN-THE-MONEY OPTIONS
SHARES FISCAL YEAR-END(1) AT FISCAL YEAR-END
ACQUIRED VALUE --------------------------- ---------------------------
NAME ON EXERCISE REALIZED EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- ----------- -------- ----------- ------------- ----------- -------------
Steven J. Malcolm......... -0- $-0- -0- 5,248 $-0- -0-
Craig R. Rich............. -0- -0- -0- 4,550 -0- -0-
Don R. Wellendorf......... -0- -0- -0- 4,289 -0- -0-
Jay A. Wiese.............. -0- -0- -0- 3,881 -0- -0-
Phillip D. Wright......... -0- -0- -0- 819 -0- -0-
---------------
(1) Williams' stock option shares granted and unexercised prior to the April 23,
2001 spinoff of Williams Communications Group, Inc. were adjusted as a
result of the spinoff using a factor of 1.089263.
The following table provides certain information concerning the grant of
our units under the Williams Energy Partners' Long-Term Incentive Plan during
the last fiscal year to the named executive officers:
LONG-TERM INCENTIVE PLAN-AWARDS IN LAST FISCAL YEAR
ESTIMATED FUTURE PAYOUTS UNDER
PERFORMANCE OR NON-STOCK PRICE-BASED PLANS
OTHER PERIOD UNTIL --------------------------------
NUMBER MATURATION OR THRESHOLD TARGET MAXIMUM
NAME OF UNITS PAYOUT # UNITS # UNITS # UNITS
---- -------- ------------------ ---------- -------- --------
Steven J. Malcolm.................... 13,000(1) 34 Months 13,000 13,000 13,000
------ ------ ------ ------
13,000 13,000 13,000 13,000
Craig R. Rich........................ 5,000(1) 34 Months 5,000 5,000 5,000
4,500(2) 34 Months 4,500 4,500 9,000
------ ------ ------ ------
9,500 9,500 9,500 14,000
Don R. Wellendorf.................... 13,000(1) 34 Months 13,000 13,000 13,000
13,300(2) 34 Months 13,300 13,300 26,600
------ ------ ------ ------
26,300 26,300 26,300 39,600
Jay A. Wiese......................... 15,500(1) 34 Months 15,500 15,500 15,500
4,500(2) 34 Months 4,500 4,500 9,000
------ ------ ------ ------
20,000 20,000 20,000 24,500
Phillip D. Wright.................... 13,000(1) 34 Months 13,000 13,000 13,000
15,800(2) 34 Months 15,800 15,800 31,600
------ ------ ------ ------
28,800 28,800 28,000 44,600
---------------
(1) Represents an initial public offering grant of our phantom units on April
19, 2001 (market values at date of grant are noted as follows): Mr. Malcolm,
13,000 units valued at $399,100; Mr. Rich, 5,000 units valued at $153,500;
Mr. Wellendorf, 13,000 units valued at $399,100; Mr. Wiese, 15,500 units
valued at $475,850 and Mr. Wright, 13,000 units valued at $399,100. The
units are subject to early vesting if we achieve certain performance
measures.
(2) Represents phantom units of deferred limited interest granted on April 19,
2001 (market values at date of grant are noted as follows): Mr. Rich, 4,500
units valued at $138,150; Mr. Wellendorf, 13,300 units valued at $408,310;
Mr. Wiese, 4,500 units valued at $138,150; and Mr. Wright, 15,800 units
valued at
65
$485,060. At the end of the vesting period, the number of units awarded
under this grant will be determined based on our assessment of whether
certain performance criteria have been met. The number of units could range
from zero to two times the number of units granted.
COMMITTEES, MEETINGS AND DIRECTOR COMPENSATION
Our general partner's Board of Directors has the responsibility for
establishing broad policies and for our overall performance. However, the Board
is not involved in our day-to-day operations. The Board is kept informed of our
business through discussions with the Chief Executive Officer, and other
officers, by reviewing analyses and reports provided to it on a regular basis
and by participating in Board and Committee meetings.
Our general partner's Board of Directors held 4 meetings during 2001. Each
director during 2001 attended all of the Board meetings. The Board has
established standing committees to consider designated matters. The Committees
of the Board are Audit, Compensation and Conflicts.
Audit Committee.
The members of the Audit Committee are: William A. Bruckmann, III,
Chairman, Don J. Gunther and William W. Hanna. The Audit Committee is composed
of nonemployee directors who review our external financial reporting, recommend
engagement of our independent auditors and review procedures for internal
auditing and the adequacy of our internal accounting controls. The Committee
held 4 meetings during 2001 and all members of the Committee in 2001 attended
each of the meetings.
Compensation Committee.
The members of the Compensation Committee are: Don J. Gunther, Chairman,
William A. Bruckmann, III and William W. Hanna. The members of the Compensation
Committee oversee related compensation decisions for the officers of our general
partner. The Committee held 1 meeting during 2001 and all members of the
Committee in 2001 were in attendance.
Conflicts Committee.
The members of the Conflicts Committee are: William A. Bruckmann, III,
Chairman, Don J. Gunther and William W. Hanna. The Conflicts Committee reviews
specific matters which the board of directors believe may involve conflicts of
interest. The Conflicts Committee will determine if the resolution of the
conflict of interest is fair and reasonable to us. The members of the Conflicts
Committee are not officers or employees of our general partner or directors,
officers or employees of its affiliates. The Committee held 2 meetings during
2001 and all members of the Committee in 2001 were in attendance.
Compensation of Directors.
Employee directors receive no additional compensation for service on our
general partner's Board of Directors or Committees of the Board. Nonemployee
directors receive an annual retainer of $10,000 in cash and 400 of our common
units. Chairmen of the Audit, Compensation and Conflicts Committees receive an
annual retainer of $1,000. Nonemployee directors receive $1,000 for each Board
meeting attended and $500 for each Audit, Compensation or Conflicts Committee
meeting attended.
Nonemployee directors may elect to receive all or any part of cash fees in
the form of common units or phantom units. Phantom units may be deferred to any
subsequent year or until such individual ceases to be a director. Nonemployee
directors may also elect to defer receipt of their annual unit retainer to any
subsequent year or until such individual ceases to be a director. Distribution
equivalents are paid on phantom units and may be received in cash or reinvested
in additional phantom units. One director elected to defer fees under this plan
in 2001.
In addition, each independent director will be reimbursed for out-of-pocket
expenses in connection with attending meetings of the board of directors or
committees. Each director will be fully indemnified by us for actions associated
with being a director to the extent permitted under Delaware law.
66
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of units held by
beneficial owners of five percent or more of the units, by directors of the
general partner, by each named executive officer of the general partner and by
all directors and executive officers of the general partner as a group as of
February 28, 2002.
PERCENTAGE OF PERCENTAGE OF
COMMON COMMON SUBORDINATED SUBORDINATED PERCENTAGE OF
NAME OF BENEFICIAL OWNER UNITS UNITS UNITS UNITS TOTAL UNITS
------------------------ ------- ------------- ------------ ------------- -------------
Williams Energy Services,
LLC(1).......................... 757,193 13.3 4,589,193 80.8 47.1
Williams Natural Gas Liquids,
Inc.(1)......................... 322,501 5.7 1,090,501 19.2 12.4
Steven J. Malcolm(3)(4)........... 2,500 -- -- --
Phillip D. Wright(2)(4)........... -- -- -- -- --
Don R. Wellendorf(4).............. -- -- -- -- --
Jay A. Wiese(4)................... -- -- -- -- --
Craig R. Rich(4).................. -- -- -- -- --
Keith E. Bailey(3)(4)............. -- -- -- -- --
Don J. Gunther(4)................. -- -- -- -- --
William A. Bruckmann, III(4)...... -- -- -- -- --
William W. "Bill" Hanna(4)........ -- -- -- -- --
All directors and executive
officers as a Group (nine
persons)(4)..................... -- -- -- -- --
---------------
(1) Williams GP LLC is owned through Williams Energy Services, LLC and Williams
Natural Gas Liquids, Inc., which are subsidiaries of The Williams Companies,
Inc. The address of The Williams Companies, Inc., Williams Energy Services,
LLC and Williams Natural Gas Liquids, Inc. is One Williams Center, Tulsa,
Oklahoma 74172.
(2) Does not include any common units or subordinated units owned by Williams
Energy Services, LLC or by Williams Natural Gas Liquids, Inc. Mr. Wright in
his capacity as Chairman and Chief Executive Officer of Williams Energy
Services, LLC and as Chairman, President and Director of Williams Natural
Gas Liquids, Inc. may be deemed to beneficially own these units.
(3) Does not include any common units or subordinated units owned by Williams
Energy Services, LLC or by Williams Natural Gas Liquids, Inc. Mr. Bailey in
his capacity as Chairman and Mr. Malcolm in his capacity as Chief Executive
Officer of The Williams Companies, Inc., which is the owner of Williams
Energy Services, LLC and Williams Natural Gas Liquids, Inc., may be deemed
to beneficially own these units.
(4) In each instance, a dash ( -- ) indicates that the individual or group does
not own any units, or the percentage calculation is less than 0.1 percent.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Steve Malcolm, Phil Wright and Don Wellendorf serve in various capacities
as executive officers of The Williams Companies, Inc., Williams Energy Services,
LLC and Williams Natural Gas Liquids, Inc. For more information with respect to
each individual's roles with these affiliated entities, please read "Item 10.
Partnership Management -- Directors and Executive Officers of Williams GP LLC"
on page 61.
Williams Energy Marketing & Trading Company and Williams Refining &
Marketing, L.L.C., subsidiaries of The Williams Companies, Inc. and affiliates
of the Partnership, are significant customers at our petroleum product
terminals, representing 11.0 percent and 7.2 percent, respectively, of our total
revenues for the year ended December 31, 2001. The services we provide them are
conducted pursuant to various contracts between them and the Partnership. For
additional information relating to our commercial agreements with The Williams
Companies and its affiliates, please read "Management's Discussion & Analysis of
Financial Condition and Results of Operations -- Related Party Transactions,"
which begins on page 31.
67
Affiliates of The Williams Companies, Inc. own 1,079,694 common units and
5,679,694 subordinated units representing an approximate aggregate 60 percent
limited partner interest in us and Williams OLP, L.P. In addition, Williams GP
LLC owns an aggregate 2 percent general partner interest in us and Williams OLP,
L.P. The general partner's ability, as general partner, to manage and operate
Williams Energy Partners and The Williams Companies, Inc.'s affiliates'
ownership of an approximate aggregate 60 percent limited partner interest in us
effectively gives the general partner the right to veto some actions of Williams
Energy Partners and to control the management of Williams Energy Partners L.P.
DISTRIBUTIONS AND PAYMENTS TO THE GENERAL PARTNER AND ITS AFFILIATES
The following table summarizes the distributions and payments to be made by
us to our general partner and its affiliates in connection with the formation,
ongoing operation and liquidation of Williams Energy Partners. These
distributions and payments were determined by and among affiliated entities and
are not the result of arm's length negotiations.
FORMATION STAGE
The consideration received by our
general partner and its affiliates,
Williams Energy Services, LLC and
Williams Natural Gas Liquids,
Inc., for the transfer of the
affiliates' interests in the
subsidiaries and a capital
contribution...................... 1,679,694 common units and 5,679,694
subordinated units;
a combined 2 percent general partner
interest in Williams Energy Partners
L.P. and Williams OLP, L.P.;
the incentive distribution rights; and
$166.5 million of the net proceeds of
our initial public offering of the
common units and the borrowings under
the credit facility. In addition, the
net proceeds of $12.1 million from the
exercise of the underwriters'
over-allotment option in our initial
public offering were used to redeem
600,000 common units from Williams
Energy Services, LLC, an affiliate of
the general partner, as partial
reimbursement for capital expenditures
incurred by Williams Energy Services,
LLC for assets we own after the initial
public offering.
Williams Energy Services, LLC and
Williams Natural Gas Liquids, Inc.,
affiliates of The Williams Companies,
Inc., transferred to us their interests
in the entities that became our
subsidiaries in exchange for 1,679,694
common units, 5,679,694 subordinated
units, the incentive distribution
rights and the combined 2 percent
general partner interest described
above. The common units and
subordinated units received by Williams
Energy Services, LLC and Williams
Natural Gas Liquids, Inc. were valued
at the $21.50 initial public offering
price. In addition, the over-allotment
was exercised for 600,000 common units.
Those units were redeemed from the
1,357,193 common units initially owned
by
68
Williams Energy Services, LLC. After
the redemption of these units,
affiliates of the Partnership owned
1,079,694 common units.
OPERATIONAL STAGE
Distributions of available cash to
our general partner and its
affiliates........................ Cash distributions will generally be
made 98 percent to the unitholders,
including to affiliates of the general
partner as holders of common units and
subordinated units, and 2 percent to
the general partner. However,
distributions that exceed the specified
target levels will result in our
general partner receiving increasing
percentages of the distributions, up to
50 percent of the distributions above
the highest target level.
Assuming we have sufficient available
cash to continue to pay distributions
on all of our outstanding units for
four quarters at our current
distribution level of $0.59 per unit
per quarter, our general partner and
its affiliates would receive annual
distributions of approximately $0.6
million on the combined 2 percent
general partner interest and a
distribution of approximately $16.0
million on their common and
subordinated units.
Payments to our general partner and
its affiliates...................... Our general partner and its affiliates
will not receive any management fee or
other compensation for the management
of Williams Energy Partners L.P. Our
general partner and its affiliates will
be reimbursed, however, for direct and
indirect expenses incurred on our
behalf. Per the Omnibus Agreement, in
2001 we were charged $6.0 million,
prorated for the Partnership's partial
2001 year, for general and
administrative expenses, excluding
expenses associated with incentive
compensation plans and completed
acquisitions. The annual general and
administrative expense charge was
increased to $6.3 million by the end of
2001. The increase is due to the
incremental general and administrative
expenses associated with acquisitions
made during 2001. In 2002, the annual
general and administrative expense
charge was increased to $6.7 million,
including the annual escalator as
provided in the Partnership's Omnibus
Agreement.
Withdrawal or removal of our general
partner............................. If our general partner withdraws in
violation of the Partnership agreement
or is removed for cause, a successor
general partner has the option to buy
the general partner interests and
incentive distribution rights for a
cash price equal to fair market value.
If our general partner withdraws or is
removed under any other circumstances,
the departing general partner has the
option to require the successor general
partner to buy the departing general
partner's interests and its incentive
69
distribution rights for a cash price
equal to fair market value.
If either of these options is not
exercised, the departing general
partner's interests and incentive
distribution rights will automatically
convert into common units equal to the
fair market value of those interests.
In addition, we will be required to pay
the departing general partner for
expense reimbursements.
LIQUIDATION STAGE
Liquidation......................... Upon our liquidation, the partners,
including our general partner, will be
entitled to receive liquidating
distributions according to their
particular capital account balances.
RIGHTS OF OUR GENERAL PARTNER
Our general partner and its affiliates own 1,079,694 common units and
5,679,694 subordinated units, representing an aggregate 58.3 percent limited
partner interest in Williams Energy Partners L.P. In addition, our general
partner owns an aggregate 2 percent general partner interest in Williams Energy
Partners L.P. and the operating limited Partnership on a combined basis. Through
the general partner's ability, as general partner, to manage and operate our
business and The Williams Companies, Inc.'s affiliates' ownership of 1,079,694
common units and all of the outstanding subordinated units, the general partner
will control the management of our business.
OMNIBUS AGREEMENT
We entered into an agreement in February 2001 with The Williams Companies,
Inc. and its affiliates and our general partner, that governs:
- potential competition among us and the other parties to the agreement;
- reimbursement of general and administrative expenses;
- indemnification for environmental liabilities and right-of-way defects or
failures;
- the grant of a license for use of the ATLAS 2000 software system and
other intellectual property; and
- reimbursement of maintenance capital expenditures.
Competition
The Williams Companies, Inc. and its affiliates have agreed that they will
not own or operate assets that are used to transport, store or distribute
ammonia in the United States or terminal and store refined petroleum products in
the continental United States. We refer to these assets below as restricted
assets. The Williams Companies, Inc. will not be prohibited from owning or
operating the following restricted assets:
- any restricted assets owned, leased or operated by The Williams
Companies, Inc. at the closing of our initial public offering on February
9, 2001;
- any restricted assets acquired after February 9, 2001 with a fair market
value not greater than $20.0 million;
- any restricted assets constructed by The Williams Companies, Inc. after
February 9, 2001 with construction costs not greater than $20.0 million;
and
70
- any restricted assets constructed or acquired by The Williams Companies,
Inc. after February 9, 2001 that are connected to assets owned by The
Williams Companies, Inc. or are primarily related to and located within
50 miles of The Williams Companies, Inc.'s refinery in Memphis,
Tennessee.
If The Williams Companies, Inc. acquires or constructs restricted assets
other than those identified above, it shall offer to sell such assets to us
within six months of acquiring or completing construction. If we and The
Williams Companies, Inc. are unable to agree on the terms of the sale, we and
The Williams Companies, Inc. will appoint a mutually-agreed-upon,
nationally-recognized investment banking firm to determine the fair market value
of the restricted assets. Once the investment bank submits its valuation of the
restricted assets to The Williams Companies, Inc. and us, we will have the
right, but not the obligation, to purchase the business in accordance with the
following process:
- If the valuation of the investment bank is in the range between the
proposed sale and purchase values of The Williams Companies, Inc. and us,
we will have the right to purchase the business at the valuation
submitted by the investment bank.
- If the valuation of the investment bank is less than the proposed
purchase value submitted by us, we will have the right to purchase the
business for the amount submitted by us.
- If the valuation of the investment bank is greater than the proposed sale
value submitted by The Williams Companies, Inc., we will have the right
to purchase the business for the amount submitted by The Williams
Companies, Inc.
If we elect not to purchase any restricted assets, The Williams Companies,
Inc. will be permitted to own or operate such assets without limitation.
General and Administrative Expenses
In 2002, we will reimburse the general partner or The Williams Companies,
Inc. for general and administrative expenses of not more than $6.7 million,
excluding expenses associated with our Long-Term Incentive Plan. This amount may
increase during the next nine years as follows:
- In each year after 2002, the amount of general and administrative
expenses, excluding expenses associated with the Long-Term Incentive
Plan, allocated to us by The Williams Companies, Inc. and the general
partner may increase by no more than the greater of 7 percent or the
percentage increase in the consumer price index for that year.
- If we make an acquisition, our general and administrative expense
allocation may increase by the amount of these expenses included in our
valuation of the business we acquire.
Indemnification
Williams Energy Services, LLC and Williams Natural Gas Liquids, Inc. have
agreed to indemnify us for up to $15.0 million for environmental liabilities
that exceed the amounts covered by the seller indemnities and insurance
coverage. The indemnity applies to environmental liabilities arising from
conduct prior to February 9, 2001 and discovered within three years of February
9, 2001. Liabilities resulting from a change in law after February 9, 2001 are
excluded from this indemnity. Williams Natural Gas Liquids, Inc. will indemnify
us for right-of-way defects or failures in our ammonia pipeline for 15 years
after the date of February 9, 2001. Williams Energy Services, LLC will indemnify
us for right-of-way defects or failures associated with our marine terminal
facilities at Galena Park, Corpus Christi and Marrero for 15 years after
February 9, 2001.
ATLAS 2000 License
The Williams Companies, Inc. and its affiliates have granted a license to
us for the use of the ATLAS 2000 software system (and to permit customers to use
the system to track inventories) and other intellectual property, including our
logo, for as long as The Williams Companies, Inc. controls our general partner,
at no charge.
71
Maintenance Capital Expenditures
In 2001 and 2002, The Williams Companies, Inc. will reimburse us for
maintenance capital expenditures for our current operations in excess of $4.9
million per year, subject to a maximum aggregate reimbursement of $15.0 million
over this two year period.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1 and 2.
PAGE
----
Covered by reports of independent auditors:
Consolidated statements of income for the three years
ended December 31, 2001................................ 36
Consolidated balance sheets at December 31, 2001 and
2000................................................... 37
Consolidated statements of cash flows for the three years
ended December 31, 2001................................ 38
Consolidated statement of partners' capital............... 39
Notes 1 through 19 to Consolidated financial statements... 40
Not covered by reports of independent auditors:
Quarterly financial data (unaudited) -- See Note 14 to
Consolidated financial statements...................... 55
Registration statement -- See Note 18..................... 57
All other schedules have been omitted since the required information is not
present or is not present in amounts sufficient to require submission of the
schedule, or because the information required is included in the financial
statements and notes thereto.
(a) 3 and (c). The exhibits listed below are filed as part of this annual
report.
EXHIBIT NO. DESCRIPTION
----------- -----------
Exhibit 3
*(a) -- Amended and Restated Agreement of Limited Partnership of
Williams Energy Partners L.P. dated February 9, 2001.
*(b) -- Amended and Restated Agreement of Limited Partnership of
Williams OLP, L.P. dated February 9, 2001.
**(c) -- Second Restated and Amended LLC Agreement for Williams GP
LLC (filed as Exhibit 4.3 to Form S-8 filed October 16,
2001).
*(d) -- Reorganization Agreement dated March 4, 2002 among
Williams Energy Partners L.P., Williams OLP, L.P.,
Williams GP LLC, and Williams GP Inc.
Exhibit 10
*(a) -- Credit Agreement dated February 6, 2001 between Williams
OLP, L.P., Bank of America, N.A., Lehman Commercial
Paper, Inc., and Suntrust Bank, including Amendment No. 1
dated July 31, 2001, and Amendment No. 2 dated July 31,
2001.
*(b) -- Contribution, Conveyance and Assumption Agreement dated
February 9, 2001, between Williams Energy Partners L.P.;
Williams OLP, L.P.; Williams GP LLC; Williams Energy
Services, LLC; Williams Natural Gas Liquids, Inc.;
Williams NGL, LLC; Williams Terminal Holdings, L.P.;
Williams Terminal Holdings, L.L.C.; Williams Ammonia
Pipeline, L.P. and Williams Bio-Energy, LLC.
72
EXHIBIT NO. DESCRIPTION
----------- -----------
*(c) -- Omnibus Agreement dated February 9, 2001, between
Williams Companies, Inc.; Williams Energy Services, LLC;
Williams Natural Gas Liquids, Inc.; Williams Pipe Line
Company, LLC; Williams Information Services Corporation;
Williams Energy Partners L.P.; Williams OLP, L.P. and
Williams GP LLC, and Amendment 1 to the Omnibus Agreement
dated January 28, 2002.
*(d) -- Purchase and Sale Agreement dated October 18, 2001,
between Geonet Gathering, Inc. and Williams Terminals
Holdings, L.P., including Exhibits A, B, C and D.
*(e) -- Products Terminalling Agreement dated November 1, 2001,
between Williams Terminals Holdings, L.P. and Williams
Energy Marketing & Trading Company.
*(f) -- Facilities Sale Agreement dated June 30, 2001, between
Transmontaigne, Inc. and Williams Terminals Holdings,
L.P., including Schedules 2.1(a) and 2.1(b) and (c).
**(g) -- Williams Energy Partners Long-Term Incentive Plan (filed
as Exhibit 4.1 to Form S-8 filed October 16, 2001).
*Exhibit 21 -- Subsidiaries of Williams GP LLC.
*Exhibit 23.1 -- Consent of Independent Auditor.
*Exhibit 24 -- Power of Attorney together with certified resolution.
*Exhibit 99 -- Williams GP LLC's balance sheet of December 31, 2001 and
notes thereto.
---------------
*Each such exhibit has heretofore been filed with the Securities and Exchange
Commission with the Form 10-K Annual Report of Williams Energy Partners L.P.
for the year ended December 31, 2001.
** Each such exhibit has heretofore been filed with the Securities and Exchange
Commission as part of the filing indicated and is incorporated herein by
reference.
(c) Reports on Form 8-K.
The Partnership's unaudited earnings for the three and six months
ending September 30, 2001 and 2000, were issued on Form 8-K on October 25,
2001.
The Partnership announced its acquisition of a petroleum storage and
distribution facility in Gibson, Louisiana from Geonet Gathering, Inc. on
Form 8-K on November 8, 2001.
(d) We do not own any partially-owned companies.
73
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, we have duly caused this report to be signed on our behalf
by the undersigned, thereunto duly authorized.
WILLIAMS ENERGY PARTNERS L.P.
(Registrant)
By: Williams GP LLC, its General
Partner
By: /s/ SUZANNE H. COSTIN
------------------------------------
Suzanne H. Costin
Attorney-in-fact
Date: May 3, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on our behalf and in the
capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ STEVEN J. MALCOLM* Chief Executive Officer (Principal May 3, 2002
------------------------------------------------ Executive Officer) and Chairman
Steven J. Malcolm of the Board of Williams GP LLC,
General Partner of Williams
Energy Partners L.P.
/s/ DON R. WELLENDORF* Senior Vice President, Chief May 3, 2002
------------------------------------------------ Financial Officer and Treasurer
Don R. Wellendorf (Principal Financial and
Accounting Officer) of Williams
GP LLC, General Partner of
Williams Energy Partners L.P.
/s/ PHILLIP D. WRIGHT* President, Chief Operating Officer May 3, 2002
------------------------------------------------ and Director of Williams GP LLC,
Phillip D. Wright General Partner of Williams
Energy Partners L.P.
/s/ KEITH E. BAILEY* Director of Williams GP LLC, May 3, 2002
------------------------------------------------ General Partner of Williams
Keith E. Bailey Energy Partners L.P.
/s/ WILLIAM A. BRUCKMANN, III* Director of Williams GP LLC, May 3, 2002
------------------------------------------------ General Partner of Williams
William A. Bruckmann, III Energy Partners L.P.
/s/ DON J. GUNTHER* Director of Williams GP LLC, May 3, 2002
------------------------------------------------ General Partner of Williams
Don J. Gunther Energy Partners L.P.
74
SIGNATURE TITLE DATE
--------- ----- ----
/s/ WILLIAM W. HANNA* Director of Williams GP LLC, May 3, 2002
------------------------------------------------ General Partner of Williams
William W. Hanna Energy Partners L.P.
*By: /s/ SUZANNE H. COSTIN May 3, 2002
------------------------------------------
Suzanne H. Costin
Attorney-in-fact
75
INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION
----------- -----------
Exhibit 3
*(a) -- Amended and Restated Agreement of Limited Partnership of
Williams Energy Partners L.P. dated February 9, 2001.
*(b) -- Amended and Restated Agreement of Limited Partnership of
Williams OLP, L.P. dated February 9, 2001.
**(c) -- Second Restated and Amended LLC Agreement for Williams GP
LLC (filed as Exhibit 4.3 to Form S-8 filed October 16,
2001).
*(d) -- Reorganization Agreement dated March 4, 2002 among
Williams Energy Partners L.P., Williams OLP, L.P.,
Williams GP LLC, and Williams GP Inc.
Exhibit 10
*(a) -- Credit Agreement dated February 6, 2001 between Williams
OLP, L.P., Bank of America, N.A., Lehman Commercial
Paper, Inc., and Suntrust Bank, including Amendment No. 1
dated July 31, 2001, and Amendment No. 2 dated July 31,
2001.
*(b) -- Contribution, Conveyance and Assumption Agreement dated
February 9, 2001, between Williams Energy Partners L.P.;
Williams OLP, L.P.; Williams GP LLC; Williams Energy
Services, LLC; Williams Natural Gas Liquids, Inc.;
Williams NGL, LLC; Williams Terminal Holdings, L.P.;
Williams Terminal Holdings, L.L.C.; Williams Ammonia
Pipeline, L.P. and Williams Bio-Energy, LLC.
*(c) -- Omnibus Agreement dated February 9, 2001, between
Williams Companies, Inc.; Williams Energy Services, LLC;
Williams Natural Gas Liquids, Inc.; Williams Pipe Line
Company, LLC; Williams Information Services Corporation;
Williams Energy Partners L.P.; Williams OLP, L.P. and
Williams GP LLC, and Amendment 1 to the Omnibus Agreement
dated January 28, 2002.
*(d) -- Purchase and Sale Agreement dated October 18, 2001,
between Geonet Gathering, Inc. and Williams Terminals
Holdings, L.P., including Exhibits A, B, C and D.
*(e) -- Products Terminalling Agreement dated November 1, 2001,
between Williams Terminals Holdings, L.P. and Williams
Energy Marketing & Trading Company.
*(f) -- Facilities Sale Agreement dated June 30, 2001, between
Transmontaigne, Inc. and Williams Terminals Holdings,
L.P., including Schedules 2.1(a) and 2.1(b) and (c).
**(g) -- Williams Energy Partners Long-Term Incentive Plan (filed
as Exhibit 4.1 to Form S-8 filed October 16, 2001).
*Exhibit 21 -- Subsidiaries of Williams GP LLC.
*Exhibit 23.1 -- Consent of Independent Auditor.
*Exhibit 24 -- Power of Attorney together with certified resolution.
*Exhibit 99 -- Williams GP LLC's balance sheet of December 31, 2001 and
notes thereto.
---------------
*Each such exhibit has heretofore been filed with the Securities and Exchange
Commission with Form 10-K Annual Report of Williams Energy Partners L.P. for
the year ended December 31, 2001.
** Each such exhibit has heretofore been filed with the Securities and Exchange
Commission as part of the filing indicated and is incorporated herein by
reference.