Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
x |
Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended June 30, 2002
OR
¨ |
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the transition period
to
Commission File Number 001-11763
TRANSMONTAIGNE INC.
| Delaware |
06-1052062 | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
2750 Republic Plaza, 370 Seventeenth Street
Denver, Colorado 80202
(Address, including zip code, of principal executive
offices)
(303) 626-8200
(Telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class |
Name of Each Exchange on Which
Registered | |
| Common Stock; $.01 par value |
American Stock Exchange |
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 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 report), 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 voting stock held by non-affiliates of the Registrant was $138,360,557. The aggregate market
value was computed by reference to the last sale price ($5.11 per share) of the Registrant’s Common Stock on the American Stock Exchange on August 30, 2002.
The number of shares of the registrant’s Common Stock outstanding on August 30, 2002 was 39,934,767.
Table of Contents
| Item |
Page No. | |||
| Part I |
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| 3 | ||||
| 10 | ||||
| 12 | ||||
| 12 | ||||
| Part II |
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| 13 | ||||
| 14 | ||||
| 16 | ||||
| 41 | ||||
| 43 | ||||
| 77 | ||||
| Part III |
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| 77 | ||||
| 77 | ||||
| 77 | ||||
| 77 | ||||
| Part IV |
||||
| 77 | ||||
| Certifications |
82 |
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PART I
This Annual Report contains certain forward-looking statements and information relating to TransMontaigne Inc. that are based on beliefs and assumptions made by us as well as information currently available to us. When used
in this document, the words “anticipate,” “believe,” “estimate,” “expect,” and similar expressions, are intended to identify forward-looking statements. Such statements reflect our current views with respect
to future events and are subject to certain risks, uncertainties, and assumptions. Should one or mores of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those
described herein as anticipated, believed, estimated or expected. We do not intend to update these forward-looking statements except as required by law.
General
TransMontaigne Inc., a Delaware corporation (“TransMontaigne”), was formed in 1995 to create an independent petroleum products merchant based in Denver,
Colorado. We are a holding company that conducts our commercial activities primarily in the Mid-Continent, Gulf Coast, Southeast, Mid-Atlantic and Northeast regions of the United States. Our commercial activities currently are divided into two main
areas: (i) Product supply, distribution, and marketing services, and (ii) Terminal and pipeline operations.
We
are seeking to expand our terminal and pipeline operations by acquiring strategically-located terminal and pipeline assets. We are evaluating opportunities to expand our terminal and pipeline infrastructure in the United States, including entering
into operating agreements with major energy companies to operate their terminal facilities. Growth by acquisition will be complemented by construction of new projects and expansion of existing facilities in specific locations to increase our present
operating capabilities. We also are seeking to expand the spectrum of commodities that we handle and markets that we serve to increase the utilization of our Products supply, distribution and marketing operations. In addition, we are aggressively
pursuing additional industrial/commercial end-users to grow our energy-related supply chain management services. Capital to finance acquisitions and expand our commercial operations may be provided by borrowings under existing credit facilities, the
issuance of debt in the capital markets, the sale of additional common stock, and cash flow from operating activities.
Commercial
Activities
We provide a broad range of integrated supply, distribution, transportation, storage, and
marketing services to refiners, distributors, marketers, and industrial/commercial end-users of refined petroleum products (e.g., gasoline, diesel fuel and heating oil), chemicals, crude oil and other bulk liquids (collectively referred to as
“Product”).
We purchase Product primarily from refineries in Texas and Louisiana and schedule
transportation of the Product to our and third-party terminals on common carrier pipelines. Simultaneously, we enter into risk management contracts, principally futures contacts on the New York Mercantile Exchange (“NYMEX”) to sell Product
at a specified future date, to reduce our exposure to changes in commodity prices. Upon sale and delivery of the physical inventory of Product to a third party, we enter into a second risk management contract that offsets the original contract in
both timing and amount and, effectively, cancels our original NYMEX position.
We seek to maintain a balanced
position of forward sale commitments against our discretionary inventories and forward purchase commitments, thereby minimizing or eliminating exposure to commodity price
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fluctuations. We evaluate our exposure to commodity price risk from an overall portfolio basis that considers the continuous movement of discretionary inventory volumes and the open positions in
energy services and risk management contracts. However, there are certain risks that we do not attempt to hedge or eliminate. For example, differences in commodity prices exist between delivery locations that are not attributable to the cost of
transportation. We refer to these differences in commodity prices between delivery locations as “basis (geographical location) differentials.” We attempt to exploit the basis (geographical location) differentials by transporting the
Product to the delivery location that maximizes the value of the Product to us. We move the Product to the desired delivery location by rerouting the transportation of the Product using our pipelines and terminals, as well as third-party pipelines,
barges, vessels, rail cars, and over-the-road tractor trailers. These differentials create opportunities for increased operating margins when we predict the most beneficial location (highest value location) for sales of our discretionary inventories
of Products. However, the margins created from exploiting these market inefficiencies do not occur ratably over our reporting periods.
It is our policy not to acquire Products, futures contracts or other derivative products for the sole purpose of speculating on commodity prices. Risk management policies have been established by our risk management
committee to monitor and control price risks. Our risk management committee is comprised of senior executives of TransMontaigne.
Product Supply, Distribution, and Marketing Services
Overview. Our Product supply, distribution and marketing operations attempt to maximize utilization of our terminal and pipeline infrastructure to market and trade various Products. Our Product supply,
distribution, and marketing margins are generated from bulk sales, exchanges of Products with major and large independent energy companies; wholesale distribution and sales of Products to jobbers and retailers (referred to as “rack
sales”); distribution and sales of Products to regional and national industrial/commercial end-users; and tailored fuel and risk management logistical services arrangements to wholesale, retail and industrial/commercial end-users. Our storage
capacity and forward sales transactions enable us to purchase Product inventories; store inventory utilizing owned and leased tank space, as well as line space controlled by us in major common carrier pipelines; arbitrage basis (geographical
location) differentials and transportation costs; and, depending upon market conditions, realize margins through sales in the future cash market or by using NYMEX contracts. In addition, we provide risk management products and logistical services to
gasoline and distillate customers that minimize the customer’s exposure to both commodity price movements and basis (geographical location) differentials. We provide these services to customers for periods as short as one month to terms that
span up to three years. The type and length of contracts provided by us will vary based upon market conditions, customer needs, and the risk management practices of the individual customer. The margins created from the risk-management contracts that
we enter into with our customers do not occur ratably over our reporting periods and can cause operating results to fluctuate from one period to the next.
Generally, as we purchase discretionary inventory at prevailing prices from refiners and producers at production points and common trading locations, we simultaneously attempt to establish or
“lock-in” a margin by selling the Product for physical delivery to third party users or by entering into a future delivery obligation, such as a futures contract on the NYMEX. We seek to maintain a balanced position of forward sale
commitments against our discretionary inventories and forward purchase commitments, thereby minimizing exposure to commodity price fluctuations occurring after the initial transactions. However, certain risks (e.g., basis (geographical location)
differentials, types of Product or delivery periods) cannot be completely hedged or eliminated.
Our discretionary
inventories of Product are shipped via our pipelines or third party-owned barges, vessels, and pipelines to our terminals or to third-party terminal locations. From these terminal locations, the Products are made available to our customers through
daily-priced rack sales, exchange agreements, and contract sales.
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Rack Sales. We manage the physical quantity of our
discretionary inventories of Product through daily-priced rack sales. On a daily basis we establish the selling price for each Product for each of our delivery locations/terminals. We announce or “post” those selling prices to independent
local jobbers via facsimile, website, email, and telephone communications. Our selling price of a particular Product on a particular day is a function of our supply at that delivery location/terminal and our estimate of the costs to replenish the
Product at that delivery location. The demand for a particular Product is sensitive to changes in pricing. If our objective is to increase demand for a particular Product at a specific delivery location, we would post the selling price of that
Product at the low end of the range of prices being offered in that location to increase our local demand. If our objective is to decrease demand for a particular Product at a specified delivery location, we would post the selling price at the high
end of the range of prices being offered in that location to reduce our local demand. For the years ended June 30, 2002 and 2001, we averaged approximately 110,000 and 64,000 barrels per day, respectively, of delivered volumes under
daily-priced rack sales.
Exchanges. Exchange agreements are entered into with major
oil companies and independent refiners. These agreements provide for the exchange of Product at one delivery location for Product at a different location. We generally receive a fee based on the volume of the Product exchanged. That fee takes into
account the cost of transportation from the receipt location to the exchange delivery location. For the years ended June 30, 2002 and 2001, we averaged approximately 110,000 and 170,000 barrels per day, respectively, of delivered volumes under
exchange agreements.
Bulk and Cycle Sales. Bulk and cycle sales of Products are
entered into with major oil companies and independent refiners. These transactions involve the sale of Products in large quantities in liquid bulk markets (Pasadena, TX, New York Harbor, Chicago, IL, Tulsa, OK refining area, and Los Angeles, CA).
These transactions also involve the sale of Products in large quantities prior to scheduled delivery to us by producers and refiners for transportation by pipelines, barges, vessels, or rail cars to our terminals. These transactions may occur while
the Products are in transit prior to reaching our terminals. For the years ended June 30, 2002 and 2001, we averaged approximately 340,000 and 260,000 barrels per day, respectively, of delivered volumes under bulk and cycle sales.
Contract Sales. Contract sales of Products are conducted from our and third-party terminal,
storage, and delivery locations with independent local jobbers, industrial/commercial end users, and governmental agencies. Contract sales provide these customers with a specified volume of Product over a specified term at a specified price. The
terms of these contracts range from as short as one month to terms that span up to three years. At the customer’s option, the pricing of the Product delivered under a contract sale may be fixed at a stipulated price per gallon, or it may vary
based on changes in published indices (e.g., OPIS and Platts). For the years ended June 30, 2002 and 2001, we averaged approximately 80,000 and 60,000 barrels per day, respectively, of delivered volumes under contract sales.
Energy Services. We provide “supply chain management” services to our
industrial/commercial end-users downstream of the truck loading rack location. Fuel and risk management logistical services provide our large and small volume customers an assured, cost effective delivered source of Products supply through our
pipelines and terminals, as well as through third-party pipeline, terminal, truck, rail and barge distribution channels. Customers of our “supply chain management” services receive the benefits of our web-based technology systems enabling
the customers to minimize their total Product costs while meeting their volumetric needs. As a result of this service, a customer can reduce the processing time associated with dispatching Product to its physical locations, processing payments
associated with Product purchases at both bulk and retail locations, and obtain other costs savings associated with procuring Product. By aggregating the demands of various customers, we are able to leverage the demand and build relationships with
other companies along the supply and distribution chain that benefit all the parties through reductions in the “back office” processing costs associated with buying and selling Products. We generally receive a fee based on the volume of
the Products we originate for the customer.
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Dedicated Capacity. Using our dedicated pipeline
capacity, we averaged in the aggregate approximately 220,000 and 230,000 barrels per day of transported volumes on the Colonial, Plantation, Explorer, and Teppco pipeline systems for the years ended June 30, 2002 and 2001, respectively. We also
transport Product to our terminals by barges, vessels, and rail cars.
Terminals and Pipelines
Overview. Our Product supply, distribution and marketing operations
generally utilize our terminal and pipeline infrastructure to market and trade various Products and provide specialized supply, logistical, and risk management services to our customers. We own and operate an extensive terminal infrastructure that
handles Products with transportation connections via pipelines, barges, rail cars and trucks to our facilities, or to third-party facilities. As of June 30, 2002, we owned and operated the following facilities: 30 delivery locations/terminals with
approximately 9.9 million barrels of tank space capacity along the Colonial and Plantation pipeline systems; 3 delivery locations/terminals with approximately 500,000 barrels of tank space capacity along the Williams pipeline system; 3 delivery
locations/terminals with approximately 1.0 million barrels of tank capacity along the Florida coast; 1 delivery location/terminal with approximately 2.2 million barrels of tank capacity in Brownsville, Texas; and 12 delivery locations/terminals with
approximately 2.9 million barrels of tank capacity along the Mississippi and Ohio rivers.
We own an interstate
Products pipeline operating from Mt. Vernon, Missouri to Rogers, Arkansas (the “Razorback Pipeline”), together with associated terminal facilities at Mt. Vernon and Rogers. The Razorback Pipeline is the only Products pipeline providing
transportation services to northwest Arkansas. Effective June 30, 2002, we acquired for cash consideration of approximately $7.2 million the remaining 40% interest in the Razorback Pipeline that we did not previously own. We also own and operate a
small intrastate crude oil gathering pipeline system, located in east Texas (the “CETEX pipeline”).
The
success of our terminal and pipeline operations depends in large part on the level of demand for Products by end users in the geographic locations served by such facilities and the ability and willingness of our customers to supply such demand by
utilizing our terminals and pipelines as opposed to the terminals and pipelines of other companies. At our terminals and pipelines, we provide throughput, storage, and transportation related services to distributors, marketers and
industrial/commercial end-users of Products.
Throughput Revenues. Terminal
throughput fees are based on the volume of Products handled at the facility’s truck loading racks, generally at a standard rate per gallon. For the years ended June 30, 2002 and 2001, we averaged approximately 520,000 and 620,000 barrels per
day, respectively, of throughput volumes at our terminals.
Storage
Revenues. Terminal storage fees generally are based on a per barrel rate or tank space capacity committed and will vary with the duration of the arrangement, the Product stored and special handling requirements,
particularly when certain types of chemicals and other bulk liquids are involved.
Transportation
Revenues. Pipeline transportation fees are based on the volume of Products transported and the distance from the origin point to the delivery point. For the years ended June 30, 2002 and 2001, we averaged approximately
24,000 and 74,000 barrels, respectively, of transported volumes through our pipelines.
Sale of NORCO,
Little Rock and Bear Paw
We owned and operated an interstate Products pipeline from Ft. Madison, Iowa
through Chicago, Illinois to Toledo, Ohio (the “NORCO Pipeline”) and associated storage facilities located at Hartsdale, East Chicago and Indianapolis, Indiana and Toledo, Ohio and related product distribution facilities located at South
Bend, Indiana; Peoria, Illinois; and Bryan, Ohio. On July 31, 2001, we completed the sale of the NORCO Pipeline system and related terminals (“NORCO”) to Buckeye Partners L.P. for cash consideration of approximately $62.0 million.
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On June 30, 2001, we completed the sale of the Little Rock terminal to Williams
Energy Partners L.P. for cash consideration of approximately $29.0 million. On July 3, 2001, we received the cash proceeds from Williams Energy Partners L.P.
We previously provided selected natural gas services including the gathering, processing, fractionating and marketing of natural gas liquids (“NGL”) and natural gas, through Bear Paw Energy
Inc., a wholly-owned subsidiary. On December 31, 1999, we sold Bear Paw Energy Inc. to BPE Acquisition LLC for cash consideration of approximately $131.2 million.
See Note 2 of Notes to Consolidated Financial Statements.
Investments in Petroleum Related Assets
We own 18.04% of the common stock
of Lion Oil Company (“Lion”), a refinery located in Arkansas. At June 30, 2002 and 2001, our investment in Lion, carried at cost, was approximately $10.1 million.
On July 27, 2001, we sold 861 shares of the common stock of West Shore Pipeline Company (“West Shore”), thereby reducing our ownership interest to 18.50%. The
West Shore common stock was sold to Midwest Pipeline Company, LLC for cash consideration of approximately $2.9 million. We sold our remaining 18.50% interest on October 29, 2001 to Buckeye Partners L.P. for cash consideration of approximately $23.1
million.
On May 30, 2002, our 30.02% equity interest in ST Oil Company was reacquired by ST Oil
Company for cash consideration of approximately $3.0 million.
See Note 8 of Notes to Consolidated Financial
Statements.
Tariff Regulations
The Razorback Pipeline, which runs between Mt. Vernon, Missouri and Rogers, Arkansas, is an interstate Products pipeline and is subject to regulation by the Federal Energy Regulatory Commission
(“FERC”) under the Interstate Commerce Act, the Energy Policy Act of 1992 and rules and orders promulgated pursuant thereto. FERC regulation requires that interstate oil pipeline rates be posted publicly and that these rates be “just
and reasonable” and nondiscriminatory. Rates of interstate oil pipeline companies are currently regulated by the FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the change from year to
year in the Producer Price Index for finished goods, less 1% (“PPI Index”). In the alternative, interstate oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings or
actual agreements between shippers and the oil pipeline company.
The CETEX Pipeline, our intrastate crude oil
pipeline located in east Texas, is subject to regulation by the Texas Railroad Commission. Texas regulations require that intrastate tariffs be filed with the Texas Railroad Commission and allows shippers to challenge such tariffs.
Environmental Matters
Our operations are subject to extensive federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, and which require
expenditures for remediation at various operating facilities, as well as expenditures in connection with the construction of new facilities. We believe that our operations and facilities are in material compliance with applicable environmental
regulations. Environmental laws and regulations have changed substantially and rapidly over the last 20 years, and we anticipate that there will be continuing changes. The trend in environmental regulation is to place more restrictions and
limitations on activities that may impact the environment, such as
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emissions of pollutants, generation and disposal of wastes and use and handling of chemical substances. Increasingly strict environmental restrictions and limitations have resulted in increased
operating costs for us and other businesses throughout the United States, and it is possible that the costs of compliance with environmental laws and regulations will continue to increase. We will attempt to anticipate future regulatory requirements
that might be imposed and to plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. It is not anticipated that we will be required in the near future to expend
amounts that are material in relation to our total capital expenditures program to comply with environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, we are unable to predict the ultimate costs and
liabilities of compliance.
Water
The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act (“CWA”), imposes strict controls against the discharge of oil and
its derivates into navigable waters. The CWA provides penalties for any discharges of petroleum products in reportable quantities and imposes substantial potential liability for the costs of removing an oil or hazardous substance spill. State laws
for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum or its derivatives in surface waters or into the groundwater. Spill prevention control and countermeasure
requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum tank spill, rupture or leak.
Contamination resulting from spills or release of refined petroleum products is an inherent risk within the petroleum terminal and
pipeline industry. To the extent that groundwater contamination requiring remediation exists around the assets we own as a result of past operations, we believe any such contamination can be controlled or remedied without having a material adverse
effect on our financial condition. However, such costs are site specific and, therefore, there can be no assurance that the effect will not be material in the aggregate.
The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which addresses three principal areas of oil pollution –
prevention, containment and cleanup, and liability. It applies to vessels, offshore platforms, and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport oil, shore facilities are required
to file oil spill response plans with the United States Coast Guard, the United States Department of Transportation Office of Pipeline Safety (“OPS”) or the Environmental Protection Agency (“EPA”). Numerous states have enacted
laws similar to OPA. Under OPA and similar state laws, responsible parties for a regulated facility from which oil is discharged may be liable for removal costs and natural resources damages. We believe that we are in material compliance with
regulations pursuant to OPA and similar state laws.
The EPA has adopted regulations that require us to have
permits in order to discharge certain storm water run-off. Storm water discharge permits may also be required by certain states in which we operate. Such permits may require us to monitor and sample the effluent. We believe that we are in material
compliance with effluent limitations at existing facilities.
Air Emissions
Our operations are subject to the federal Clean Air Act and comparable state and local statutes. The Clean Air Act Amendments
of 1990 (the “Clean Air Act”) require most industrial operations in the United States to incur capital expenditures in order to meet the air emission control standards that are developed and implemented by the EPA and state environmental
agencies. Pursuant to the Clean Air Act, any of our facilities that emit volatile organic compounds or nitrogen oxides and are located in ozone non-attainment areas face increasingly stringent regulations, including requirements that certain sources
install the reasonably available control technology. Some of our facilities have been included within the categories of hazardous air pollutant sources, and we are in compliance with the currently applicable standards. The Clean Air Act regulations
are still being implemented by the EPA and state agencies, and we do not anticipate that implementation of the regulations will have a material adverse effect on us.
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Safety Regulation
We are subject to regulation by the United States Department of Transportation under the Accountable Pipeline and Safety Partnership Act
of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipeline
facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to make certain reports and provide
information as required by the Secretary of Transportation.
We are subject to OPS regulation requiring
qualification of pipeline personnel. The regulation requires pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. The intent of this regulation is to ensure a
qualified work force and to reduce the probability and consequence of incidents caused by human error. The regulation establishes qualification requirements for individuals performing covered tasks, and amends certain training requirements in
existing regulations.
We are also subject to OPS regulation for High Consequence Areas (“HCA”) for
Category 2 pipeline systems (companies operating less than 500 miles of jurisdictional pipeline). This regulation specifies how to assess, evaluate, repair and validate the integrity of pipeline segments that could impact populated areas, areas
unusually sensitive to environmental damage and commercially navigable waterways, in the event of a release. The pipeline segments that could impact HCAs must be identified by November 18, 2002. The regulation requires an integrity management
program that utilizes internal pipeline inspection, pressure testing, or other equally effective means to assess the integrity of pipeline segments in HCAs. An integrity management program must be completed by February 18, 2003. The program requires
periodic review of pipeline segments in HCAs to ensure adequate preventative and mitigative measures exist. Through this program, we are to evaluate a range of threats to each pipeline segment’s integrity by analyzing available information
about the pipeline segment and consequences of a failure in a HCA. The regulation requires prompt action to address integrity issues raised by the assessment and analysis. The complete baseline assessment of all segments must be performed by
February 17, 2009, with intermediate compliance deadlines prior to that. Our assets that are subject to these requirements are: (1) the Pinebelt Pipeline (the pipeline connecting the Collins and Purvis, Mississippi complexes); (2) the Razorback
Pipeline; (3) the Bellemeade Pipeline (pipeline connecting the Richmond Terminal to the nearby Virginia Power plant); and (4) the Birmingham Terminal pipeline connection to Plantation Pipeline.
We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. We believe that we are in
material compliance with OSHA and state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures.
The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require us
to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, state and local governmental authorities, and local citizens upon request. In general, we
expect to increase our expenditures during the next decade to comply with higher industry and regulatory safety standards such as those described above. Such expenditures cannot be accurately estimated at this time, although we do not believe that
they will have a material adverse impact.
We are subject to OSHA Process Safety Management (“PSM”)
regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified
thresholds; or any process which involves a flammable liquid or gas, as defined in the regulations, stored on-site in one location, in a quantity of 10,000 pounds or more. We believe that we are in material compliance with the PSM regulations.
Employees
We had 440 employees at August 30, 2002. No employees are subject to representation by unions for collective bargaining purposes.
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Our executive offices are located at 2750
Republic Plaza, 370 Seventeenth Street, Denver, Colorado 80202; telephone number (303) 626-8200 and facsimile number (303) 626-8228. In addition, we have an operations office located at 200 Mansell Court East, Suite 600, Roswell, Georgia 30076;
telephone number (770) 518-3500 and facsimile number (770) 518-3567.
On or about March 1, 2003, our executive
offices will be located at 1670 Broadway, Suite 3100, Denver, Colorado 80202.
Our pipelines, approximate miles of
pipeline, and geographical locations are as follows:
| Pipeline Name |
Approximate Miles
of Pipeline |
Geographical Location | ||
| Razorback |
67 |
Mt. Vernon, Missouri south to Rogers, Arkansas | ||
| CETEX |
220 |
East Texas area—north of Tyler, Texas | ||
| NORCO(1) |
480 |
Fort Madison, Iowa east to Toledo, Ohio |
(1) |
This pipeline was sold on July 31, 2001. See Note 2 of Notes to Consolidated Financial Statements. |
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At June 30, 2002, our terminal locations and approximate useable storage capacity
were as follows:
| Locations |
Approximate Useable Storage Capacity (in barrels) | |
| Colonial/Plantation Facilities: |
||
| Albany, GA |
181,000 | |
| Americus, GA |
83,000 | |
| Athens, GA |
165,000 | |
| Atlanta, GA |
370,000 | |
| Bainbridge, GA |
188,000 | |
| Belton, SC |
204,000 | |
| Belton, SC – Piedmont |
258,000 | |
| Birmingham, AL |
533,000 | |
| Charlotte, NC |
400,000 | |
| Charlotte, NC – Piedmont |
290,000 | |
| Collins, MS |
170,000 | |
| Collins, MS (Pipeline Injection Facility) |
1,263,000 | |
| Doraville, GA – Piedmont |
394,000 | |
| Greensboro, NC |
422,000 | |
| Greensboro, NC – Piedmont |
368,000 | |
| Griffin, GA |
93,000 | |
| Lookout Mountain, GA |
195,000 | |
| Macon, GA |
164,000 | |
| Meridian, MS |
120,000 | |
| Montgomery, AL |
124,000 | |
| Montvale, VA |
443,000 | |
| Norfolk, VA |
360,000 | |
| Purvis, MS |
938,000 | |
| Purvis, MS – Piedmont |
124,000 | |
| Rensselaer, NY |
503,000 | |
| Richmond, VA |
414,000 | |
| Rome, GA |
132,000 | |
| Selma, NC – Piedmont |
468,000 | |
| Spartanburg, SC |
286,000 | |
| Spartanburg, SC – Piedmont |
260,000 | |
| | ||
| 9,913,000 | ||
| | ||
| Midwest Facilities: |
||
| Mount Vernon, MO |
198,000 | |
| Rogers, AR |
172,000 | |
| Chippewa Falls, WI |
113,000 | |
| | ||
| 483,000 | ||
| | ||
| Upper River Facilities: |
||
| Evansville, IN |
214,000 | |
| Greater Cincinnati, KY (Covington) |
183,000 | |
| Henderson, KY |
261,000 | |
| New Albany, IN |
177,000 | |
| Louisville, KY |
172,000 | |
| Cape Girardeau, MO |
131,000 | |
| East Liverpool, OH |
206,000 | |
| Owensboro, KY |
147,000 | |
| Paducah, KY Complex |
297,000 | |
| | ||
| 1,788,000 | ||
| |
| Locations |
Approximate Useable Storage Capacity (in barrels) | |
| Lower River Facilities: |
||
| Baton Rouge, LA - Dock facility |
— | |
| Arkansas City, AR |
633,000 | |
| Greenville, MS Complex |
502,000 | |
| | ||
| 1,135,000 | ||
| | ||
| Brownsville Facilities: |
||
| Brownsville, TX Complex |
2,200,000 | |
| | ||
| Florida Facilities: |
||
| Pensacola, FL |
147,000 | |
| Port Everglades, FL |
422,000 | |
| Tampa, FL |
454,000 | |
| | ||
| 1,023,000 | ||
| | ||
| Total Terminal Useable Storage Capacity |
16,542,000 | |
| |
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| Locations |
Approximate Useable Storage Capacity (in barrels) | |
| NORCO Facilities(1): |
||
| Bryan, OH |
67,000 | |
| East Chicago, IN |
1,148,000 | |
| Hartsdale, IN |
918,000 | |
| Indianapolis, IN |
192,000 | |
| Peoria, IL |
169,000 | |
| South Bend, IN |
136,000 | |
| Toledo, OH |
483,000 | |
| | ||
| 3,113,000 | ||
| |
(1) |
These facilities were sold on July 31, 2001. See Note 2 of Notes to Consolidated Financial Statements. |
We have been named as a defendant in
various lawsuits and a party to various other legal proceedings, in the ordinary course of business, some of which are covered in whole or in part by insurance. We believe that the outcome of such lawsuits and other proceedings will not individually
or in the aggregate have a material adverse effect on our consolidated financial condition, results of operations, or cash flows.
No matter was submitted to a
vote of security holders, through the solicitation of proxies or otherwise, during the three months ended June 30, 2002.
12
Table of Contents
PART II
Our common stock is traded on
the American Stock Exchange under the symbol “TMG”. The following table sets forth, for the periods indicated, the range of high and low per share sale prices for our common stock as reported on the American Stock Exchange.
| Low |
High | |||||
| July 1, 2000 through September 30, 2000 |
$ |
4.25 |
$ |
6.50 | ||
| October 1, 2000 through December 31, 2000 |
$ |
2.38 |
$ |
5.50 | ||
| January 1, 2001 through March 31, 2001 |
$ |
2.75 |
$ |
4.50 | ||
| April 1, 2001 through June 30, 2001 |
$ |
3.50 |
$ |
6.10 | ||
| July 1, 2001 through September 30, 2001 |
$ |
4.00 |
$ |
6.75 | ||
| October 1, 2001 through December 31, 2001 |
$ |
4.35 |
$ |
6.30 | ||
| January 1, 2002 through March 31, 2002 |
$ |
5.10 |
$ |
6.00 | ||
| April 1, 2002 through June 30, 2002 |
$ |
4.20 |
$ |
6.05 | ||
On August 30, 2002, the last reported sale price for our common
stock on the American Stock Exchange was $5.11 per share. As of August 30, 2002, there were 443 stockholders of record of our common stock. This number does not include stockholders whose shares are held in trust by other entities. The actual number
of stockholders is greater than the number of stockholders of record. Based on the number of annual reports requested by brokers, we estimate that we have approximately 2,200 beneficial owners of our common stock as of August 30, 2002.
On June 28, 2002, we issued 72,890 shares of Series B Redeemable Convertible Preferred Stock in a transaction exempt from
registration pursuant to Regulation D of the Securities Act of 1933 (see Note 14 of Notes to Consolidated Financial Statements).
No dividends were declared or paid on our common stock during the periods reported in the table above. We intend to retain future cash flow for use in our business and have no current intention of paying dividends to our common
stockholders in the foreseeable future. Any payment of future dividends to our common stockholders and the amounts thereof will depend upon our earnings, financial condition, capital requirements and other factors deemed relevant by our Board of
Directors. Our bank credit facility and certificate of designations of our preferred stock contain restrictions on the payment of dividends on our common stock. Under the terms and conditions of our bank credit facility, we are precluded from paying
a dividend on our common stock without the express consent of the lenders (see Note 12 of Notes to Consolidated Financial Statements). Our preferred stock certificate of designations restricts the payment of cash dividends on our common stock unless
the holders of our preferred stock have received a cash dividend for their immediately preceding dividend payment date. Additionally, we are precluded from paying dividends on our common stock in excess of $10 million during any 12-month period
without the express consent of holders of two-thirds of the then outstanding shares of preferred stock.
13
Table of Contents
The following selected
financial data for the years ended June 30, 2002, 2001, 2000 and 1999; the two months ended June 30, 1998; and the year ended April 30, 1998 has been derived from our consolidated financial statements. This selected financial data should be read in
conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7, and the consolidated financial statements and notes thereto included in Item 8, “Financial Statements and
Supplementary Data.”
TRANSMONTAIGNE INC.
Selected Financial Data
(thousands of dollars)
| Years ended June
30, |
Two months ended
June 30, |
Year ended April 30,
|
|||||||||||||||||
| 2002 |
2001 |
2000 |
1999 |
1998 |
1998 |
||||||||||||||
| STATEMENT OF OPERATIONS DATA: |
|||||||||||||||||||
| Net operating margins(1) |
$ |
91,502 |
|
73,890 |
|
73,597 |
|
64,944 |
|
1,125 |
|
35,889 |
| ||||||
| Impairment of long lived assets |
|
— |
|
— |
|
(50,136 |
) |
— |
|
— |
|
— |
| ||||||
| Corporate relocation and transition |
|
(6,316 |
) |
— |
|
— |
|
— |
|
— |
|
— |
| ||||||
| Operating income (loss) |
|
33,419 |
|
20,308 |
|
(40,563 |
) |
30,179 |
|
(2,586 |
) |
19,234 |
| ||||||
| Interest expense and other financing costs |
|
(21,432 |
) |
(30,424 |
) |
(35,480 |
) |
(30,454 |
) |
(1,769 |
) |
(8,164 |
) | ||||||
| Gain (loss) on disposition of assets, net |
|
(13 |
) |
22,146 |
|
13,930 |
|
— |
|
— |
|
— |
| ||||||
| Net earnings (loss) |
|
8,558 |
|
11,338 |
|
(37,937 |
) |
1,939 |
|
(2,663 |
) |
7,638 |
| ||||||
| Net earnings (loss) attributable to common stockholders |
|
(2,793 |
) |
2,375 |
|
(46,443 |
) |
(335 |
) |
(2,663 |
) |
7,638 |
| ||||||
| OTHER FINANCIAL DATA: |
|||||||||||||||||||
| EBITDA(2) |
|
51,425 |
|
42,878 |
|
33,507 |
|
48,703 |
|
(524 |
) |
29,510 |
| ||||||
| Adjusted EBITDA(3) |
|
64,388 |
|
61,196 |
|
33,507 |
|
48,703 |
|
(524 |
) |
29,510 |
| ||||||
| Capital expenditures |
|
15,809 |
|
11,542 |
|
61,264 |
|
137,556 |
|
6,455 |
|
66,634 |
| ||||||
| STATEMENT OF CASH FLOWS DATA: |
|||||||||||||||||||
| Net cash provided by (used in): |
|||||||||||||||||||
| Operating activities |
|
(89,127 |
) |
35,507 |
|
267,526 |
|
(68,861 |
) |
3,673 |
|
(4,570 |
) | ||||||
| Investing activities |
|
106,822 |
|
(18,969 |
) |
77,902 |
|
(467,040 |
) |
(6,277 |
) |
(66,131 |
) | ||||||
| Financing activities |
|
3,811 |
|
(61,130 |
) |
(305,417 |
) |
522,613 |
|
12 |
|
64,124 |
| ||||||
| BALANCE SHEET DATA: |
|||||||||||||||||||
| Working capital |
|
162,216 |
|
33,872 |
|
134,807 |
|
356,602 |
|
86,467 |
|
94,393 |
| ||||||
| Long-term debt |
|
187,000 |
|
130,000 |
|
202,625 |
|
495,672 |
|
128,971 |
|
128,970 |
| ||||||
| Preferred stock |
|
105,360 |
|
174,825 |
|
170,115 |
|
170,115 |
|
— |
|
— |
| ||||||
| Common stockholders’ equity |
|
205,350 |
|
167,550 |
|
161,983 |
|
205,936 |
|
145,266 |
|
147,804 |
| ||||||
(1) |
Net operating margins represents net revenues, less direct operating costs and expenses. |
(2) |
EBITDA is defined as total net operating margins, less selling, general and administrative expenses, less corporate relocation and transition costs, plus
dividend income from petroleum related investments. We believe that, in addition to cash flow from operating activities and net earnings (loss), EBITDA is a useful financial performance measurement for assessing operating performance since it
provides an additional basis to evaluate our ability to incur and service debt and to fund capital expenditures. In evaluating EBITDA, we believe that consideration should be given, among other things, to the amount by which EBITDA exceeds interest
costs for the period; how EBITDA compares to principal repayments on debt for
|
14
Table of Contents
the period; and how EBITDA compares to capital expenditures for the period. To evaluate EBITDA, the components of EBITDA such as net revenue and direct operating expenses and the variability of
such components over time, also should be considered. EBITDA should not be construed, however, as an alternative to operating income (loss) (as determined in accordance with generally accepted accounting principles (“GAAP”)) as an
indicator of our operating performance, or to cash flows from operating activities (as determined in accordance with GAAP) as a measure of liquidity. Our method of calculating EBITDA may differ from methods used by other companies and, as a result,
EBITDA measures disclosed herein might not be comparable to other similarly titled measures used by other companies. |
(3) |
Adjusted EBITDA is defined as EBITDA, plus lower or cost or market write-downs on our inventories— minimum volumes (see Note 7 of Notes to Consolidated
Financial Statements). We believe that Adjusted EBITDA is the most useful measure in evaluating our performance because it eliminates the impact on our operating results from the impairment of our inventories—minimum volumes.
|
15
Table of Contents
This Annual Report contains certain forward-looking statements and
information relating to TransMontaigne Inc. that are based on beliefs and assumptions made by us as well as information currently available to us. When used in this document, the words “anticipate,” “believe,”
“estimate,” “expect,” and similar expressions, are intended to identify forward-looking statements. Such statements reflect our current views with respect to future events and are subject to certain risks, uncertainties, and
assumptions. Should one or mores of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those described herein as anticipated, believed, estimated or expected. The
Company does not intend to update these forward-looking statements except as required by law.
GENERAL
The following discussion and analysis of the results of operations and financial condition should be read in conjunction with the
consolidated financial statements. Material period-to-period variances in the consolidated statements of operations are discussed under “Results of Operations.” The “Liquidity and Capital Resources” section analyzes cash flows
and financial position.
TransMontaigne Inc. (“TransMontaigne”) was formed in 1995 to create an
independent refined petroleum products merchant based in Denver, Colorado. We are a holding company that conducts our commercial activities primarily in the Mid-Continent, Gulf Coast, Southeast, Mid-Atlantic and Northeast regions of the United
States. We supply, distribute, transport, store, and market refined petroleum products, chemicals, crude oil, and other bulk liquids (collectively referred to as “Products”) to refiners, distributors, marketers, and industrial/commercial
end-users.
Our commercial activities currently are divided into two main areas: (i) Product supply, distribution,
and marketing services, and (ii) Terminal and pipeline operations. Our Product supply, distribution and marketing operations generally utilize our terminal and pipeline infrastructure to market and trade various Products and provide specialized
supply, logistical, and risk management services to our customers.
Product Supply, Distribution, and Marketing Operations
We seek to maintain a balanced position of forward sale commitments against our discretionary inventories and
forward purchase commitments, thereby minimizing or eliminating exposure to commodity price fluctuations. We evaluate our exposure to commodity price risk from an overall portfolio basis that considers the continuous movement of discretionary
inventory volumes and the open positions in energy services and risk management contracts. However, there are certain risks that we do not attempt to hedge or eliminate. For example, we attempt to exploit the price relationships between various
delivery locations (referred to as “basis (geographical location) differentials”). These differentials create opportunities for increased operating margins when we predict the most beneficial location (highest value location) for sales of
our discretionary inventories of refined products. However, the margins created from exploiting these market inefficiencies do not occur ratably over our reporting periods.
Our Product supply, distribution, and marketing operations typically purchase Products at prevailing prices from refiners and producers at production points and common
trading locations. When we purchase Products, we simultaneously sell the Products for physical delivery to third party users or by entering into future delivery obligations, such as, futures contracts on the NYMEX. These futures contracts minimize
or eliminate our exposure to fluctuations in the quoted price of the commodity, but do not minimize exposure to basis (geographical location) differentials. These Products are then shipped via barge, pipelines we own, or third party- owned pipelines
to terminals we own or to third-party terminal locations. From these terminal locations, the Products are made available to our customers either through contract sales, exchange agreements or daily-priced rack sales.
16
Table of Contents
Rack Sales. We manage the physical quantity of our
discretionary inventories of Product through daily-priced rack sales. On a daily basis we establish the selling price for each Product for each of our delivery locations/terminals. We announce or “post” those selling prices to independent
local jobbers via facsimile, website, email, and telephone communications. Our selling price of a particular Product on a particular day is a function of our supply at that delivery location/terminal and our estimate of the costs to replenish the
Product at that delivery location. The demand for a particular Product is sensitive to changes in pricing. If our objective is to increase demand for a particular Product at a specific delivery location, we would post the selling price of that
Product at the low end of the range of prices being offered in that location to increase our local demand. If our objective is to decrease demand for a particular Product at a specified delivery location, we would post a selling price at the high
end of the range of prices being offered in that location to reduce our local demand. For the years ended June 30, 2002 and 2001, we averaged approximately 110,000 and 64,000 barrels per day, respectively, of delivered volumes under
daily-priced rack sales.
Exchanges. Exchange agreements are entered into with major
oil companies and independent refiners. These agreements provide for the exchange of Product at one delivery location for Product at a different location. We generally receive a fee based on the volume of the Product exchanged. That fee takes into
account the cost of transportation from the receipt location to the exchange delivery location. For the years ended June 30, 2002 and 2001, we averaged approximately 110,000 and 170,000 barrels per day, respectively, of delivered volumes under
exchange agreements.
Bulk and Cycle Sales. Bulk and cycle sales of Products are
entered into with major oil companies and independent refiners. These transactions involve the sale of Products in large quantities in liquid bulk markets (Pasadena, TX, New York Harbor, Chicago, IL, Tulsa, OK refining area, and Los Angeles, CA).
These transactions also involve the sale of Products in large quantities prior to scheduled delivery to us by producers and refiners for transportation by pipelines, barges, vessels, or rail cars to our terminals. These transactions may occur while
the Products are in transit prior to reaching our terminals. For the years ended June 30, 2002 and 2001, we averaged approximately 340,000 and 260,000 barrels per day, respectively, of delivered volumes under bulk and cycle sales.
Contract Sales. Contract sales of Products are conducted from our own and third-party terminal,
storage, and delivery locations with independent local jobbers, industrial/commercial end users, and governmental agencies. Contract sales provide these customers with a specified volume of Product over a specified term at a specified price. The
terms of these contracts range from as short as one month to terms that span up to three years. The pricing of the Product delivered under a contract sale may be fixed at a stipulated price per gallon or it may vary based on changes in published
indices (e.g., OPIS and Platts). For the years ended June 30, 2002 and 2001, we averaged approximately 80,000 and 60,000 barrels per day, respectively, of delivered volumes under contract sales.
Energy Services. We provide “supply chain management” services to our industrial/commercial
end-users downstream of the truck loading rack location. Fuel and risk management logistical services provide our large and small volume customers an assured, cost effective delivered source of Products supply through our pipelines and terminals, as
well as through third-party pipeline, terminal, truck, rail and barge distribution channels. Customers of our “supply chain management” services receive the benefits of our web-based technology systems enabling the customers to minimize
their total Product costs while meeting their volumetric needs. We generally receive a fee based on the volume of the Products we originate for the customer in exchange for providing our supply chain management services.
Our Product supply, distribution, and marketing operations include energy trading and risk management activities as defined by Emerging
Issues Task Force Issue No. 98-10 (“EITF 98-10”), Accounting for Contracts Involved in Energy Trading and Risk Management Activities. In accordance with EITF 98-10, our energy trading and risk management activities are marked to
market (i.e., recorded at fair value in the accompanying
17
Table of Contents
consolidated balance sheet). The mark-to-market method of accounting requires that the effect of changes in the fair value of our energy trading and risk management activities be recognized as
assets and liabilities and included in net revenues attributable to Product supply, distribution, and marketing in the period of the change in value.
The consensus on EITF 98-10 previously permitted revenues from energy trading and risk management activities to be presented on the face of the statement of operations on either a gross or net basis.
We previously elected to present revenues from our Product supply, distribution, and marketing operations on a gross basis with a separate line item entitled “Product costs” in the costs and expenses section of the accompanying
consolidated statements of operations. Product costs represent the cost of the Products sold, settlement of risk management contracts, transportation, storage, terminaling costs, and commissions. At its June 2002 meeting, the EITF amended its
consensus on EITF 98-10 to require that revenues from energy trading and risk management activities be reported on a net basis (i.e., product costs are required to be netted directly against gross revenues to arrive at net revenues). That amended
guidance is effective for financial statements issued for periods ending after July 15, 2002. Nevertheless, we have chosen to adopt early that amended guidance for all periods presented. Therefore, for the year ended June 30, 2002 and all prior
periods, we have presented revenues from our Product supply, distribution and marketing operation on a net basis in the accompanying consolidated statements of operations. Net earnings (loss) have not been affected by this change in presentation.
Net revenues attributable to our Product supply, distribution, and marketing operations are as follows (in thousands):
| Years ended June 30, |
||||||||||
| 2002 |
2001 |
2000 |
||||||||
| Gross revenues |
$ |
5,967,508 |
|
5,140,833 |
|
4,953,707 |
| |||
| Less cost of revenues |
|
(5,898,761 |
) |
(5,094,515 |
) |
(4,934,854 |
) | |||
| |
|
|
|
|
|
| ||||
| Net revenues |
$ |
68,747 |
|
46,318 |
|
18,853 |
| |||
| |
|
|
|
|
|
| ||||
Our energy trading and risk management activities include our
inventories—discretionary volumes, energy services contracts, and risk management contracts. Our inventories—discretionary volumes are held for sale or exchange in the ordinary course of business and consist of refined petroleum products,
primarily gasoline and distillates. Our energy services contracts require us to deliver physical quantities of Products over specified terms at specified prices. Our risk management contracts (e.g., forward sales contracts, forward purchase
contracts, and swaps) minimize our exposure to changes in commodity prices. We enter into risk management contracts with the objective of offsetting the changes in the values of our inventories—discretionary volumes and energy services
contracts. It is our policy not to acquire Products, futures contracts or other derivative products for the purpose of speculating on the flat price associated with the underlying commodity. Risk management policies have been established by our Risk
Management Committee to monitor and control these price risks. Our Risk Management Committee is comprised of our senior executives.
Our inventories—discretionary volumes are carried at fair value in the accompanying consolidated financial statements. Our energy services and risk management contracts also are carried at fair value in the accompanying
consolidated financial statements. The fair value of our energy services and risk management contracts are presented as “Unrealized gains or losses on energy services and risk management contracts” in the accompanying consolidated balance
sheet.
Terminals and Pipelines
We own and operate a terminal infrastructure that handles Products with transportation connections via pipelines, barges, rail cars and trucks to our facilities and to
third-party facilities. As of June 30, 2002, we owned and operated the following facilities: 30 delivery locations/terminals with approximately 9.9 million barrels of tank space capacity along the Colonial and Plantation pipeline systems; 3 delivery
locations/terminals with
18
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approximately 500,000 barrels of tank space capacity along the Explorer/Williams pipeline systems; 3 delivery locations/terminals with approximately 1.0 million barrels of tank capacity along the
Florida coast; 1 delivery location/terminal with approximately 2.2 million barrels of tank capacity in Brownsville, Texas; and 12 delivery locations/terminals with approximately 2.9 million barrels of tank capacity along the Mississippi and Ohio
rivers.
We own an interstate Products pipeline operating from Mt. Vernon, Missouri to Rogers, Arkansas (the
“Razorback Pipeline”), together with associated terminal facilities at Mt. Vernon and Rogers. The Razorback Pipeline is the only Products pipeline providing transportation services to northwest Arkansas. Effective June 30, 2002, we
acquired for cash consideration of approximately $7.2 million the remaining 40% interest in the Razorback Pipeline system that we did not previously own. We also own and operate a small intrastate crude oil gathering pipeline system, located in east
Texas (the “CETEX pipeline”).
The success of our terminal and pipeline operations depends in large part
on the level of demand for Products by end users in the geographic locations served by such facilities and the ability and willingness of our customers to supply such demand by utilizing our terminals and pipelines as opposed to the terminals and
pipelines of other companies. At our terminals and pipelines, we provide throughput, storage, and transportation related services to distributors, marketers and industrial/commercial end-users of Products.
Throughput Revenues. Terminal throughput fees are based on the volume of Products handled at the
facility’s truck loading racks, generally at a standard rate per gallon. For the years ended June 30, 2002 and 2001, we averaged approximately 520,000 and 620,000 barrels per day, respectively, of throughput volumes at our terminals.
Storage Revenues. Terminal storage fees generally are based on a per barrel rate or
tank space capacity committed and will vary with the duration of the arrangement, the Product stored and special handling requirements, particularly when certain types of chemicals and other bulk liquids are involved.
Transportation Revenues. Pipeline transportation fees are based on the volume of Products transported and
the distance from the origin point to the delivery point. For the years ended June 30, 2002 and 2001, we averaged approximately 24,000 and 74,000 barrels per day, respectively, of transported volumes through our pipelines.
The direct operating costs and expenses of the terminals and pipelines operations include the directly related wages and
employee benefits, utilities, communications, maintenance and repairs, property taxes, rent, vehicle expenses, environmental compliance costs, materials and supplies. We cannot predict the impact of future fuel conservation measures, alternate fuel
requirements, governmental regulation, technological advances in fuel economy, demographic changes, weather conditions, crop prices, and energy-generation devices, all of which could reduce the demand for Products in the areas we serve.
Natural Gas Services
We previously provided selected natural gas services including the gathering, processing, fractionating, and marketing of natural gas liquids and natural gas. We discontinued this activity when we sold
it effective December 31, 1999 (see Note 2 of Notes to Consolidated Financial Statements).
Natural gas gathering
and processing revenues were based on the inlet volume of natural gas purchased from producers under both percentage-of-proceeds and fee-based arrangements. Natural gas was gathered and processed into NGL products, principally propane, butane and
natural gasoline and residue natural gas. These products were transported by truck or pipeline to storage facilities from which they were further transported and marketed to wholesalers and end-users. Residue natural gas was delivered to and
marketed through connections with third-party interstate natural gas pipelines. Operating expenses of the natural gas processing activity include the directly related wages and employee benefits, utilities, maintenance and repairs, property taxes,
rent, insurance, vehicle expenses, environmental compliance costs, materials and supplies.
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Table of Contents
CRITICAL ACCOUNTING ESTIMATES
A summary of the significant accounting policies that we have adopted and followed in the preparation of our consolidated financial statements is detailed in Note 1 of
Notes to the Consolidated Financial Statements. Certain of these accounting policies require the use of estimates. We have identified the following estimates that, in our opinion, are subjective in nature, require the exercise
of judgment, and involve complex analysis. These estimates are based on our knowledge and understanding of current conditions and actions we may take in the future. Changes in these estimates will occur as a result of the passage of time and the
occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations.
Allowance for Doubtful Accounts. At June 30, 2002, our allowance for doubtful accounts was $1.25 million. Our allowance for doubtful accounts represents the amount of
trade receivables that we do not expect to collect. The valuation of our allowance for doubtful accounts is based on our analysis of specific individual customer balances that are past due and, from that analysis we estimate the amount of the
receivable balance that we do not expect to collect. That estimate is based on various factors, including our experience in collecting past due amounts from the customer being evaluated, customer’s current financial condition, the current
economic environment and the economic outlook for the future.
Inventories—Discretionary
Volumes. At June 30, 2002, we held Products for sale or exchange in the ordinary course of business with a value of $175.2 million. Our inventories—discretionary volumes are carried at fair value in the accompanying
consolidated balance sheets. The valuation of our inventories—discretionary volumes is based on quoted prices, when available. However, quoted prices are not available from brokers for all future periods and delivery locations in which we are
committed to do business. When quoted prices are not available, we estimate the values based on historical relationships between current and future prices and delivery locations.
Energy Services Contracts. At June 30, 2002, we were a party to energy services contracts that require us to deliver physical quantities of
refined petroleum products over a specified term at a specified price. Our energy services contracts are carried at fair value in the accompanying consolidated balance sheets. At June 30, 2002, our net unrealized gains on energy services contracts
were approximately $13.9 million. The valuation of our energy services contracts is based on quoted prices, when available. However, quoted prices are not available from brokers for all future periods and delivery locations in which we are committed
to do business. When quoted prices are not available, we estimate the values based on historical relationships between current and future prices and delivery locations.
Accrued Lease Abandonment. At June 30, 2002, we have an accrued liability of $3.1 million as our estimate of the future payments we expect to
pay, net of sublease payments we expect to receive from subleasing our to-be-vacated office space in Denver, Colorado and Atlanta, Georgia. The valuation of our accrued lease abandonment is based on the timing and amount of sublease payments we
expect to receive from subleasing our to-be-vacated office space. Our estimate of the timing and amount of sublease payments is based on information received from real estate brokers.
Accrued Transportation and Deficiency Agreements. At June 30, 2002, we have an accrued liability of $2.8 million as our estimate of the future
payments we expect to pay for the estimated shortfall in volumes for the remainder of the terms of our transportation and deficiency agreements. The valuation of our accrued transportation and deficiency agreements is based on our estimate of the
future volumes we expect to supply and ship with the counterparties to these agreements. We estimate the future volumes based on our historical volumes supplied and shipped with the counterparties. Our accrued liability would be adjusted if our
current projections of future volumes to be supplied and shipped with the counterparties indicated a significant increase or decrease in expected volumes due to changes in the scope and breadth of our Product supply, distribution, and marketing
operations.
20
Table of Contents
Accrued Environmental Obligations. At June 30,
2002, we have an accrued liability of $2.3 million as our estimate of the future payments we expect to pay for environmental costs to remediate existing conditions attributable to past operations. The valuation of our accrued environmental
obligations is based on our estimate of the remediation costs to be incurred in the future. We estimate the future remediation costs based on specific site studies using enacted laws and regulations. Estimates of our environmental obligations are
subject to change due to a number of factors and judgments involved in the estimation process, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation, technology changes affecting
remediation methods, alternative remediation methods and strategies, and changes in environmental laws and regulations.
Series B Redeemable Convertible Preferred Stock. At June 30, 2002, the carrying amount of the Series B Redeemable Convertible Preferred Stock was $80.9 million. The carrying amount is based on our
estimate of the fair value of the Series B Redeemable Preferred Stock at the date of issuance (June 28, 2002). We estimated the value of the Series B Redeemable Preferred Stock by adding together (i) the present value of the expected dividend
payments and mandatory redemption value discounted at a risk-adjusted rate and (ii) the value of the embedded conversion option using an option pricing model.
SIGNIFICANT DEVELOPMENTS
During the year ended June 30, 2002, we amended and
restated our bank credit facility (“New Facility”) to provide us with financing to expand our petroleum products marketing and terminaling network, support our working capital requirements and general corporate needs, recapitalize our
preferred stock, and repurchase shares of our common stock. The New Facility provides us with a revolving line of credit and the ability to issue letters of credit to support our Product supply, distribution, and marketing operations.
We also announced our decision to relocate our Product supply, distribution, and marketing operations from Roswell, Georgia to
Denver, Colorado to join our corporate headquarters.
Extension of Bank Credit Facility
On June 28, 2002, we entered into the New Facility with a syndication of banks. The New Facility provides for a maximum borrowing under
the revolving line of credit that is the lesser of (i) $300 million and (ii) the borrowing base. The borrowing base is a function of our accounts receivable, inventory, exchanges, margin deposits, open positions of energy services and risk
management contracts, outstanding letters of credit, and outstanding indebtedness as defined in the New Facility. Borrowings under the New Facility bear interest (at our option) based on the lender’s base rate plus a specified margin, or LIBOR
plus a specified margin; the specified margins are a function of our leverage ratio as defined in the New Facility. Borrowings under the New Facility are secured by substantially all of our assets. The New Facility matures on June 27, 2005. The
terms of the New Facility include financial covenants relating to fixed charge coverage, current ratio, maximum leverage ratio, consolidated tangible net worth, capital expenditures, cash distributions and open inventory positions that are tested on
a quarterly and annual basis. At June 30, 2002, we were in compliance with all covenants included in the New Facility.
Preferred
Stock Recapitalization
On June 28, 2002, we entered into an agreement with the holders of the Series A
Convertible Preferred Stock (the “Preferred Stock Recapitalization Agreement”) to redeem a portion of the outstanding Series A Convertible Preferred Stock and warrants in exchange for cash, shares of common stock, and shares of a newly
created and designated preferred stock (“Series B Redeemable Convertible Preferred Stock”).
The
Preferred Stock Recapitalization Agreement resulted in the redemption of 157,715 shares of Series A Convertible Preferred Stock and warrants to purchase 9,841,493 shares of common stock in exchange for the (i) issuance of 72,890 shares of
Series B Redeemable Convertible Preferred Stock with a fair value of approximately
21
Table of Contents
$80.9 million, (ii) issuance of 11,902,705 shares of common stock with a fair value of approximately $59.5 million, and (iii) a cash payment of approximately
$21.3 million. The fair value of the consideration paid to the holders of the Series A Convertible Preferred Stock was in excess of the financial statement carrying amount of the Series A Convertible Preferred Stock that was redeemed. That
excess of approximately $1.5 million has been treated in a manner similar to preferred stock dividends in the accompanying consolidated financial statements. At June 30, 2002, there were 24,421 shares of Series A Convertible Preferred Stock that
remain outstanding.
In connection with the Preferred Stock Recapitalization Agreement, we also agreed to
repurchase approximately 4.1 million shares of our common stock from an institutional holder of the Series A Convertible Preferred Stock for cash consideration of approximately $20.4 million.
We borrowed approximately $41.7 million under the New Facility to finance the redemption of the Series A Convertible Preferred Stock and the reacquisition of the
common stock.
Corporate Relocation and Transition
During the year ended June 30, 2002, we announced to our employees that our Product supply, distribution, and marketing operations in Atlanta, Georgia would be relocated to
Denver, Colorado. On March 19, 2002, we offered approximately 72 employees the opportunity to relocate to Denver, Colorado and we informed approximately 25 employees that they would not be offered the opportunity to relocate to Denver, Colorado.
Ultimately, 36 employees chose to relocate to Denver, Colorado. Those employees are entitled to receive a transition bonus and a relocation package payable upon transfer to the Denver office. The transition bonus is being accrued over the period
from date of acceptance by the employee to the expected date of arrival in Denver, Colorado. The relocation costs are being accrued as incurred/earned by the employee. Ultimately, 36 employees chose not to relocate and those employees are entitled
to receive termination benefits on their termination date as determined by us. The special termination benefits were accrued upon receipt of the notification from the employee that they did not intend to accept the offer to relocate to Denver,
Colorado. For the year ended June 30, 2002, we accrued approximately $2.1 million of benefits due to employees, of which approximately $2.0 million remains unpaid as of June 30, 2002. We expect to pay the accrued liability of approximately $2.0
million during the year ending June 30, 2003.
| Special charge |
Amounts paid |
Accrued liability at June 30, 2002 | ||||||
| Accrued severance payable to employees not relocating to Denver, Colorado |
$ |
1,512 |
(84 |
) |
1,428 | |||
| Accrued transition benefits payable to employees relocating to Denver, Colorado |
|
501 |
— |
|
501 | |||
| Relocation costs incurred during the period |
|
100 |
— |
|
100 | |||
| Other |
|
25 |
(25 |
) |
— | |||
| |
|
|
|
| ||||
| $ |
2,138 |
(109 |
) |
2,029 | ||||
| |
|
|
|
| ||||
In connection with our corporate relocation and transition, we
entered into an operating lease for new office space in Denver, Colorado. The new lease was executed on April 19, 2002. Prior to June 30, 2002, we engaged commercial real estate agents to solicit prospective tenants to sublease our existing office
space in Denver, Colorado and the vacated space in Roswell, Georgia. We expect to vacate our existing office space in Denver, Colorado during February 2003 and the space in Roswell, Georgia during September 2002. The accrual for the abandonment of
the office leases represents the excess of the remaining lease payments subsequent to vacancy of the space by us over the estimated sublease rentals to be received based on current market conditions. The abandonment of leasehold improvements
represents the carrying amount of those assets that are expected to be
22
Table of Contents
abandoned in connection with the abandonment of the office leases. For the year ended June 30, 2002, we charged to income approximately $4.2 million for abandonment of office leases and leasehold
improvements.
| Special charge |
Amounts paid or written-off |
Accrued liability at June 30, 2002 | ||||||
| Abandonment of office leases: |
||||||||
| Denver, Colorado |
$ |
1,150 |
— |
|
1,150 | |||
| Atlanta, Georgia |
|
1,960 |
— |
|
1,960 | |||
| Abandonment of leasehold improvements: |
||||||||
| Denver, Colorado |
|
550 |
(550 |
) |
— | |||
| Atlanta, Georgia |
|
518 |
(518 |
) |
— | |||
| |
|
|
|
| ||||
| $ |
4,178 |
(1,068 |
) |
3,110 | ||||
| |
|
|
|
| ||||
We expect to pay the accrued liability of approximately $3.1
million, net of estimated sublease rentals, as follows:
| Years ending June 30: |
Lease payments |
Estimated sublease rentals |
Accrued liability at June 30, 2002 | |||||
| 2003 |
$ |
745 |
(97 |
) |
648 | |||
| 2004 |
|
991 |
(562 |
) |
429 | |||
| 2005 |
|
1,020 |
(565 |
) |
455 | |||
| 2006 |
|
1,045 |
(569 |
) |
476 | |||
| 2007 |
|
948 |
(508 |
) |
440 | |||
| Thereafter |
|
1,243 |
(581 |
) |
662 | |||
| |
|
|
|
| ||||
| $ |
5,992 |
(2,882 |
) |
3,110 | ||||
| |
|
|
|
| ||||
DISPOSITIONS
On May 31, 2002, our 30.02% interest in ST Oil Company was reacquired by ST Oil Company for cash consideration of approximately $3.0 million and we recognized a net gain of
approximately $1.4 million on the sale. The proceeds from the sale were used for general corporate purposes.
On
July 31, 2001, we sold the NORCO Pipeline system and related terminals (“NORCO”) to Buckeye Partners L.P. for cash consideration of approximately $62.0 million and recognized a net gain of approximately $8.6 million on the sale. The
proceeds from the sale were used to repay long-term debt and for general corporate purposes.
On July 27,
2001, we sold 861 shares of the common stock of West Shore Pipeline Company (“West Shore”), thereby reducing our ownership interest to 18.50%. The West Shore common stock was sold to Midwest Pipeline Company, LLC for cash consideration of
approximately $2.9 million. We recognized a loss of approximately $1.1 million on this sale. As a result of this transaction, we also recognized a loss on our remaining investment in West Shore of approximately $8.8 million. We sold our remaining
18.50% interest on October 29, 2001 to Buckeye Partners L.P. for cash consideration of approximately $23.1 million, which approximated our adjusted book value. The cash proceeds from both sales were used to repay long-term debt and for general
corporate purposes.
Effective June 30, 2001, we sold two petroleum distribution facilities in Little Rock,
Arkansas to Williams Energy Partners L.P. for $29.0 million. The cash proceeds from the sales transactions were received on July 3,
23
Table of Contents
2001. We recognized a net gain in June 2001 of approximately $22.1 million on the sale. The proceeds from the sale were used to repay long-term debt and for general corporate purposes.
Effective December 31, 1999, we sold our natural gas gathering subsidiary, Bear Paw Energy Inc.,
(“BPEI”), to BPE Acquisition LLC, a special purpose entity formed by Bear Paw’s management in association with Thomas J. Edelman and Chase Capital Partners. The sale of BPEI was for cash consideration of $107.5 million, plus
$23.7 million for reimbursement of the capital expenditures we made on BPEI’s newly constructed Powder River coal seam gathering system from July 1, 1999 to December 31, 1999. This disposition resulted in an approximate $16.6 million gain. The
sale proceeds were used to reduce long-term debt and for general corporate purposes.
ACQUISITIONS
Effective June 30, 2002, we acquired for cash consideration of approximately $7.2 million the remaining 40% interest that we previously
did not own in the Razorback Pipeline system, a 67 mile Products pipeline between Mount Vernon, Missouri and Rogers, Arkansas with approximately .4 million barrels of storage capacity.
On May 31, 2000, we acquired two Products terminals located in Richmond and Montvale, Virginia for approximately $3.2 million. These facilities are interconnected to the
Colonial and Plantation pipeline systems and include approximately .5 million barrels of storage capacity.
SUBSEQUENT EVENTS
On August 23, 2002, we announced the signing of a long-term terminaling agreement with P.M.I. Trading Limited
to provide Products terminaling services and a related pipeline construction assistance agreement with P.M.I. Services North America, Inc., both affiliates of Petroleos Mexicanos, for the construction of a new 17-mile U.S. Products pipeline
from the U.S./Mexican border to our terminaling facility located at the port of Brownsville, Texas.
We also
announced that on July 31, 2002, we closed on the purchase of a 25,000-barrel terminal in Brownsville, Texas. The terminal provides us with additional storage and rail car handling facilities and operating synergies with our main facility in
Brownsville, Texas.
24
Table of Contents
RESULTS OF OPERATIONS
Selected annual results of operations data are summarized below (in thousands):
| Years ended June
30, |
||||||||||
| 2002 |
2001 |
2000 |
||||||||
| Product supply, distribution and marketing: |
||||||||||
| Revenues, net |
$ |
68,747 |
|
46,318 |
|
18,853 |
| |||
| Lower of cost or market write-downs on minimum inventory volumes (1) |
|
(12,963 |
) |
(18,318 |
) |
— |
| |||
| |
|
|
|
|
|
| ||||
| Net operating margins (2) |
|
55,784 |
|
28,000 |
|
18,853 |
| |||
| |
|
|
|
|
|
| ||||
| Terminals and pipelines: |
||||||||||
| Revenues |
|
63,386 |
|
82,305 |
|
78,522 |
| |||
| Direct operating costs and expenses |
|
(27,668 |
) |
(36,415 |
) |
(34,268 |
) | |||
| |
|
|
|
|
|
| ||||
| Net operating margins |
|
35,718 |
|
45,890 |
|
44,254 |
| |||
| |
|
|
|
|
|
| ||||
| Natural gas services (3): |
||||||||||
| Revenues |
|
— |
|
— |
|
18,249 |
| |||
| Direct operating costs and expenses |
|
— |
|
— |
|
(7,759 |
) | |||
| |
|
|
|
|
|
| ||||
| Net operating margins |
|
— |
|
— |
|
10,490 |
| |||
| |
|
|
|
|
|
| ||||
| Total net operating margins |
|
91,502 |
|
73,890 |
|
73,597 |
| |||
| Selling, general and administrative expenses |
|
(35,211 |
) |
(34,072 |
) |
(41,680 |
) | |||
| Depreciation and amortization |
|
(16,556 |
) |
(19,510 |
) |
(22,344 |
) | |||
| Impairment of long-lived assets |
|
— |
|
— |
|
(50,136 |
) | |||
| Corporate relocation and transition |
|
(6,316 |
) |
— |
|
— |
| |||
| |
|
|
|
|
|
| ||||
| Operating income (loss) |
|
33,419 |
|
20,308 |
|
(40,563 |
) | |||
| Dividend income from and equity in earnings of petroleum related investments |
|
1,450 |
|
3,060 |
|
1,590 |
| |||
| Interest income |
|
599 |
|
2,914 |
|
3,419 |
| |||
| Interest expense and other financing costs |
|
(21,432 |
) |
(30,424 |
) |
(35,480 |
) | |||
| Gain (loss) on disposition of assets, net |
|
(13 |
) |
22,146 |
|
13,930 |
| |||
| |
|
|
|
|
|
| ||||
| Earnings (loss) before income taxes |
|
14,023 |
|
18,004 |
|
(57,104 |
) | |||
| Income tax (expense) benefit |
|
(5,465 |
) |
(6,666 |
) |
19,167 |
| |||
| |
|
|
|
|
|
| ||||
| Net earnings (loss) |
|
8,558 |
|
11,338 |
|
(37,937 |
) | |||
| Preferred stock dividends |
|
(11,351 |
) |
(8,963 |
) |
(8,506 |
) | |||
| |
|
|
|
|
|
| ||||
| Net earnings (loss) attributable to common stockholders |
$ |
(2,793 |
) |
2,375 |
|
(46,443 |
) | |||
| |
|
|
|
|
|
| ||||
(1) |
We did not measure lower of cost or market write-downs related to minimum inventory during the year ended June 30, 2000, as we did not separately account for
our minimum inventory prior to July 1, 2000. |
(2) |
Net operating margins represent net revenues, less direct operating costs and expenses. |
(3) |
Our natural gas services activities were divested as of December 31, 1999. |
25
Table of Contents
The |
following table summarizes our cash flows, EBITDA, and adjusted EBITDA (in thousands): |
| Years ended June
30, |
||||||||||
| 2002 |
2001 |
2000 |
||||||||
| Net cash provided (used) by operating activities |
$ |
(89,127 |
) |
35,507 |
|
267,526 |
| |||
| |
|
|
|
|
|
| ||||
| Net cash provided (used) by investing activities |
$ |
106,822 |
|
(18,969 |
) |
77,902 |
| |||
| |
|
|
|
|
|
| ||||
| Net cash provided (used) by financing activities |
$ |
3,811 |
|
(61,130 |
) |
(305,417 |
) | |||
| |
|
|
|
|
|
| ||||
| Calculation of EBITDA and Adjusted EBITDA: |
||||||||||
| Total net operating margins |
$ |
91,502 |
|
73,890 |
|
73,597 |
| |||
| Selling, general, and administrative |
|
(35,211 |
) |
(34,072 |
) |
(41,680 |
) | |||
| Corporate relocation and transition |
|
(6,316 |
) |
— |
|
— |
| |||
| Dividend income from petroleum related investments |
|
1,450 |
|
3,060 |
|
1,590 |
| |||
| |
|
|
|
|
|
| ||||
| EBITDA (1) |
|
51,425 |
|
42,878 |
|
33,507 |
| |||
| Lower of cost or market write-downs on minimum inventory volumes |
|
12,963 |
|
18,318 |
|
— |
| |||
| |
|
|
|
|
|
| ||||
| Adjusted EBITDA (2) |
$ |
64,388 |
|
61,196 |
|
33,507 |
| |||
| |
|
|
|
|
|
| ||||
(1) |
EBITDA is defined as total net operating margins, less selling, general and administrative expenses, less corporate relocation and transition costs, plus
dividend income from petroleum related investments. We believe that, in addition to cash flow from operating activities and net earnings (loss), EBITDA is a useful financial performance measurement for assessing operating performance since it
provides an additional basis to evaluate our ability to incur and service debt and to fund capital expenditures. In evaluating EBITDA, we believe that consideration should be given, among other things, to the amount by which EBITDA exceeds interest
costs for the period; how EBITDA compares to principal repayments on debt for the period; and how EBITDA compares to capital expenditures for the period. To evaluate EBITDA, the components of EBITDA, such as net revenue and direct operating
expenses, and the variability of such components over time, also should be considered. EBITDA should not be construed, however, as an alternative to operating income (loss) (as determined in accordance with GAAP) as an indicator of our operating
performance, or to cash flows from operating activities (as determined in accordance with GAAP) as a measure of liquidity. Our method of calculating EBITDA may differ from methods used by other companies and, as a result, EBITDA measures disclosed
herein might not be comparable to other similarly titled measures used by other companies. |
(2) |
Adjusted EBITDA is defined as EBITDA plus lower of cost or market write-downs on our inventories— minimum volumes. We believe that Adjusted EBITDA is the
most useful measure in evaluating our performance because it eliminates the impact on operating results from the impairment of our inventories—minimum volumes. |
26
Table of Contents
Selected quarterly results of operations data are summarized below (in thousands, except volume and per unit margin
data):
| Three months ended |
Year ended June 30, 2002 |
|||||||||||||||
| September 30, 2001 |
December 31, 2001 |
March 31, 2002 |
June 30, 2002 |
|||||||||||||
| Product supply, distribution and marketing: |
||||||||||||||||
| Revenues, net |
$ |
27,599 |
|
13,729 |
|
20,106 |
|
7,313 |
|
68,747 |
| |||||
| Lower of cost or market write-downs on minimum inventory volumes |
|
(849 |
) |
(12,114 |
) |
— |
|
— |
|
(12,963 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Net operating margins |
|
26,750 |
|
1,615 |
|
20,106 |
|
7,313 |
|
55,784 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Terminals and pipelines: |
||||||||||||||||
| Revenues |
|
15,516 |
|
15,175 |
|
15,764 |
|
16,931 |
|
63,386 |
| |||||
| Direct operating costs and expenses |
|
(7,175 |
) |
(6,662 |
) |
(6,168 |
) |
(7,663 |
) |
(27,668 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Net operating margins |
|
8,341 |
|
8,513 |
|
9,596 |
|
9,268 |
|
35,718 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Total net operating margins |
|
35,091 |
|
10,128 |
|
29,702 |
|
16,581 |
|
91,502 |
| |||||
| Selling, general, and administrative |
|
(8,465 |
) |
(8,185 |
) |
(8,955 |
) |
(9,606 |
) |
(35,211 |
) | |||||
| Depreciation and amortization |
|
(4,282 |
) |
(4,024 |
) |
(4,143 |
) |
(4,107 |
) |
(16,556 |
) | |||||
| Corporate relocation and transition |
|
— |
|
— |
|
(315 |
) |
(6,001 |
) |
(6,316 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Operating income (loss) |
|
22,344 |
|
(2,081 |
) |
16,289 |
|
(3,133 |
) |
33,419 |
| |||||
| Other income (expense), net |
|
(6,811 |
) |
(2,660 |
) |
(2,200 |
) |
(7,725 |
) |
(19,396 |
) | |||||
| Income tax (expense) benefit |
|
(5,902 |
) |
1,801 |
|
(5,354 |
) |
3,990 |
|
(5,465 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Net earnings (loss) |
$ |
9,631 |
|
(2,940 |
) |
8,735 |
|
(6,868 |
) |
8,558 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Calculation of EBITDA and Adjusted EBITDA: |
||||||||||||||||
| Total net operating margins |
$ |
35,091 |
|
10,128 |
|
29,702 |
|
16,581 |
|
91,502 |
| |||||
| Selling, general, and administrative |
|
(8,465 |
) |
(8,185 |
) |
(8,955 |
) |
(9,606 |
) |
(35,211 |
) | |||||
| Corporate relocation and transition |
|
— |
|
— |
|
(315 |
) |
(6,001 |
) |
(6,316 |
) | |||||
| Dividend income from petroleum related investments |
|
1,349 |
|
108 |
|
(7 |
) |
— |
|
1,450 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| EBITDA |
|
27,975 |
|
2,051 |
|
20,425 |
|
974 |
|
51,425 |
| |||||
| Lower of cost or market write-downs on minimum inventory volumes |
|
849 |
|
12,114 |
|
— |
|
— |
|
12,963 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Adjusted EBITDA |
$ |
28,824 |
|
14,165 |
|
20,425 |
|
974 |
|
64,388 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Terminal Volumes—bbls/day |
|
515,035 |
|
499,955 |
|
509,005 |
|
546,670 |
|
517,666 |
| |||||
| Terminals Net Operating Margin per bbl |
$ |
0.162 |
|
0.169 |
|
0.189 |
|
0.169 |
|
0.170 |
| |||||
| Pipeline Volumes—bbls/day |
|
32,674 |
|
17,226 |
|
22,961 |
|
23,552 |
|
24,103 |
| |||||
| Pipelines Net Operating Margin per bbl |
$ |
0.288 |
|
0.585 |
|
0.451 |
|
0.458 |
|
0.415 |
| |||||
27
Table of Contents
| Three months ended |
Year ended June 30, 2001 |
|||||||||||||||
| September 30, 2000 |
December 31, 2000 |
March 31, 2001 |
June 30, 2001 |
|||||||||||||
| Product supply, distribution and marketing: |
||||||||||||||||
| Revenues, net |
$ |
8,310 |
|
10,865 |
|
14,640 |
|
12,503 |
|
46,318 |
| |||||
| Lower of cost or market write-downs on minimum inventory volumes |
|
(4,528 |
) |
(2,353 |
) |
(1,940 |
) |
(9,497 |
) |
(18,318 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Net operating margins |
|
3,782 |
|
8,512 |
|
12,700 |
|
3,006 |
|
28,000 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Terminals and pipelines: |
||||||||||||||||
| Revenues |
|
20,753 |
|
20,527 |
|
20,164 |
|
20,861 |
|
82,305 |
| |||||
| Direct operating costs and expenses |
|
(8,401 |
) |
(8,496 |
) |
(9,944 |
) |
(9,574 |
) |
(36,415 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Net operating margins |
|
12,352 |
|
12,031 |
|
10,220 |
|
11,287 |
|
45,890 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Total net operating margins |
|
16,134 |
|
20,543 |
|
22,920 |
|
14,293 |
|
73,890 |
| |||||
| Selling, general, and administrative |
|
(7,237 |
) |
(8,157 |
) |
(9,102 |
) |
(9,576 |
) |
(34,072 |
) | |||||
| Depreciation and amortization |
|
(4,847 |
) |
(4,821 |
) |
(4,927 |
) |
(4,915 |
) |
(19,510 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Operating income (loss) |
|
4,050 |
|
7,565 |
|
8,891 |
|
(198 |
) |
20,308 |
| |||||
| Other income (expense), net |
|
(3,616 |
) |
(4,754 |
) |
(8,143 |
) |
14,209 |
|
(2,304 |
) | |||||
| Income tax (expense) benefit |
|
(165 |
) |
(1,068 |
) |
(284 |
) |
(5,149 |
) |
(6,666 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Net earnings (loss) |
$ |
269 |
|
1,743 |
|
464 |
|
8,862 |
|
11,338 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Calculation of EBITDA and Adjusted EBITDA: |
||||||||||||||||
| Total net operating margins |
$ |
16,134 |
|
20,543 |
|
22,920 |
|
14,293 |
|
73,890 |
| |||||
| Selling, general, and administrative |
|
(7,237 |
) |
(8,157 |
) |
(9,102 |
) |
(9,576 |
) |
(34,072 |
) | |||||
| Dividend income from petroleum related investments |
|
919 |
|
820 |
|
766 |
|
555 |
|
3,060 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| EBITDA |
|
9,816 |
|
13,206 |
|
14,584 |
|
5,272 |
|
42,878 |
| |||||
| Lower of cost or market write-downs on minimum inventory volumes |
|
4,528 |
|
2,353 |
|
1,940 |
|
9,497 |
|
18,318 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Adjusted EBITDA |
$ |
14,344 |
|
15,559 |
|
16,524 |
|
14,769 |
|
61,196 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Terminal Volumes—bbls/day |
|
618,987 |
|
601,985 |
|
610,929 |
|
630,063 |
|
615,491 |
| |||||
| Terminals Net Operating Margin per bbl |
$ |
0.188 |
|
0.188 |
|
0.171 |
|
0.170 |
|
0.179 |
| |||||
| Pipeline Volumes—bbls/day |
|
74,771 |
|
71,218 |
|
74,487 |
|
76,717 |
|
74,298 |
| |||||
| Pipelines Net Operating Margin per bbl |
$ |
0.240 |
|
0.245 |
|
0.120 |
|
0.222 |
|
0.207 |
| |||||
28
Table of Contents
YEAR ENDED JUNE 30, 2002 COMPARED TO YEAR ENDED JUNE 30, 2001
We reported net earnings of $8.6 million for the year ended June 30, 2002, compared to net earnings of $11.3 million for the year ended June 30, 2001. After preferred stock
dividends, the net earnings (loss) attributable to common stockholders was $(2.8) million for the year ended June 30, 2002, compared to net earnings of $2.4 million for the year ended June 30, 2001. Basic and diluted loss per common share for the
year ended June 30, 2002 was $(0.09) based on 31.3 million weighted average common shares outstanding. Basic and diluted earnings per share for the year ended June 30, 2001 was $0.08 per share based upon 30.9 million weighted average common shares
outstanding and 31.0 million weighted average diluted shares outstanding.
Product Supply, Distribution and Marketing
Our Product supply, distribution, and marketing operations include energy trading and risk management
activities as defined by Emerging Issues Task Force Issue No. 98-10 (“EITF 98-10”), Accounting for Contracts Involved in Energy Trading and Risk Management Activities. In accordance with EITF 98-10, our energy trading and risk
management activities are marked to market (i.e., recorded at fair value in the accompanying consolidated balance sheet). The mark-to-market method of accounting requires that the effect of changes in the fair value of our energy trading and risk
management activities be recognized as assets and liabilities and included in net revenues attributable to Product supply, distribution, and marketing in the period of the change in value.
We seek to maintain a balanced position of forward sale commitments against our discretionary inventories and forward purchase commitments, thereby minimizing or
eliminating exposure to commodity price fluctuations. We evaluate our exposure to commodity price risk from an overall portfolio basis that considers the continuous movement of discretionary inventory volumes and the open positions in energy
services and risk management contracts. However, there are certain risks that we do not attempt to hedge or eliminate. For example, we attempt to exploit the price relationships between various delivery locations (referred to as “basis
(geographical location) differentials”). These differentials create opportunities for increased operating margins when we predict the most beneficial location (highest value location) for sales of our discretionary inventories of refined
products. However, the margins created from exploiting these market inefficiencies do not occur ratably over our reporting periods.
During a “contango” or “carry” market structure, we utilize our and third-party terminals to store Products to capture commodity price differentials between current and future months. Mark-to-market
accounting will create volatility in our net operating margins due to either the widening or narrowing of these pricing spreads from the original spread relationship. If the spreads widen (narrow), marking these storage volumes and the related
forward contracts to market will produce unrealized losses (gains) in interim reporting periods. These negative (positive) results will reverse and the originally anticipated spread will be recognized during the future periods when the physical
Product inventory is delivered against the short future position. At June 30, 2002, we held approximately 3.0 million barrels of distillates in our terminals for future delivery.
The net operating margins reported for the Product supply, distribution and marketing operations include amounts realized on Product sales, exchanges and arbitrage. The net
revenues from our Product supply, distribution, and marketing operations for the year ended June 30, 2002 was $68.7 million compared to $46.3 million for the year ended June 30, 2001. The increase of $22.4 million in net revenues is due
principally to taking advantage of market opportunities that were caused by volatility in basis (geographical location) differentials. During the quarter ended September 30, 2001, a disruption at a Chicago refinery resulted in increased volatility
in basis (geographical location) differentials. This disruption increased the basis (geographical location) differentials for both gasoline and distillates between the Gulf Coast, Chicago and Group (Mid-Continent) regions, which created significant
margin opportunities in arbitraging the basis (geographical location) differentials between those markets. During the quarter ended March 31, 2002, we were able to increase our net operating margins by taking advantage of the price volatility in the
gasoline market in the Gulf Coast region. That volatility also created significant arbitrage opportunities associated with basis (geographical
29
Table of Contents
location) differentials. In addition, during the quarter ended March 31, 2002, we renegotiated and extended for an additional year, a fixed-price supply contract with a large
industrial/commercial end-user. We recognized approximately $3.0 million in net revenues associated with this contract extension and we deferred approximately $1.7 million for the value of the supply chain management services that we are committed
to provide over the term of the supply contract. During the quarter ended June 30, 2002, we experienced a reduction in volatility in basis (geographical location) differentials combined with an unfavorable relationship between crude oil and refined
product prices.
During the years ended June 30, 2002 and 2001, we recognized impairment losses of approximately
$13.0 million and $18.3 million, respectively, due to lower of cost or market write-downs on the minimum inventory volumes. These write-downs are included in net operating margins attributable to our Product supply, distribution, and marketing
operations.
Terminals and Pipelines
The net operating margins from our terminal and pipeline operations for the year ended June 30, 2002 were $35.7 million compared to $45.9 million for the year ended June 30, 2001. The decrease of $10.2
million in net operating margins was due principally to the sale of our Little Rock facilities on June 30, 2001 and the NORCO system on July 31, 2001. For the year ended June 30, 2001, the net operating margins from the Little Rock facilities and
the NORCO system were $9.1 million.
Our pipeline net operating margins per barrel of transported volumes were
approximately $0.42 and $0.21 for the years ended June 30, 2002 and 2001, respectively. The increase in net operating margins per barrel is due principally to the higher unit tariff being realized on one of our joint tariffs, as compared to the
lower unit tariff associated with our NORCO system which was disposed of in July 2001.
Selling, General, and Administrative
Selling, general and administrative expenses for the year ended June 30, 2002 were $35.2 million, compared to
$34.1 million for the year ended June 30, 2001. The increase of $1.1 million was due principally to increased compensation and travel expenses related to our corporate relocation and transition during the year ended June 30, 2002.
Depreciation and amortization for the year ended June 30, 2002 was $16.6 million, compared to $19.5 million for the year
ended June 30, 2001. The decrease of $2.9 million in depreciation and amortization was due primarily to the disposition of the NORCO system and Little Rock facilities.
We recognized special charges of $6.3 million during the year ended June 30, 2002 related to the corporate relocation and transition. We expect to recognize an additional
special charge of $2.1 million during the year ended June 30, 2003 to complete the corporate relocation and transition. The additional special charges will consist of $1.7 million in moving costs for employees relocating to Denver, Colorado,
transition benefits of $0.3 million payable to employees relocating to Denver, Colorado, and moving costs of $0.1 million related to the relocation of the corporate headquarters.
Other Income and Expenses
Dividend income and equity in
earnings from petroleum related investments for the year ended June 30, 2002 was $1.5 million, compared to $3.1 million for the year ended June 30, 2001. The decrease of $1.6 million in dividend income was due principally to the decline in dividends
received from West Shore. We sold our investment in West Shore on October 29, 2001.
Interest income for the year
ended June 30, 2002 was $0.6 million, compared to $2.9 million for the year ended June 30, 2001. The decrease of $2.3 million in interest income was due primarily to a decrease in interest
30
Table of Contents
bearing cash balances and lower interest rates during the year ended June 30, 2002. Pursuant to our cash management practices, excess cash balances are used to pay down our outstanding borrowings
under our bank credit facility and commodity margin loan.
Interest expense for the year ended June 30, 2002 was
$12.4 million, compared to $18.1 million during the year ended June 30, 2001. For the year ended June 30, 2002, our interest expense resulted from $7.0 million for outstanding borrowings under our bank credit facility and Senior Notes, $0.3 million
for outstanding letters of credit, $0.5 million for outstanding borrowings under our commodity margin loan, and $4.6 million in net payments for the interest rate swap. The decrease of $5.7 million in interest expense was primarily attributable to a
reduction in the amount of debt outstanding during the current year. We used a portion of the proceeds from the sale of the Little Rock facilities, NORCO system, and West Shore to repay our outstanding borrowings under our bank credit facility and
commodity margin loan. We also benefited from lower interest rates during the year ended June 30, 2002, as the average interest rate under our bank credit facility was 5.13% and 6.6% for the years ended June 30, 2002 and 2001, respectively.
Other financing costs for the year ended June 30, 2002 were $9.0 million, compared to $12.3 million for the year
ended June 30, 2001. The decrease of $3.3 million in other financing costs was due principally to a reduction in the amortization of deferred financing costs of $1.7 million and a lower unrealized loss on the interest rate swap of $1.3 million. The
unrealized loss on the interest rate swap was $2.3 million and $3.6 million during the years ended June 30, 2002 and 2001, respectively. The swap agreement provides that we pay a fixed interest rate of 5.48% on the notional amount of $150 million in
exchange for receiving a variable rate based on LIBOR so long as the one-month LIBOR interest rate does not rise above 6.75%. If the one-month LIBOR rate rises above 6.75%, the swap knocks out and we will receive no payments under the agreement
until such time as the one-month LIBOR rate declines below 6.75%. At June 30, 2002 and 2001, the one-month LIBOR rate was 1.84% and 4.08%, respectively. This swap agreement expires in August 2003.
Gain (loss) on the disposition of assets for the year ended June 30, 2002 consists of $(9.9) loss on the sale of West Shore, $8.6 million
gain on the sale of the NORCO system, $1.4 million gain on the sale of our investment in ST Oil Company, and $(0.1) loss on the sale of other assets. Gain on the disposition of assets was $22.1 million for the year ended June 30, 2001 due
to the sale of the Little Rock facilities.
Income Taxes
Income tax expense was $5.5 million for the year ended June 30, 2002, which represents an effective combined federal and state income tax rate of 39.0%. Income tax expense
was $6.7 million for the year ended June 30, 2001, which represents an effective combined federal and state income tax rate of 37.0%.
Preferred Stock Dividends
Preferred stock dividends on the Series A Convertible Preferred
Stock were $9.8 million and $9.0 million for the years ended June 30, 2002 and 2001, respectively. The increase in the current year dividend resulted from our election to pay the preferred dividends “in-kind” by issuing additional shares
of Series A Convertible Preferred Stock.
The fair value of the consideration paid to the holders of the Series A
Convertible Preferred Stock to affect the Preferred Stock Recapitalization was in excess of the financial statement carrying amount of the Series A Convertible Preferred Stock that was redeemed. That excess of approximately $1.5 million has been
treated in a manner similar to preferred stock dividends in the accompanying consolidated financial statements.
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Table of Contents
YEAR ENDED JUNE 30, 2001 COMPARED TO YEAR ENDED JUNE 30, 2000
We reported net earnings of $11.3 million for the year ended June 30, 2001, compared to a net loss of $(37.9) million for the year ended
June 30, 2000. After preferred stock dividends, the net earnings attributable to common stockholders was $2.4 million for the year ended June 30, 2001, compared to a net loss of $(46.4) million for the year ended June 30, 2000. Basic and
diluted earnings per common share for the year ended June 30, 2001 were $0.08 based on 30.9 million weighted average common shares outstanding and 31.0 million weighted average diluted shares outstanding. Basic and diluted loss per share for
the year ended June 30, 2000 were $(1.52) based on 30.5 million weighted average common shares outstanding.
The
increase in net earnings resulted primarily from the absence of an impairment charge in the year ended June 30, 2001, compared to a pre-tax $50.1 million impairment charge in fiscal 2000; increased net operating margins from the Product supply,
distribution and marketing operations, offset by the net operating margins from the natural gas services activities which were sold; decreased selling, general and administrative expenses; decreased depreciation and amortization expenses
attributable to the sale of the natural gas services activities; and decreased interest expense, attributable to a decrease in average interest rates for the current year, a reduction in the amount of outstanding debt resulting from the sale of the
natural gas services activities, and a reduction in the amount of discretionary inventory being carried by us during the current year.
Product Supply, Distribution and Marketing
The net revenues reported for the Product
supply, distribution and marketing operations include amounts realized on Product sales, exchanges and arbitrage transactions. During the year ended June 30, 2001, we benefited from the following items: increased supply disruptions in the gasoline
and distillate markets; concerns regarding the availability of distillate for the Northeastern region of the United States; the completion of our Baton Rouge dock facility which allowed us to arbitrage basis (geographical location) differentials
between Colonial pipeline supplied barrels and Mississippi River based barrels; and an overall increase in the demand for Products from customers supplied by us. In the prior year, we experienced losses from liquidating a portion of our
discretionary inventory position and an unfavorable impact from an abnormal price movement between crude oil and distillates. Subsequently, we amended our risk management policies to reduce the potential exposure from future abnormal commodity price
movements of this nature by establishing daily reporting of our cumulative profit and loss positions to various levels of management, each of which has predetermined limits that escalate with the applicable level of authority.
Our Products inventory consists primarily of gasoline and distillates, the majority of which is held for sale or exchange in
the ordinary course of business. A portion of this inventory, based on line fill and tank bottoms, is required to be held for operating balances in the conduct of our daily Product supply, distribution and marketing operations, and is maintained
both in tanks and pipelines owned by us and pipelines owned by third parties. During the quarter ended June 30, 2000, we embarked upon a thorough review of our inventory management strategies and customer contracts. As a result, we lowered our
required minimum inventory from over 3.8 million barrels to the current level of 2.0 million barrels. We also changed our strategy regarding the risk management associated with this minimum inventory. Previously, we were hedging the minimum
inventory in the futures market and we were renewing the hedges forward at the end of each month as the prior month’s hedging contracts expired. In connection with our new risk management strategy, we removed the hedging contracts on our
minimum inventory, thereby eliminating any future cash receipts or payments associated with rolling the hedging contracts on the inventory that was not being sold.
During the year ended June 30, 2000, we experienced a cash loss of $12.4 million associated with rolling the hedges into a backwardated market (a market in which the
current month commodity price is higher than the future price in succeeding periods) with respect to the minimum inventory. No loss of this type was realized in the year ended June 30, 2001 due to the change in the strategy associated with hedging
the minimum inventory. The new policy has resulted in recording the minimum inventories at the lower of cost or market with the resulting non-cash write-downs recognized in net operating margins. We recognized a lower of cost or market write-down of
$18.3 million during the year ended June 30, 2001 relating to our minimum inventories.
32
Table of Contents
Terminals and Pipelines
The net operating margins from our terminal and pipeline operations for the year ended June 30, 2001 was $45.9 million, compared to $44.3 million for the year ended June
30, 2000. The increase of $1.6 million in net operating margins is mostly attributable to increased utilization of our terminals during the current year which was offset somewhat by lower utilization of our pipeline systems. The total revenues
recognized by our terminal and pipeline operations increased by approximately $3.8 million during the year ended 2001. The increase in net operating margins resulting from the increases in revenues was offset by an increase of approximately
$2.3 million in operating expenses during the year ended June 30, 2001. In the year ended June 30, 2000, we recognized a loss of approximately $0.8 million for the write-off of a few small terminal customers’ receivable balances.
Natural Gas Services
Our natural gas services activities were divested effective December 31, 1999.
Selling, General, and Administrative
Selling, general and administrative expenses for the
year ended June 30, 2001 were $34.1 million, compared to $41.7 million for the year ended June 30, 2000. The decrease of $7.6 million in selling, general, and administrative expenses is due principally to lease contract cancellation costs,
additional personnel related costs related to separation and release agreements, non-cash stock compensation costs, and other personnel costs related to a corporate staff reduction and relocation plan, all of which amounted to approximately
$5.0 million during the year ended June 30, 2000 that were not incurred during the current year. The sale of our natural gas services activities resulted in a reduction of approximately $0.5 million of employee costs in the current year. During
the year ended June 30, 2001, travel and entertainment expenses decreased by approximately $0.6 million, and employee wage and benefit expenses decreased by approximately $1.5 million.
Depreciation and amortization for the year ended June 30, 2001 was $19.5 million, compared to $22.3 million for the year ended June 30, 2000. The decrease was due
primarily to the disposition of our natural gas services activities.
Non-cash impairment charges on long-lived
assets for the fiscal year ended June 30, 2000 totaled $50.1 million, before income taxes. The charges include $31.9 million relating to certain of our Product terminals acquired in the 1998 acquisition of Louis Dreyfus Energy Corp. and $18.2
million relating to certain intangible assets recorded as a result of the same acquisition. The impairment charges resulted from the change in the planned use of certain terminals and the abandonment of a pipeline that supplied one terminal, thereby
significantly impacting the economic viability of the terminals. Each of these events significantly reduced or eliminated future cash flows related to these assets. The $31.9 million impairment charge for the terminals reduced the book value of the
assets to their estimated fair value. The additional $18.2 million impairment charge for the intangible assets represented the unamortized balance of the intangible assets. Our review of the market location differentials associated with those
assets showed that we received little or no value from those assets in the period ended June 30, 2000. There were no impairment charges on long-lived assets for the year ended June 30, 2001.
Other Income and Expenses
Dividend income and
equity in earnings from petroleum related investments for the year ended June 30, 2001 were $3.1 million, compared to $1.6 million for the year ended June 30, 2000. The increase of $1.5 million in dividend income was due principally to dividends
being received from West Shore and Lion Oil in the year ended June 30, 2001, compared to the prior year in which dividends were received only from West Shore. Additionally, we recorded $0.1 million of equity earnings in the year ended June 30, 2001
from our investment in ST Oil Company.
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Table of Contents
Interest income for the year ended June 30, 2001 was $2.9 million, compared to
$3.4 million for the year ended June 30, 2000. The decrease of $0.5 million in interest income was due primarily to a decrease in interest bearing cash balances and lower interest rates during the year ended June 30, 2001.
Interest expense for the year ended June 30, 2001 was $18.1 million, compared to $28.5 million for the year ended June 30, 2000. The
decrease of $10.4 million in interest expense was primarily attributable to a reduction in the amount of debt outstanding during the current year resulting from the sale of our natural gas services activities and the liquidation of our discretionary
inventory in the prior year. We also benefited by an overall reduction in our borrowing rate under our bank credit facility due to declining LIBOR rates.
Other financing costs for the year ended June 30, 2001 were $12.3 million, compared to $6.9 million for the year ended June 30, 2000. The unrealized loss on the interest rate swap was $3.6 million for
the year ended June 30, 2001. In the year ended June 30, 2000, the unrealized gain on the interest rate swap was $1.6 million. The unrealized loss on the interest rate swap was due to a decline in the one-month LIBOR rates during the year ended
June 30, 2001.
Gain on the disposition of assets was $22.1 for the year ended June 30, 2001, primarily due to the
sale of the Little Rock facilities. Gain on the disposition of assets was $13.9 million for the year ended June 30, 2000 and was primarily due to the sale of our natural gas services activities, partially offset by losses on the disposition and
retirement of other assets no longer used in our operations.
Income Taxes
Income tax expense was $6.7 million for the year ended June 30, 2001, which represents an effective combined federal and state income tax rate of 37.0%. Income tax
benefit was $19.2 million for the year ended June 30, 2000, which represents an effective combined federal and state income tax rate of 33.6%. The effective tax rate for the year ended June 30, 2000 was lower than the effective tax rate for the year
ended June 30, 2001 due to an adjustment in cumulative temporary differences recognized in the fiscal year ended June 30, 2000.
Preferred Stock Dividends
Preferred stock dividends on the Series A Convertible Preferred
Stock were $9.0 million and $8.5 million for the years ended June 30, 2001 and 2000, respectively. The increase in the current year dividend resulted from our election to pay the preferred dividends for the quarters ended March 31 and June 30, 2001
“in-kind” by issuing additional shares of Series A Convertible Preferred Stock.
34
Table of Contents
FINANCIAL POSITION
At June 30, 2002, our current assets exceeded our current liabilities by $162.2 million, compared to $33.9 million at June 30, 2001. The increase of $128.3 in working
capital is due principally to increases in accounts receivable of $94.7 million and inventories—discretionary volumes of $138.0 million, net of amounts due under exchange agreements, being offset by decreases in the current portion of net
unrealized gains on energy trading and risk management contracts of $18.3 million and increases in accounts payable of $31.1 million and excise taxes payable of $40.0 million.
The increase in accounts receivable of $94.7 million is due principally to an increase in the volume of daily-priced rack sales, which are billed on a gross basis, compared
to exchange transactions, which are billed on a net basis, and an increase in Product supply, distribution, and marketing volumes coupled with a corresponding increase in the price of gasoline. Our gross revenues for the Product supply,
distribution, and marketing operations were approximately $564.8 million for the month ended June 30, 2002, compared to approximately $391.6 million for the month ended June 30, 2001.
Our inventories—discretionary volumes are held for sale or exchange in the ordinary course of business and consist of Products, primarily gasolines and distillates.
Our inventories—discretionary volumes are presented in the accompanying consolidated balance sheet as current assets and are carried at fair value. Inventories—discretionary volumes are as follows (in thousands):
| June 30, 2002 |
June 30, 2001 | |||||||||
| Amount |
Bbls |
Amount |
Bbls | |||||||
| Products held for sale or exchange |
$ |
158,261 |
5,224 |
$ |
20,234 |
468 | ||||
| Products due to others under exchange agreements, net |
|
16,908 |
525 |
|
76,754 |
2,778 | ||||
| |
|
|
|
|
| |||||
| Inventories—discretionary volumes |
$ |
175,169 |
5,749 |
$ |
96,988 |
3,246 | ||||
| |
|
|
|
|
| |||||
During the last six months of the year ended June 30, 2002, we
increased our discretionary inventory of distillates to capitalize on the “carry” or “contango” market structure. During a “contango” market, we utilize our and third-party terminals to store Products to capture
commodity price differentials between current and future months. At June 30, 2002, we held approximately 3.0 million barrels of distillates in our terminals for future delivery.
Our inventories—discretionary volumes are an integral component of our overall energy trading and risk management activities. We evaluate the level of
inventories—discretionary volumes in combination with energy trading and risk management disciplines, (including certain hedging strategies, forward purchases and sales, swaps and other financial instruments) to manage market exposure,
primarily commodity price risk. We evaluate the market exposure from an overall portfolio basis that considers both continuous movement of physical inventory balances and related open positions in energy trading and risk management contracts.
Our inventories—minimum volumes are required to be held for operating balances in the conduct of our overall
operating activities. We do not intend to sell or exchange these inventories in the ordinary course of business and, therefore, we do not hedge the market risks associated with this minimum inventory. Our inventories—minimum volumes are
presented in the accompanying consolidated balance sheet as non-current assets and are carried at the lower of cost or market. Inventories—minimum volumes are as follows (in thousands):
| June 30, 2002 |
June 30, 2001 | |||||||||
| Amount |
Bbls |
Amount |
Bbls | |||||||
| Gasolines |
$ |
27,855 |
1,200 |
$ |
33,831 |
1,200 | ||||
| Distillates |
|
17,443 |
800 |
|
24,430 |
800 | ||||
| |
|
|
|
|
| |||||
| Inventories—minimum volumes |
$ |
45,298 |
2,000 |
$ |
58,261 |
2,000 | ||||
| |
|
|
|
|
| |||||
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Table of Contents
During the years ended June 30, 2002 and 2001, we recognized impairment losses of
approximately $13.0 million and $18.3 million, respectively, due to lower of cost or market write-downs on this minimum inventory. These write-downs are included in net operating margins attributable to our Product supply, distribution, and
marketing operations. At June 30, 2002 and 2001, the weighted average adjusted cost basis of our inventories—minimum volumes was $0.54 and $0.69 per gallon, respectively.
During the three months ended June 30, 2000, we conducted a thorough review of our inventory management strategies and customer contracts. Effective July 1, 2000, we
designated 2.0 million barrels of refined petroleum products as inventories—minimum volumes and we changed our risk management strategy associated with this minimum inventory. In accordance with our revised risk management strategy, we removed
the hedging contracts on the minimum inventory volumes prior to July 1, 2002.
Relative month-end commodity prices
from June 30, 2001 to June 30, 2002 (NYMEX close on the last day of the month) are as follows:
| Crude |
Heating oil |
Gasoline | |||||
| 6/30/01 |
$ |
26.25 |
.709 |
.721 | |||
| 7/31/01 |
|
26.35 |
.697 |
.732 | |||
| 8/31/01 |
|
27.20 |
.766 |
.806 | |||
| 9/30/01 |
|
23.43 |
.664 |
.680 | |||
| 10/31/01 |
|
21.18 |
.598 |
.552 | |||
| 11/30/01 |
|
19.44 |
.532 |
.534 | |||
| 12/31/01 |
|
19.84 |
.551 |
.573 | |||
| 1/31/02 |
|
19.48 |
.523 |
.559 | |||
| 2/28/02 |
|
21.74 |
.563 |
.581 | |||
| 3/31/02 |
|
26.31 |
.669 |
.825 | |||
| 4/30/02 |
|
27.29 |
.689 |
.823 | |||
| 5/31/02 |
|
25.31 |
.630 |
.738 | |||
| 6/30/02 |
|
26.86 |
.680 |
.794 | |||
The following table indicates the maturities of our energy services
and risk management contracts, including the credit quality of our counter parties to those contracts with unrealized gains at June 30, 2002.
| Fair value of contracts (in thousands) |
||||||||||||||
| Maturity less than 1 year |
Maturity 1-3 years |
Maturity 4-5 years |
Maturity in excess of 5 years |
Total |
||||||||||
| Unrealized gain position—asset |
||||||||||||||
| Energy services contracts: |
||||||||||||||
| Investment grade |
$ |
3,651 |
|
— |
|
— |
— |
3,651 |
| |||||
| Non-investment grade |
|
4,123 |
|
7,979 |
|
— |
— |
12,102 |
| |||||
| No external rating |
|
6,751 |
|
113 |
|
6,864 |
| |||||||
| |
|
|
|
|
|
|
|
| ||||||
| |
14,525 |
|
8,092 |
|
— |
— |
22,617 |
| ||||||
| Risk management contracts— |
||||||||||||||
| NYMEX futures contracts |
|
11,809 |
|
5,877 |
|
— |
— |
17,686 |
| |||||
| |
|
|
|
|
|
|
|
| ||||||
| $ |
26,334 |
|
13,969 |
|
— |
— |
40,303 |
| ||||||
| |
|
|
|
|
|
|
|
| ||||||
| Unrealized loss position—liability |
||||||||||||||
| Energy services contracts |
$ |
(8,522 |
) |
(209 |
) |
— |
— |
(8,731 |
) | |||||
| Risk management contracts— |
||||||||||||||
| NYMEX futures contracts |
|
(13,641 |
) |
— |
|
— |
— |
(13,641 |
) | |||||
| |
|
|
|
|
|
|
|
| ||||||
| $ |
(22,163 |
) |
(209 |
) |
— |
— |
(22,732 |
) | ||||||
| |
|
|
|
|
|
|
|
| ||||||
| Net unrealized gain position—asset |
$ |
4,171 |
|
13,760 |
|
— |
— |
17,931 |
| |||||
| |
|
|
|
|
|
|
|
| ||||||
36
Table of Contents
At June 30, 2002, the unrealized gain on our energy services contracts with
non-investment grade counterparties was approximately $12.1 million. A single industrial/commercial end-user represented approximately $11.5 million of that unrealized gain. At June 30, 2002, we also had energy services contracts with that end-user
that were in an unrealized loss position of approximately $0.5 million. Therefore, the fair value of our energy services contracts with that industrial/commercial end-user was approximately $11.0 million at June 30, 2002. The following table
includes information about the changes in the fair value of our energy services contracts with that industrial/commercial end-user for the year ended June 30, 2002 (in thousands):
| Fair value at June 30, 2001 |
$ |
11,401 |
| |
| Amounts realized or otherwise settled during the year |
|
(3,461 |
) | |
| Fair value of additional contracts entered into during the year(1) |
|
4,689 |
| |
| Change in fair value attributable to change in commodity prices |
|
(2,002 |
) | |
| Other changes in fair value |
|
414 |
| |
| |
|
| ||
| Fair value at June 30, 2002 |
$ |
11,041 |
| |
| |
|
|
(1) |
Approximately $3.0 million was included in net revenues attributable to the Product supply, distribution and marketing activities and approximately $1.7 million
was deferred for supply chain management services to be provided over the term of the contract (see Note 11 of Notes to Consolidated Financial Statements). |
We do not acquire or sell Products, futures contracts, or other financial instruments solely for the purpose of speculating on changes in commodity prices. Our Risk
Management Committee reviews the discretionary inventory and related open positions in energy services and risk management contracts on a regular basis in order to ensure compliance with our inventory and risk management policies. We have adopted
policies under which changes to our net risk position, which is subject to commodity price risk, requires the prior approval of our Audit Committee of the Board of Directors.
Our inventories—discretionary volumes, energy services contracts, and risk management contracts are the integral components of our overall energy trading and risk
management activities. We evaluate our market risk exposure from an overall portfolio basis that considers changes in physical inventories—discretionary volumes, open positions in energy services contracts, and open positions in risk management
contracts. We have established risk management policies and procedures to monitor and control our market risk exposure. Our overall risk management objective is to minimize our exposure to changes in commodity prices. We accomplish this objective by
entering into risk management contracts that offset the changes in the values of our inventories—discretionary volumes and energy services contracts when there are changes in commodity prices. At June 30, 2002, our open positions in risk
management contracts include forward contracts (purchases and sales), swaps, and other financial instruments to manage market exposure, primarily commodity price risk.
We principally utilize exchange-traded risk management contracts to manage our commodity price risk. These contracts require us to maintain initial and variation margin
deposits with a third party financial intermediary. At June 30, 2002, we had $8.6 million on deposit to cover our margin requirements on open risk management contracts, which consisted solely of an initial margin deposit. At June 30, 2002, a $0.05
per gallon unfavorable change in commodity prices would have required us to deposit approximately $1.6 million in variation margin. Conversely, a $0.05 per gallon favorable change in commodity prices would have permitted us to reduce the deposit in
our margin account by approximately $1.6 million. We have the contractual right to request that the counterparties to our energy services contracts post additional letters of credit or make additional cash deposits with us to assist us in meeting
our obligations to cover our margin requirements.
Capital expenditures for the year ended June 30, 2002 were
$15.8 million for terminal and pipeline facilities and assets to support these facilities. Future capital expenditures will depend on numerous factors, including the availability, economics and cost of appropriate acquisitions which we identify and
evaluate; the economics, cost and required regulatory approvals with respect to the expansion and enhancement of existing systems and facilities; customer demand for the services we provide; local, state and federal governmental regulations;
37
Table of Contents
environmental compliance requirements; and the availability of debt financing and equity capital on acceptable terms.
On June 28, 2002, we executed the New Facility with a syndication of banks. The New Facility provides for a maximum borrowing line of credit that is the lesser of
(i) $300 million and (ii) the borrowing base. The borrowing base is a function of our accounts receivable, inventory, exchanges, margin deposits, open positions of energy services and risk management contracts, outstanding letters of credit,
and outstanding indebtedness as defined in the New Facility. Borrowings under the New Facility are secured by substantially all of our assets. The New Facility matures on June 27, 2005. The terms of the New Facility include financial covenants
relating to fixed charge coverage, current ratio, maximum leverage ratio, consolidated tangible net worth, capital expenditures, cash distributions and open inventory positions that are tested on a quarterly and annual basis. As of June 30, 2002, we
were in compliance with all covenants included in the New Facility. At June 30, 2002, we had borrowings of $187.0 million outstanding under the New Facility. We also had the ability to borrow an additional $113.0 million under the New Facility based
on the borrowing base computation at June 30, 2002.
We have contractual obligations that are required to be
settled in cash. The amounts of our contractual obligations are as follows (in thousands):
| Years ending June 30, |
|||||||||||||
| 2003 |
2004 |
2005 |
2006 |
2007 |
Thereafter | ||||||||
| Debt |
$ |
11,312 |
— |
187,000 |
— |
— |
— | ||||||
| Preferred stock |
|
— |
— |
— |
— |
— |
72,890 | ||||||
| Transportation and deficiency agreements |
|
779 |
786 |
786 |
489 |
— |
— | ||||||
| Operating leases: |
|||||||||||||
| New corporate headquarters |
|
— |
524 |
968 |
968 |
1,015 |
5,788 | ||||||
| Existing corporate headquarters (excluding estimated sublease rentals) |
|
1,888 |
1,398 |
1,435 |
1,468 |
1,380 |
2,591 | ||||||
| Property and equipment |
|
1,304 |
1,294 |
1,141 |
324 |
162 |
— | ||||||
| |
|
|
|
|
|
| |||||||
| Total contractual obligations to be settled in cash |
$ |
15,283 |
4,002 |
191,330 |
3,249 |
2,557 |
81,269 | ||||||
| |
|
|
|
|
|
| |||||||
See Notes 11, 12, 14 and 19 of Notes to Consolidated Financial
Statements.
We have outstanding letters of credit with third parties in the amount of $11.5 million which expire
within one year.
We believe that our current working capital position; future cash expected to be provided by
operating activities; available borrowing capacity under our New Facility and commodity margin loan; and our relationship with institutional lenders and equity investors should enable us to meet our planned capital and liquidity requirements.
CASH FLOWS
Net cash used by operating activities of $89.1 million for the fiscal year ended June 30, 2002 was due principally to increases in accounts receivable and inventories—discretionary volumes. The net cash provided by
operating activities of $35.5 million for the year ended June 30, 2001 was due principally to decreases in accounts receivable and inventories—discretionary volumes, offset by an increase in net assets from price risk management activities and
a decrease in trade accounts payable and inventory due under exchange agreements. The net cash provided by operating activities of $269.1 million for the year ended June 30, 2000 was due principally to a reduction in our physical inventory, an
increase in the amount of inventory due under exchanges and a reduction of trade accounts receivable, offset by a reduction in trade accounts payable.
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Table of Contents
Net cash provided by investing activities of $106.8 million for the year ended
June 30, 2002 was due principally to proceeds received from the sale of assets of $120.5 million offset by capital expended for construction and improvements to existing operating facilities and acquisitions of $15.8 million. Net cash used by
investing activities of $19.0 million during the year ended June 30, 2001 was due principally to capital expended for construction and improvements to existing operating facilities of $11.5 million and additional restricted cash of $8.0 million to
cover required margin deposits on risk management contracts. Net cash provided by investing activities of $76.3 million during the year ended June 30, 2000 was due principally to proceeds from the sale of our natural gas services activities of
$137.4 million offset by capital expended for construction and improvements to existing operating facilities and acquisitions of $61.3 million.
Net cash provided by financing activities of $3.8 million for the year ended June 30, 2002 was due principally to proceeds from additional borrowings under our bank credit facility of $57.0 million
offset by payments to retire common stock of $20.4 million, payments to retire preferred stock of $21.3 million, payments on our commodity margin loan of $8.7 million, and additional deferred debt issuance costs of $2.8 million. Net cash used by
financing activities of $61.1 million for the year ended June 30, 2001 was due principally to repayments of borrowings under our bank credit facility and master shelf facility of $77.0 million and payments of preferred stock dividends of $4.3
million offset by borrowings under our commodity margin loan of $20.0 million. Net cash used by financing activities of $305.4 million for the year ended June 30, 2000 was due principally to repayments of borrowings under our bank credit
facility and master shelf facility of $290.7 million and payments of preferred stock dividends of $8.5 million and additional deferred debt issuance costs of $6.4 million.
NEW ACCOUNTING STANDARDS
In June 2001, the Financial
Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 141 requires that the
purchase method of accounting be used for all business combinations initiated after June 30, 2001. SFAS No. 141 also specifies criteria intangible assets acquired in a purchase method business combination must meet to be recognized and reported
apart from goodwill, and establishes that any purchase price allocable to an assembled workforce may not be accounted for separately. SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but
instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142. SFAS No. 142 also requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives to their
estimated residual values, and reviewed for impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. We have adopted the provisions of SFAS No. 141 and we will adopt SFAS No. 142
effective July 1, 2002. The adoption of SFAS No. 141 did not have any impact on our financial statements, and we do not expect the adoption of SFAS No. 142 to have an impact on our financial statements.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which addresses financial accounting and
reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the
acquisition, construction, development and/or normal use of the asset. SFAS No. 143 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. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through
charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement. We are required to adopt the provisions of SFAS No. 143 effective July 1, 2002. To accomplish
this, we must identify all legal obligations for asset retirement obligations, if any, and determine the fair value of these obligations on the date of adoption. The determination of fair value is complex and will require us to gather market
information and develop cash flow models. Additionally, we will be required to develop processes to track and monitor these obligations. We currently are in the process of assessing the impact, if any, on our financial position, results of
operations, and cash flows of adopting SFAS No. 143. However, we are unable to estimate the impact of adopting this statement at the date of this report.
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Table of Contents
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, which is effective for fiscal years beginning after December 15, 2001. SFAS No. 144 establishes one accounting model to be used for long-lived assets to be disposed of by sale and broadens the presentation of
discontinued operations to include more disposal transactions. SFAS No. 144 also provides guidance that will eliminate inconsistencies in accounting for the impairment or disposal of long-lived assets under existing accounting pronouncements. The
new rule retains many of the fundamental recognition and measurement provisions provided for in SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, but significantly changes the
criteria for classifying an asset as held for sale. We do not expect the adoption of SFAS No. 144 to have an impact on our financial statements.
The FASB issued Statement No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections, on April 30, 2002. Statement No. 145 rescinds
Statement No. 4, which required all gains and losses from extinguishments of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. Upon adoption of Statement No. 145, companies will be
required to apply the criteria in APB 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 in
determining the classification of gains and losses resulting from the extinguishments of debt. Statement No. 145 is effective for fiscal years beginning after May 15, 2002. We have adopted SFAS No. 145 as of July 1, 2001 (see Note 11 of Notes to
Consolidated Financial Statements).
In June 2002 the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities, which addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (“EITF”) Issue No. 94-3, Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS No. 146 applies to costs associated with an exit activity that does not involve an entity newly acquired in a
business combination or with a disposal activity covered by SFAS No. 144. A liability for a cost associated with an exit or disposal activity generally shall be recognized and measured initially at its fair value in the period in which the liability
is incurred. In periods subsequent to initial measurement, changes to the liability shall be measured using the credit-adjusted risk-free rate that was used to measure the liability initially. We are required to adopt the provisions of SFAS No. 146
for exit or disposal activities initiated after December 31, 2002. In connection with our corporate relocation and transition, we accrued our expected lease abandonment costs and severance costs. It would appear that SFAS No. 146 would not permit
the accrual of those expected costs in advance of those costs being incurred. Had SFAS No. 146 been in effect for the year ended June 30, 2002, we believe that approximately $3.1 million of accrued lease abandonment costs and approximately $0.7
million of accrued severance benefits would not have been recognized at June 30, 2002.
40
Table of Contents
Risk Policies
We are exposed to market risk through changes in commodity prices and
interest rates as discussed below. We have no foreign currency exchange risks. Risk management policies have been established by our Risk Management Committee (“RMC”) to monitor and control these market risks. Our RMC is comprised
primarily of senior executives. Our RMC has responsibility for oversight with respect to all product risk management policies and our Audit Committee approves the financial exposure limits.
Commodity Risk
Our
earnings, cash flow and liquidity may be affected by a variety of factors beyond our control, including the supply of, and demand for Products. Demand for Products depends on, among other factors, changes in domestic and foreign economies, weather
conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. As a result, Products experience price volatility, which directly impacts
our revenues and net operating margins. Our net operating margins are not impacted as much by the absolute price of the commodities as they are by the impact that the absolute price has upon supply and demand and the related movement of Products.
We have developed risk management strategies to mitigate the risk associated with price volatility on our Product
inventories. We believe these strategies are integral to our risk policies since Product inventories are required to effectively operate our Product supply, distribution and marketing operations and such inventories are expected to be purchased,
sold and carried over extended periods of time in the ordinary course of business.
We mitigate exposure to
commodity price fluctuations by maintaining a balanced position of future commitments for Product purchases and sales, either in the physical commodity market or the derivative commodity markets. Our strategies are intended to minimize the impact of
Product prices volatility on profitability and generally involve the purchase and sale of exchange-traded, energy futures and options. To a lesser extent, we enter into energy swap agreements, such as crack spreads, when they better match specific
price movements in our markets. These strategies are designed to minimize, on a short-term basis, our exposure to the risk of fluctuations in Product margins. The barrels of Products covered by such contracts vary and are closely managed and subject
to internally established risk guidelines.
In connection with our Products supply, distribution and marketing
operations, we engage in price risk management activities. Our price risk management activities are energy trading activities as defined by EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities.
As such, the financial instruments utilized are marked to market in accordance with the guidance set forth in EITF 98-10. Under the mark-to-market method of accounting, forwards, swaps, options and other financial instruments with third parties are
reflected at market value, net of future physical delivery related costs, and are shown as “Unrealized gain or loss on energy services and risk management contracts” in the accompanying consolidated balance sheets. Unrealized gains and
losses from newly originated contracts, contract restructurings and the impact of price movements are included in net revenues. Changes in the assets and liabilities from price risk management activities result primarily from changes in the
valuation of the portfolio of contracts, newly initiated transactions and the timing of settlement relative to the receipt of cash for certain contracts. The market prices used to value these transactions reflect management’s best estimate
considering various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. The values are adjusted to reflect the potential impact of liquidating our position in an orderly
manner over a reasonable period of time under present market conditions.
For certain of our energy services
contracts and contract locations, calculating fair value relies on a degree of estimation in calculating the basis (geographical location) differentials for deferred trading months and locations without an actively traded forward cash market. For
these markets (in which we cannot secure a
41
Table of Contents
forward traded basis (geographical location) differential quote from a broker), our mark-to-market model estimates the basis (geographical location) differentials based on a rolling historical
average. Currently, it is not practicable for us to estimate the effects on our financial condition, results of operations, or cash flows from an unfavorable change in basis (geographical location) differentials.
Contractual commitments are subject to risks relating to market value fluctuations, as well as counterparty credit and liquidity risk. We
have established procedures to continually monitor these contracts in order to minimize credit risk, including the establishment and review of credit limits, margin requirements, master net out arrangements, letters of credit and other guarantees.
Interest Rate Risk
At June 30, 2002, we had outstanding $187.0 million under the New Facility. We are exposed to risk resulting from changes in interest rates as a result of the variable-rate
debt associated with the New Facility. The interest rate is based on the lender’s alternate base rate plus a spread, or LIBOR plus a spread, in effect at the time of the borrowings and is adjusted monthly, bi-monthly, quarterly or
semi-annually. Based on the outstanding balance of our variable interest rate debt at June 30, 2002, our interest rate swap, and assuming market interest rates increase or decrease 100 basis points, the potential annual increase or decrease in
interest expense is approximately $0.4 million.
In August 1999, we entered into two “periodic
knock-out” swap agreements with money center banks to offset the exposure of an increase in variable interest rates on our debt. Each swap was for a notional value of $150 million and was for a term expiring in August 2003. The swaps settle
monthly, contain a knockout level on the one-month LIBOR at or above 6.75%, and have a fixed interest rate of 5.48%. The swaps provide that we pay a fixed interest rate of 5.48% on $300 million notional amount in exchange for a variable rate based
on LIBOR so long as the one-month LIBOR interest rate does not rise above 6.75%. If the one-month LIBOR rate rises above 6.75%, the swap knocks out and no payments are due under the agreements until such time as the one-month LIBOR rate declines
below 6.75%. Prior to June 30, 2000, proceeds from the swap agreements were recorded as a reduction in interest expense, as the swaps were designated as hedges against the changes in interest rates.
As a result of the significant reduction in the variable rate debt during the fiscal year ended June 30, 2000 and with the adoption of
SFAS 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133, on June 30, 2000, the swaps were no
longer designated as hedges. Any changes in the fair value of the interest rate swap are recognized immediately in earnings. As a result, at June 30, 2000, we recorded the fair value of the two swap agreements at $1.6 million in other assets, and a
corresponding unrealized gain of $1.6 million. In August 2000, we settled one of the swap agreements, recognizing no gain or loss on the settlement. As of June 30, 2002, the fair market value of the remaining swap agreement is a liability of
$5.4 million, which is recorded in accrued liabilities. For the years ended June 30, 2002 and 2001, we recorded an unrealized (non-cash) loss on the interest rate swap of $2.3 million and $3.6 million, respectively. For the years ended June 30,
2002, 2001 and 2000, we made (received) net payments of $4.6 million, $(0.7) million, and $(1.0) million, respectively, on the interest rate swap that are included in interest expense (income).
42
Table of Contents
The
following consolidated financial statements should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations.
TransMontaigne Inc. and Subsidiaries
Independent Auditors’ Report
Consolidated Balance Sheets as of June 30, 2002
and 2001
Consolidated Statements of Operations for the years ended June 30, 2002, 2001 and 2000
Consolidated Statements of Preferred Stock and Common Stockholders’ Equity for the years ended
June 30, 2002, 2001 and 2000
Consolidated Statements of Cash Flows for the years ended June 30, 2002,
2001 and 2000
Notes to Consolidated Financial Statements
43
Table of Contents
Independent Auditors’ Report
The Board of Directors and Stockholders
TransMontaigne Inc.:
We have audited the accompanying consolidated balance sheets of TransMontaigne Inc. and subsidiaries as of June 30, 2002 and 2001, and the related consolidated
statements of operations, preferred stock and common stockholders’ equity, and cash flows for each of the years in the three-year period ended June 30, 2002. These consolidated financial statements are the responsibility of
TransMontaigne’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position
of TransMontaigne Inc. and subsidiaries as of June 30, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended June 30, 2002, in conformity with accounting principles
generally accepted in the United States of America.
Denver, Colorado
September 13, 2002
44
Table of Contents
TRANSMONTAIGNE INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(In thousands, except share amounts)
| June 30, 2002 |
June 30, 2001 |
||||||
| Assets |
|||||||
| Current assets: |
|||||||
| Cash and cash equivalents |
$ |
30,852 |
|
9,346 |
| ||
| Restricted cash held by commodity broker |
|
4,577 |
|
7,984 |
| ||
| Trade accounts receivable, net |
|
173,736 |
|
79,050 |
| ||
| Inventories—discretionary volumes |
|
175,169 |
|
96,988 |
| ||
| Unrealized gains on energy services and risk management contracts |
|
26,334 |
|
55,282 |
| ||
| Receivable from sale of assets |
|
— |
|
29,033 |
| ||
| Prepaid expenses and other |
|
2,598 |
|
4,130 |
| ||
| |
|
|
|
| |||
| |
413,266 |
|
281,813 |
| |||
| Property, plant and equipment, net |
|
251,431 |
|
304,232 |
| ||
| Inventories—minimum volumes |
|
45,298 |
|
58,261 |
| ||
| Unrealized gains on energy services and risk management contracts |
|
13,969 |
|
9,875 |
| ||
| Investments in petroleum related assets |
|
10,131 |
|
47,760 |
| ||
| Deferred tax assets |
|
7,882 |
|
12,944 |
| ||
| Deferred debt issuance costs, net |
|
2,729 |
|
4,667 |
| ||
| Other assets |
|
4,263 |
|
2,977 |
| ||
| |
|
|
|
| |||
| $ |
748,969 |
|
722,529 |
| |||
| |
|
|
|
| |||
| Liabilities, Preferred Stock, and Common Stockholders’ Equity |
|||||||
| Current liabilities: |
|||||||
| Commodity margin loan |
$ |
11,312 |
|
20,000 |
| ||
| Trade accounts payable |
|
103,314 |
|
72,170 |
| ||
| Unrealized losses on energy services and risk management contracts |
|
22,163 |
|
32,822 |
| ||
| Inventory due under exchange agreements, net |
|
16,908 |
|
76,754 |
| ||
| Excise taxes payable |
|
72,045 |
|
32,025 |
| ||
| Other accrued liabilities |
|
25,308 |
|
14,170 |
| ||
| |
|
|
|
| |||
| |
251,050 |
|
247,941 |
| |||
| Other liabilities: |
|||||||
| Long-term debt |
|
187,000 |
|
130,000 |
| ||
| Unrealized losses on energy services and risk management contracts |
|
209 |
|
2,213 |
| ||
| |
|
|
|
| |||
| Total liabilities |
|
438,259 |
|
380,154 |
| ||
| |
|
|
|
| |||
| Preferred stock: |
|||||||
| Series A Convertible Preferred stock |
|
24,421 |
|
174,825 |
| ||
| Series B Redeemable Convertible Preferred stock |
|
80,939 |
|
— |
| ||
| |
|
|
|
| |||
| |
105,360 |
|
174,825 |
| |||
| |
|
|
|
| |||
| Common stockholders’ equity: |
|||||||
| Common stock |
|
399 |
|
318 |
| ||
| Capital in excess of par value |
|
245,844 |
|
205,256 |
| ||
| Deferred stock-based compensation |
|
(2,540 |
) |
(2,465 |
) | ||
| Accumulated deficit |
|
(38,353 |
) |
(35,559 |
) | ||
| |
|
|
|
| |||
| |
205,350 |
|
167,550 |
| |||
| |
|
|
|
| |||
| $ |
748,969 |
|
722,529 |
| |||
| |
|
|
|
| |||
See accompanying notes to consolidated financial statements.
45
Table of Contents
TRANSMONTAIGNE INC. AND SUBSIDIARIES
Consolidated Statements of Operations
(In thousands, except per share amounts)
| Year ended June 30, 2002 |
Year ended June 30, 2001 |
Year ended June 30, 2000 |
||||||||
| Revenues: |
||||||||||
| Product supply, distribution, and marketing, net |
$ |
68,747 |
|
46,318 |
|
18,853 |
| |||
| Terminal and pipelines |
|
63,386 |
|
82,305 |
|
78,522 |
| |||
| Natural gas services |
|
— |
|
— |
|
18,249 |
| |||
| |
|
|
|
|
|
| ||||
| |
132,133 |
|
128,623 |
|
115,624 |
| ||||
| |
|
|
|
|
|
| ||||
| Direct operating costs and expenses: |
||||||||||
| Lower of cost or market write-downs on minimum inventory volumes |
|
(12,963 |
) |
(18,318 |
) |
— |
| |||
| Terminal and pipelines |
|
(27,668 |
) |
(36,415 |
) |
(34,268 |
) | |||
| Natural gas services |
|
— |
|
— |
|
(7,759 |
) | |||
| |
|
|
|
|
|
| ||||
| |
(40,631 |
) |
(54,733 |
) |
(42,027 |
) | ||||
| |
|
|
|
|
|
| ||||
| Net operating margins |
|
91,502 |
|
73,890 |
|
73,597 |
| |||
| |
|
|
|
|
|
| ||||
| Costs and expenses: |
||||||||||
| Selling, general and administrative |
|
(35,211 |
) |
(34,072 |
) |
(41,680 |
) | |||
| Depreciation and amortization |
|
(16,556 |
) |
(19,510 |
) |
(22,344 |
) | |||
| Impairment of long-lived assets |
|
— |
|
— |
|
(50,136 |
) | |||
| Corporate relocation and transition: |
||||||||||
| Severance, transition, and relocation benefits |
|
(2,138 |
) |
— |
|
— |
| |||
| Abandonment of office leases and leasehold improvements |
|
(4,178 |
) |
— |
|
— |
| |||
| |
|
|
|
|
|
| ||||
| |
(58,083 |
) |
(53,582 |
) |
(114,160 |
) | ||||
| |
|
|
|
|
|
| ||||
| Operating income (loss) |
|
33,419 |
|
20,308 |
|
(40,563 |
) | |||
| Other income (expenses): |
||||||||||
| Dividend income from and equity in earnings of petroleum related investments |
|
1,450 |
|
3,060 |
|
1,590 |
| |||
| Interest income |
|
599 |
|
2,914 |
|
3,419 |
| |||
| Interest expense |
|
(12,436 |
) |
(18,129 |
) |
(28,540 |
) | |||
| Other financing costs: |
||||||||||
| Early payment penalty on senior notes |
|
(1,943 |
) |
(1,277 |
) |
(875 |
) | |||
| Amortization of debt issuance costs |
|
(1,744 |
) |
(3,499 |
) |
(3,770 |
) | |||
| Write-off of debt issuance costs related to bank credit facility and senior notes |
|
(2,987 |
) |
(3,885 |
) |
(3,855 |
) | |||
| Unrealized gain (loss) on interest rate swap |
|
(2,322 |
) |
(3,634 |
) |
1,560 |
| |||
| Gain (loss) on disposition of assets, net |
|
(13 |
) |
22,146 |
|
13,930 |
| |||
| |
|
|
|
|
|
| ||||
| |
(19,396 |
) |
(2,304 |
) |
(16,541 |
) | ||||
| |
|
|
|
|
|
| ||||
| Earnings (loss) before income taxes |
|
14,023 |
|
18,004 |
|
(57,104 |
) | |||
| Income tax benefit (expense) |
|
(5,465 |
) |
(6,666 |
) |
19,167 |
| |||
| |
|
|
|
|
|
| ||||
| Net earnings (loss) |
$ |
8,558 |
|
11,338 |
|
(37,937 |
) | |||
| |
|
|
|
|
|
| ||||
See accompanying notes to consolidated financial statements.
46
Table of Contents
TRANSMONTAIGNE INC. AND SUBSIDIARIES
Consolidated Statements of Operations (continued)
(In thousands, except per share amounts)
| Year ended June 30, 2002 |
Year ended June 30, 2001 |
Year ended June 30, 2000 |
||||||||
| Computation of earnings (loss) per share: |
||||||||||
| Net earnings (loss) |
$ |
8,558 |
|
11,338 |
|
(37,937 |
) | |||
| Preferred stock dividends |
|
(11,351 |
) |
(8,963 |
) |
(8,506 |
) | |||
| |
|
|
|
|
|
| ||||
| Net earnings (loss) attributable to common stockholders |
$ |
(2,793 |
) |
2,375 |
|
(46,443 |
) | |||
| |
|
|
|
|
|
| ||||
| Earnings (loss) per common share |
||||||||||
| Basic |
$ |
(0.09 |
) |
0.08 |
|
(1.52 |
) | |||
| |
|
|
|
|
|
| ||||
| Diluted |
$ |
(0.09 |
) |
0.08 |
|
(1.52 |
) | |||
| |
|
|
|
|
|
| ||||
| Weighted average common shares outstanding: |
||||||||||
| Basic |
|
31,267 |
|
30,879 |
|
30,491 |
| |||
| |
|
|
|
|
|
| ||||
| Diluted |
|
31,267 |
|
31,003 |
|
30,491 |
| |||
| |
|
|
|
|
|
| ||||
See accompanying notes to consolidated financial statements.
47
Table of Contents
TRANSMONTAIGNE INC. AND SUBSIDIARIES
Consolidated Statements of Preferred Stock and Common Stockholders’ Equity
Years Ended June 30,
2002, 2001 and 2000
(In thousands)
| Preferred stock |
Common stock |
Capital in excess of par value |
Deferred stock-based compensation |
Retained earnings (accumulated
deficit) |
Total common
stockholders’ equity |
|||||||||||||||||
| Series A |
Series B |
|||||||||||||||||||||
| Balance at June 30, 1999 |
$ |
170,115 |
|
— |
$ |
305 |
|
197,122 |
|
— |
|
8,509 |
|
205,936 |
| |||||||
| Common stock issued for options exercised |
|
— |
|
— |
|
— |
|
136 |
|
— |
|
— |
|
136 |
| |||||||
| Net tax effect arising from stock-based compensation |
|
— |
|
— |
|
— |
|
(68 |
) |
— |
|
— |
|
(68 |
) | |||||||
| Deferred compensation related to restricted stock awards |
|
— |
|
— |
|
2 |
|
1,863 |
|
(1,865 |
) |
— |
|
— |
| |||||||
| Amortization of deferred stock-based compensation |
|
— |
|
— |
|
— |
|
— |
|
400 |
|
— |
|
400 |
| |||||||
| Compensation expense related to extension of exercise period of options |
|
— |
|
— |
|
— |
|
2,022 |
|
— |
|
— |
|
2,022 |
| |||||||
| Preferred stock dividends |
|
— |
|
— |
|
— |
|
— |
|
— |
|
(8,506 |
) |
(8,506 |
) | |||||||
| Net loss |
|
— |
|
— |
|
— |
|
— |
|
— |
|
(37,937 |
) |
(37,937 |
) | |||||||
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
| Balance at June 30, 2000 |
$ |
170,115 |
|
— |
$ |
307 |
|
201,075 |
|
(1,465 |
) |
(37,934 |
) |
161,983 |
| |||||||
| Common stock issued for options and warrants exercised |
|
— |
|
— |
|
6 |
|
1,891 |
|
— |
|
— |
|
1,897 |
| |||||||
| Net tax effect arising from stock-based compensation |
|
— |
|
— |
|
— |
|
(5 |
) |
— |
|
— |
|
(5 |
) | |||||||
| Forfeiture of restricted stock awards prior to vesting |
|
— |
|
— |
|
— |
|
(135 |
) |
135 |
|
— |
|
— |
| |||||||
| Deferred compensation related to restricted stock awards |
|
— |
|
— |
|
5 |
|
2,430 |
|
(2,435 |
) |
— |
|
— |
| |||||||
| Amortization of deferred stock-based compensation |
|
— |
|
— |
|
— |
|
— |
|
1,300 |
|
— |
|
1,300 |
| |||||||
| Preferred stock dividends, including $4,710 paid-in-kind |
|
4,710 |
|
— |
|
— |
|
— |
|
— |
|
(8,963 |
) |
(8,963 |
) | |||||||
| Net earnings |
|
— |
|
— |
|
— |
|
— |
|
— |
|
11,338 |
|
11,338 |
| |||||||
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
| Balance at June 30, 2001 |
$ |
174,825 |
|
— |
$ |
318 |
|
205,256 |
|
(2,465 |
) |
(35,559 |
) |
167,550 |
| |||||||
| Common stock issued for options exercised |
|
— |
|
— |
|
— |
|
151 |
|
— |
|
— |
|
151 |
| |||||||
| Common stock repurchased from employees for withholding taxes |
|
— |
|
— |
|
— |
|
(112 |
) |
— |
|
— |
|
(112 |
) | |||||||
| Net tax effect arising from stock-based compensation |
|
— |
|
— |
|
— |
|
(24 |
) |
— |
|
— |
|
(24 |
) | |||||||
| Forfeiture of restricted stock awards prior to vesting |
|
— |
|
— |
|
(1 |
) |
(501 |
) |
502 |
|
— |
|
— |
| |||||||
| Deferred compensation related to restricted stock awards |
|
— |
|
— |
|
4 |
|
2,085 |
|
(2,089 |
) |
— |
|
— |
| |||||||
| Amortization of deferred stock-based compensation |
|
— |
|
— |
|
— |
|
— |
|
1,512 |
|
— |
|
1,512 |
| |||||||
| Preferred stock dividends paid-in-kind |
|
9,816 |
|
— |
|
— |
|
— |
|
— |
|
(9,816 |
) |
(9,816 |
) | |||||||
| Recapitalization of Series A Convertible Preferred stock |
|
(160,220 |
) |
80,939 |
|
119 |
|
59,394 |
|
— |
|
(1,536 |
) |
57,977 |
| |||||||
| Common stock repurchased and retired |
|
— |
|
— |
|
(41 |
) |
(20,405 |
) |
— |
|
— |
|
(20,446 |
) | |||||||
| Net earnings |
|
— |
|
— |
|
— |
|
— |
|
— |
|
8,558 |
|
8,558 |
| |||||||
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
| Balance at June 30, 2002 |
$ |
24,421 |
|
80,939 |
$ |
399 |
|
245,844 |
|
(2,540 |
) |
(38,353 |
) |
205,350 |
| |||||||
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
See accompanying notes to consolidated financial statements.
48
Table of Contents
TRANSMONTAIGNE INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(In thousands)
| Year ended June 30, 2002 |
Year ended June 30, 2001 |
Year ended June 30, 2000 |
||||||||
| Cash flows from operating activities: |
||||||||||
| Net earnings (loss) |
$ |
8,558 |
|
11,338 |
|
(37,937 |
) | |||
| Adjustments to reconcile net earnings (loss) to net cash provided (used) by operating activities: |
||||||||||
| Depreciation and amortization |
|
16,556 |
|
19,510 |
|
22,344 |
| |||
| Equity in earnings of petroleum related investments |
|
— |
|
93 |
|
— |
| |||
| Deferred tax expense (benefit) |
|
5,062 |
|
6,224 |
|
(19,948 |
) | |||
| Net tax effect arising from stock-based compensation |
|
(24 |
) |
(5 |
) |
(68 |
) | |||
| Loss (gain) on disposition of assets, net |
|
13 |
|
(22,146 |
) |
(13,930 |
) | |||
| Impairment of long-lived assets |
|
— |
|
— |
|
50,136 |
| |||
| Abandonment of office leases |
|
3,110 |
|
— |
|
— |
| |||
| Abandonment of leasehold improvements |
|
1,068 |
|
— |
|
— |
| |||
| Amortization of deferred stock-based compensation |
|
1,512 |
|
1,300 |
|
400 |
| |||
| Amortization of debt issuance costs |
|
1,744 |
|
3,499 |
|
3,770 |
| |||
| Write-off of debt issuance costs |
|
2,987 |
|
3,885 |
|
3,855 |
| |||
| Unrealized loss (gain) on interest rate swap |
|
2,322 |
|
3,634 |
|
(1,560 |
) | |||
| Net change in unrealized (gains)/losses on long-term energy services and risk management contracts |
|
(6,098 |
) |
(7,663 |
) |
— |
| |||
| Lower of cost or market write-downs on minimum inventory volumes |
|
12,963 |
|
18,318 |
|
— |
| |||
| Compensation expense related to extension of exercise period on options |
|
— |
|
— |
|
2,022 |
| |||
| Other |
|
538 |
|
— |
|
316 |
| |||
| Changes in operating assets and liabilities, net of non-cash activities: |
||||||||||
| Trade accounts receivable, net |
|
(94,686 |
) |
38,689 |
|
56,383 |
| |||
| Inventories – discretionary volumes |
|
(78,182 |
) |
67,302 |
|
127,891 |
| |||
| Prepaid expenses and other |
|
1,533 |
|
1,944 |
|
(1,719 |
) | |||
| Trade accounts payable |
|
31,144 |
|
(34,507 |
) |
(58,795 |
) | |||
| Unrealized (gain)/loss on energy services and risk management contracts |
|
18,289 |
|
(36,797 |
) |
32,783 |
| |||
| Inventory due under exchange agreements, net |
|
(59,845 |
) |
(48,504 |
) |
99,467 |
| |||
| Excise taxes payable and other accrued liabilities |
|
42,309 |
|
9,393 |
|
2,116 |
| |||
| |
|
|
|
|
|
| ||||
| Net cash provided (used) by operating activities |
|
(89,127 |
) |
35,507 |
|
267,526 |
| |||
| |
|
|
|
|
|
| ||||
| Cash flows from investing activities: |
||||||||||
| Purchases of property, plant and equipment |
|
(15,809 |
) |
(11,542 |
) |
(61,264 |
) | |||
| Proceeds from sale of assets |
|
120,510 |
|
1,439 |
|
137,357 |
| |||
| Decrease (increase) in restricted cash held by commodity broker |
|
3,407 |
|
(7,984 |
) |
— |
| |||
| Decrease (increase) in other assets |
|
(1,286 |
) |
(882 |
) |
1,809 |
| |||
| |
|
|
|
|
|
| ||||
| Net cash provided (used) by investing activities |
|
106,822 |
|
(18,969 |
) |
77,902 |
| |||
| |
|
|
|
|
|
| ||||
| Cash flows from financing activities: |
||||||||||
| Net borrowings (repayments) of long-term debt |
|
57,000 |
|
(76,995 |
) |
(290,677 |
) | |||
| Net borrowings (repayments) of commodity margin loan |
|
(8,688 |
) |
20,000 |
|
— |
| |||
| Deferred debt issuance costs |
|
(2,791 |
) |
(1,779 |
) |
(6,370 |
) | |||
| Common stock issued for options and warrants exercised |
|
151 |
|
1,897 |
|
136 |
| |||
| Common stock repurchased from employees for withholding taxes |
|
(112 |
) |
— |
|
— |
| |||
| Common stock repurchased and retired |
|
(20,446 |
) |
— |
|
— |
| |||
| Cash paid to recapitalize preferred stock |
|
(21,303 |
) |
— |
|
— |
| |||
| Preferred stock dividends paid in cash |
|
— |
|
(4,253 |
) |
(8,506 |
) | |||
| |
|
|
|
|
|
| ||||
| Net cash provided (used) by financing activities |
|
3,811 |
|
(61,130 |
) |
(305,417 |
) | |||
| |
|
|
|
|
|
| ||||
| Increase (decrease) in cash and cash equivalents |
|
21,506 |
|
(44,592 |
) |
40,011 |
| |||
| Cash and cash equivalents at beginning of year |
|
9,346 |
|
53,938 |
|
13,927 |
| |||
| |
|
|
|
|
|
| ||||
| Cash and cash equivalents at end of year |
$ |
30,852 |
|
9,346 |
|
53,938 |
| |||
| |
|
|
|
|
|
| ||||
See accompanying notes to consolidated financial statements.
49
Table of Contents
TRANSMONTAIGNE INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows (continued)
(In thousands)
| Year ended June 30, 2002 |
Year ended June 30, 2001 |
Year ended June 30, 2000 |
||||||||
| Supplemental disclosures of cash flow information: |
||||||||||
| Cash paid for income taxes |
$ |
600 |
|
700 |
|
200 |
| |||
| |
|
|
|
|
|
| ||||
| Cash paid for interest expense |
$ |
12,240 |
|
19,731 |
|
26,542 |
| |||
| |
|
|
|
|
|
| ||||
| Sale of Bear Paw on December 31, 1999: |
||||||||||
| Assets disposed |
$ |
— |
|
— |
|
(114,313 |
) | |||
| Liabilities recorded |
|
— |
|
— |
|
(250 |
) | |||
| Interest income |
|
— |
|
— |
|
(78 |
) | |||
| Gain on disposition |
|
— |
|
— |
|
(16,587 |
) | |||
| |
|
|
|
|
|
| ||||
| Cash received from sale |
$ |
— |
|
— |
|
131,228 |
| |||
| |
|
|
|
|
|
| ||||
| Sale of Little Rock facilities on June 30, 2001: |
||||||||||
| Proceeds receivable |
$ |
— |
|
29,033 |
|
— |
| |||
| Assets disposed |
|
— |
|
(6,162 |
) |
— |
| |||
| Liabilities recorded: |
||||||||||
| Accrued environmental obligations |
|
— |
|
(700 |
) |
— |
| |||
| Other |
|
— |
|
(25 |
) |
— |
| |||
| Gain on disposition |
|
— |
|
(22,146 |
) |
— |
| |||
| |
|
|
|
|
|
| ||||
| Cash received from sale |
$ |
29,033 |
|
— |
|
— |
| |||
| |
|
|
|
|
|
| ||||
| Sale of West Shore shares on July 27, 2001 and October 29, 2001: |
||||||||||
| Investment in West Shore |
$ |
(35,952 |
) |
— |
|
— |
| |||
| Loss on disposition |
|
9,896 |
|
— |
|
— |
| |||
| |
|
|
|
|
|
| ||||
| Cash received from sale |
$ |
26,056 |
|
— |
|
— |
| |||
| |
|
|
|
|
|
| ||||
| Sale of NORCO system on July 31, 2001: |
||||||||||
| Assets disposed |
$ |
(49,733 |
) |
— |
|
— |
| |||
| Liabilities recorded upon sale: |
||||||||||
| Accrued environmental obligations |
|
(2,000 |
) |
— |
|
— |
| |||
| Accrued indemnities |
|
(1,300 |
) |
— |
|
— |
| |||
| Other |
|
(116 |
) |
— |
|
— |
| |||
| Gain on disposition |
|
(8,601 |
) |
— |
|
— |
| |||
| |
|
|
|
|
|
| ||||
| Cash received from sale |
$ |
61,750 |
|
— |
|
— |
| |||
| |
|
|
|
|
|
| ||||
| Sale of ST Oil Company on May 31, 2002: |
||||||||||
| Investment in ST Oil Company |
$ |
(1,677 |
) |
— |
|
— |
| |||
| Gain on disposition |
|
(1,363 |
) |
— |
|
— |
| |||
| |
|
|
|
|
|
| ||||
| Cash received from sale |
$ |
3,040 |
|
— |
|
— |
| |||
| |
|
|
|
|
|
| ||||
| Other cash sales – cash received from sales of other assets |
$ |
631 |
|
1,439 |
|
6,129 |
| |||
| |
|
|
|
|
|
| ||||
| Total cash received from sales of assets |
$ |
120,510 |
|
1,439 |
|
137,357 |
| |||
| |
|
|
|
|
|
| ||||
See accompanying notes to consolidated financial statements.
50
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Years ended June 30, 2002, 2001 and 2000
(1) Summary |
of Significant Accounting Policies |
Principles of Consolidation and Use of Estimates
Our accounting and financial reporting policies conform to accounting principles and practices generally accepted in the United States of America. The accompanying consolidated financial statements include the accounts of
TransMontaigne Inc. and its majority-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Changes in these
estimates and assumptions will occur as a result of the passage of time and the occurrence of future events. Actual results could differ from these estimates.
Nature of Business and Basis of Presentation
TransMontaigne Inc., a Delaware corporation (“TransMontaigne”), was formed in 1995 to create an independent petroleum products merchant based in Denver, Colorado. We are a holding company that conducts operations primarily
in the Mid-Continent, Gulf Coast, Southeast, Mid-Atlantic and Northeast regions of the United States. We provide a broad range of integrated supply, distribution, marketing, terminal storage, and transportation services to refiners, distributors,
marketers, and industrial/commercial end-users of refined petroleum products (e.g., gasoline, diesel fuel, and heating oil), chemicals, crude oil and other bulk liquids (collectively referred to as “Product”).
Our commercial operations currently are divided into two main areas: (i) Product supply, distribution, and marketing, and
(ii) terminals and pipelines.
Accounting for Product Supply, Distribution, and Marketing Operations
Our Product supply, distribution, and marketing operations include energy trading and risk
management activities. Our energy trading and risk management activities are marked to market (i.e., recorded at fair value in the accompanying consolidated balance sheet) in accordance with Emerging Issues Task Force Issue No. 98-10
(“EITF 98-10”), Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The mark-to-market method of accounting requires that the effect of changes in the fair value of our energy trading and risk
management activities be recognized as assets and liabilities and included in net revenues attributable to Product supply, distribution, and marketing in the period of the change in value.
The consensus on EITF 98-10 previously permitted revenues from energy trading and risk management activities to be presented on the face of the statement of
operations on either a gross or net basis. We previously elected to present revenues from our Product supply, distribution, and marketing operations on a gross basis with a separate line item entitled “Product costs” in the costs and
expenses section of the accompanying consolidated statements of operations. Product costs represent the cost of the Products sold, settlement of risk management contracts, transportation, storage, terminaling costs, and commissions. At its June 2002
meeting, the EITF amended its consensus on EITF 98-10 to require that revenues from energy trading and risk management activities be reported on a net basis (i.e., product costs are required to be netted directly against gross revenues to arrive at
net revenues). That amended guidance is effective for
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
financial statements issued for periods ending after July 15, 2002. Nevertheless, we have chosen to adopt early that amended guidance for all periods presented. Therefore, for the year ended June
30, 2002 and all prior periods, we have presented revenues from our Product supply, distribution and marketing operation on a net basis in the accompanying consolidated statements of operations. Net earnings (loss) have not been affected by this
change in presentation. Net revenues attributable to our Product supply, distribution, and marketing operations are as follows (in thousands):
| Years ended June 30, |
||||||||||
| 2002 |
2001 |
2000 |
||||||||
| Gross revenues |
$ |
5,967,508 |
|
5,140,833 |
|
4,953,707 |
| |||
| Less cost of revenues |
|
(5,898,761 |
) |
(5,094,515 |
) |
(4,934,854 |
) | |||
| |
|
|
|
|
|
| ||||
| Net revenues |
$ |
68,747 |
|
46,318 |
|
18,853 |
| |||
| |
|
|
|
|
|
| ||||
The cash flow impact of these energy trading and
risk management activities is reflected in cash flows from operating activities in the accompanying consolidated statements of cash flows.
We evaluate our market exposure, primarily commodity price risk, from an overall portfolio basis that considers both continuous movement of discretionary inventory volumes and related open positions in
energy services and risk management contracts. Our inventories—discretionary volumes are an integral component of our overall energy trading and risk management activities.
Energy Services Contracts. We enter into energy services contracts that require us to deliver physical quantities of Product
over a specified term at a specified price. The pricing of the Product delivered under energy services contracts may be fixed at a stipulated price per gallon, or it may vary based on changes in published indices (e.g., Platt’s—Bulk and
OPIS—Wholesale).
Our energy services contracts are carried at fair value in the accompanying
consolidated financial statements. The fair value of our energy services contracts is included in “Unrealized gains or losses on energy services and risk management contracts” in the accompanying consolidated balance sheet. Changes in the
fair value of our energy services contracts are included in net revenues attributable to our Product supply, distribution and marketing operations.
The fair value of an energy services contract is based on a combination of published daily market prices and estimates based on historical market
conditions. For market locations in which we have access to Product via our terminals, dedicated pipeline capacity, and/or a throughput/exchange arrangement, fair value is determined by adding the quoted near month New York Mercantile Exchange
(“NYMEX”) futures quote to the appropriate basis (geographical location) differential and the transportation cost to deliver the Product from the bulk trading location to the contract’s specified delivery location. We estimate the
basis (geographical location) differentials for certain deferred trading months and city-specific locations because we cannot secure a forward traded basis (geographical location) differential quote from a broker. In those situations, our
mark-to-market model estimates the basis (geographical locations) differentials based on a rolling historical average, which is updated quarterly.
For market locations in which we do not have access to Product via our terminals, dedicated pipeline capacity, and/or a throughput/exchange arrangement, we
purchase Product on a spot basis from approved vendors to satisfy our contractual obligations. In these contracts, we are exposed to the differential between
52
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
the bulk trading locations and the city-specific wholesale markets, as we do not control the pipeline and terminal capacity to facilitate shipment of the physical Product. Our mark-to-market
model incorporates this basis (geographical location) differential to each city-specific location.
Risk Management Contracts. We enter into risk management contracts to minimize our exposure to changes in commodity prices. We evaluate our market risk exposure from an overall portfolio basis that
considers changes in physical inventories—discretionary volumes, open positions in energy services contracts, and open positions in risk management contracts. We enter into risk management contracts that offset the changes in the values of our
inventories—discretionary volumes and energy services contracts. At June 30, 2002, our open positions in risk management contracts include forward contracts (purchases and sales), swaps, and other financial instruments to manage market
exposure, primarily commodity price risk.
Our risk management contracts are carried at
fair value in the accompanying consolidated financial statements. The fair value of our risk management contracts is included in “Unrealized gains or losses on energy services and risk management contracts” in the accompanying consolidated
balance sheet. Changes in the fair value of our risk management contracts are included in net revenues attributable to our Product supply, distribution and marketing operations. The fair value of our risk management contracts is based on quoted
market prices. Forward contracts (purchases and sales) are valued using NYMEX quoted market prices.
We also enter into various swap agreements with our trading partners and price risk management customers that settle against a wide variety of wholesale and retail pricing indices. We utilize a combination of futures contracts and
over-the-counter forward contracts to manage the commodity price risk associated with these contracts. Our methodology used to calculate a forward replacement cost for these instruments is consistent with the methodology used to value our forward
physical cash commitments. We use a rolling historical average difference between the pricing index that the swap contract utilizes (e.g., Department of Energy National and OPIS-Wholesale indices) and the related NYMEX futures contract utilized to
manage the commodity price risk associated with the commitment.
Inventories—Discretionary
Volumes. Our inventories—discretionary volumes are held for sale or exchange in the ordinary course of business and consist of refined petroleum products, primarily gasoline and distillates. Our
inventories—discretionary volumes are carried at fair value in the accompanying consolidated financial statements. Changes in the fair value of our inventories—discretionary volumes are included in net revenues attributable to our Product
supply, distribution and marketing operations.
We maintain and hold for sale or exchange
discretionary inventory that has different quality grades but is interchangeable within these grades (e.g., premium, mid-grade, and regular unleaded gasoline). Our refined petroleum products inventories are traded in futures markets, large fungible
bulk markets (Pasadena, TX, New York Harbor, Chicago, IL, Tulsa, OK refining area, and Los Angeles, CA); and in city-specific wholesale markets. Quoted market prices (e.g., NYMEX, Platt’s-Bulk, and OPIS-Wholesale) are readily available for
these markets. The valuation of our inventories—discretionary volumes is based on the nearest quoted market price, plus quoted basis (geographical location) differentials to the various bulk market areas, plus Federal Energy Regulatory
Commission regulated transportation costs and industry recognized handling charges to city-specific wholesale markets. Near-term basis (geographical location) differentials are quoted and traded in the over-the-counter petroleum markets and are
verified by the various cash brokers that facilitate trading. We estimate the basis (geographical location) differentials for certain deferred trading months and city-specific locations because we cannot secure a forward traded basis (geographical
location) differential quote from a broker. In those situations, our mark-to-market model estimates the basis (geographical locations) differentials based on a rolling historical average, which is updated quarterly.
53
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
We utilize this valuation methodology for all
inventories—discretionary volumes held by us in storage, along with any valuation of a related exchange imbalance with a trading partner. This methodology provides us a consistent means of valuing discretionary inventory volumes at a spot
liquidation value and utilizes pricing components that are based on market prices and regulated pipeline tariffs.
Inventories—Minimum Volumes. Our inventories—minimum volumes are required to be held for operating balances in the conduct of our overall operating activities. We do not consider our
inventories—minimum volumes to be a component of our energy trading and risk management activities. We do not intend to sell or exchange these inventories in the ordinary course of business and, therefore, we do not hedge the market risks
associated with this minimum inventory.
Our inventories—minimum volumes are presented in the
accompanying consolidated balance sheet as non-current assets and are carried at the lower of cost or market (replacement cost). The replacement cost of our inventories—minimum volumes is based on the nearest quoted market price, plus quoted
basis (geographical location) differentials to the various bulk market areas, plus Federal Energy Regulatory Commission regulated transportation costs and industry recognized handling charges to city-specific wholesale markets. Near-term basis
(geographical location) differentials are quoted and traded in the over-the-counter petroleum markets and are easily verified by the various cash brokers that facilitate trading.
Prior to July 1, 2000, we carried our inventories—minimum volumes at fair value because they were a component of our energy trading and risk management
activities. Effective July 1, 2000, upon completion of a review of our inventory management strategies and customer contracts, we designated 2.0 million barrels of refined petroleum products as inventories—minimum volumes and we changed our
risk management strategy associated with this minimum inventory. In accordance with our revised risk management strategy, we removed the hedging contracts on the inventories—minimum volumes prior to July 1, 2000.
Accounting for Terminal and Pipeline Activities
In connection with our terminal and pipeline operations, we utilize the accrual method of accounting for revenue and expenses. At our terminals and
pipelines, we provide throughput, storage, and transportation related services to distributors, marketers, and industrial/commercial end-users of Products. Throughput revenue is recognized when the Product is delivered to the customer; storage
revenue is recognized ratably over the term of the storage contract; transportation revenue is recognized when the Product has been delivered to the customer at the specified delivery location.
Cash and Cash Equivalents
We consider all short-term investments with a remaining maturity of three months or less at the date of purchase to be cash equivalents.
Restricted cash represents cash deposits held by our commodity broker to cover initial and variation margin requirements related to open NYMEX futures
contracts.
Property, Plant and Equipment
Depreciation is computed using the straight-line and double-declining balance methods. Estimated useful lives are 20 to 25 years for plant, which includes
buildings, storage tanks, and pipelines, and 3 to 20 years for equipment. All items of property, plant and equipment are carried at cost. Expenditures that
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
increase capacity, or extend useful lives are capitalized. Routine repairs and maintenance are expensed. For the years ended June 30, 2002, 2001 and 2000, we incurred repairs and maintenance
costs of approximately $7.7 million, $8.7 million, and $7.3 million, respectively. Computer software costs are capitalized and amortized over their useful lives, generally not to exceed 5 years. The costs of installing certain enterprise wide
information systems are amortized over periods not exceeding 10 years.
We evaluate long-lived
assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable based on expected undiscounted cash flows attributable to that asset. If an asset is impaired, the impairment loss
to be recognized is the excess of the carrying amount of the asset over its estimated fair value (see Note 9 of Notes to Consolidated Financial Statements).
Deferred Debt Issuance Costs
Deferred debt
issuance costs are amortized using the interest method over the term of the underlying debt instrument.
Environmental Obligations
We accrue for environmental costs that relate to
existing conditions caused by past operations when estimable. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated
and ongoing monitoring costs, as well as fines, damages and other costs, including direct internal and legal costs. Liabilities for environmental costs at a specific site are initially recorded when it is probable that we will be liable for such
costs, and a reasonable estimate of the associated costs can be made based on available information. Such an estimate includes our share of the liability for each specific site and the sharing of the amounts related to each site that will not be
paid by other potentially responsible parties, based on enacted laws and adopted/regulations and policies. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional
information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of
investigation at certain sites, the lengthy time frames required to complete remediation, technology changes, alternatives available and the evolving nature of environmental laws and regulations. At June 30, 2002 and 2001, we had accrued
environmental reserves of approximately $2.3 million and $0.7 million, respectively, representing our best estimate of our remediation obligations (see Note 11 of Notes to Consolidated Financial Statements). During the year ended June 30, 2002, we
made payments of approximately $0.4 million towards our remediation obligations.
Income Taxes
We utilize the asset and liability method of accounting for income taxes. Under this method,
deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets
and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment
date.
Equity-Based Compensation Plans
We account for our employee stock option plans and restricted stock awards using the intrinsic value method pursuant to APB Opinion No. 25. We recognize
deferred compensation on the date of grant if the
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
quoted market price of the underlying common stock exceeds the exercise price (zero exercise price in the case of an award of restricted common stock). Deferred compensation is amortized to
income over the related vesting period on an accelerated basis pursuant to FASB Interpretation No. 28.
Earnings (Loss) Per Common Share
Basic earnings (loss) per common share is
calculated based on the weighted average number of common shares outstanding during the period, excluding restricted common stock subject to continuing vesting requirements. Diluted earnings (loss) per share is calculated based on the weighted
average number of common shares outstanding during the period and, when dilutive, potential common shares from the exercise of stock options and warrants to purchase common stock and restricted common stock subject to continuing vesting requirements
pursuant to the treasury stock method. Diluted earnings (loss) per share also gives effect, when dilutive, to the conversion of the preferred stock pursuant to the if-converted method.
Reclassifications
Certain amounts in the prior years have been reclassified to conform to the current year’s presentation. We have classified inventories—minimum volumes as a non-current asset in the accompanying consolidated balance sheet
(see Note 7 of Notes to Consolidated Financial Statements). We also have presented separately the current and non-current unrealized gains/losses on open energy services and risk management contracts in the accompanying consolidated balance sheet
(see Note 5 of Notes to Consolidated Financial Statements). At June 30, 2001, we presented our commodity margin loan (see Note 12 of Notes to Consolidated Financial Statements) as an offset to cash and cash equivalents and we presented our preferred
stock as a component of stockholders’ equity (see Note 14 of Notes to Consolidated Financial Statements) in the accompanying consolidated balance sheet. Net earnings (loss) have not been affected by these reclassifications.
(2) |
Dispositions of Terminals and Pipelines |
On July 31, 2001, we sold the NORCO Pipeline system and related terminals (“NORCO”) for cash consideration of approximately $62.0 million and
recognized a net gain of approximately $8.6 million on the sale. For the year ended June 30, 2001, we recognized net revenues of approximately $8.6 million, direct operating costs and expenses of approximately $3.3 million, and depreciation and
amortization expense of approximately $3.0 million related to the operations of the NORCO system.
Effective June 30, 2001, we sold two petroleum distribution facilities in Little Rock, Arkansas for $29.0 million. The cash proceeds from the sales transactions were received on July 3, 2001. We recognized a net gain in June
2001 of approximately $22.1 million on the sale. For the year ended June 30, 2001, we recognized net revenues of approximately $4.7 million, direct operating costs and expenses of approximately $0.9 million, and depreciation and amortization expense
of approximately $0.4 million.
Effective December 31, 1999, we sold our natural gas gathering
subsidiary, Bear Paw Energy Inc. (“BPEI”), for cash consideration of $131.2 million and recognized a net gain of approximately $16.6 million on the sale.
(3) |
Acquisitions of Terminals and Pipelines |
Effective June 30, 2002, we acquired for cash consideration of approximately $7.2 million the remaining 40% interest that we previously did not own in the
Razorback Pipeline system (“Razorback”), a
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
67 mile petroleum products pipeline between Mount Vernon, Missouri and Rogers, Arkansas with approximately .4 million barrels of storage capacity.
On May 31, 2000, we acquired two Products terminals located in Richmond and Montvale, Virginia for cash consideration of
approximately $3.2 million. These facilities are interconnected to the Colonial and Plantation pipeline systems and include approximately 0.5 million barrels of storage capacity.
We accounted for these acquisitions using the purchase method of accounting as of the effective date of each transaction. Accordingly, the purchase price of
each transaction was allocated to the assets and liabilities acquired based upon the estimated fair value of those assets and liabilities as of the acquisition date. The purchase price was allocated as follows (in thousands):
| Razorback |
Virginia terminals | |||||
| Prepaid expenses and other current assets |
$ |
2 |
|
— | ||
| Property, plant and equipment |
|
7,188 |
|
3,234 | ||
| Other accrued liabilities assumed |
|
(75 |
) |
— | ||
| |
|
|
| |||
| Cash paid, net of cash acquired of $85 and $0, respectively |
$ |
7,115 |
|
3,234 | ||
| |
|
|
| |||
The proforma combined results of operations
including Razorback as if the acquisition of Razorback had occurred on July 1, 2001 would not have been materially different from the results of operations reported in the accompanying consolidated statements of operations.
(4) |
Inventories—Discretionary Volumes |
Inventories—discretionary volumes are as follows (in thousands):
| June 30, 2002 |
June 30, 2001 | ||||
| Products held for sale or exchange |
$ |
158,261 |
20,234 | ||
| Products due under exchange agreements, net |
|
16,908 |
76,754 | ||
| |
|
| |||
| Inventories—discretionary volumes |
$ |
175,169 |
96,988 | ||
| |
|
| |||
Our inventories—discretionary volumes are held
for sale or exchange in the ordinary course of business and consist of Products, primarily gasolines and distillates. Our inventories—discretionary volumes are presented in the accompanying consolidated balance sheet as current assets and are
carried at fair value. Changes in the fair value of our inventories—discretionary volumes are included in net revenues attributable to our Product supply, distribution and marketing segment. Products due under exchange agreements represent
physical Products in our possession that we owe to counterparties pursuant to an exchange agreement in which we exchange Product in a specified delivery location for Product in a different delivery location.
Our inventories—discretionary volumes are an integral component of our overall energy trading and risk management
activities. We manage inventories—discretionary volumes in combination with energy services and risk management contracts by utilizing risk and portfolio management disciplines, including certain hedging strategies, forward purchases and sales,
swaps and other financial instruments to manage market exposure, primarily commodity price risk (see Note 5 of Notes to Consolidated Financial
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Table of Contents
TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
Statements). At June 30, 2002 and 2001, we held for sale or exchange approximately 5.2 million and .5 million barrels of discretionary inventory, net of .5 million and 2.8 million barrels
due under exchange agreements, at a weighted average value of approximately $0.72 and $1.03 per gallon, respectively.
(5) |
Unrealized Gains/Losses on Energy Services and Risk Management Contracts, Net |
Unrealized gains and losses on energy services and risk management contracts are as follows (in thousands):
| June 30, 2002 |
June 30, 2001 |
||||||
| Unrealized gains—current |
$ |
26,334 |
|
55,282 |
| ||
| Unrealized gains—long-term |
|
13,969 |
|
9,875 |
| ||
| |
|
|
|
| |||
| Unrealized gains—asset |
|
40,303 |
|
65,157 |
| ||
| |
|
|
|
| |||
| Unrealized losses—current |
|
(22,163 |
) |
(32,822 |
) | ||
| Unrealized losses—long-term |
|
(209 |
) |
(2,213 |
) | ||
| |
|
|
|
| |||
| Unrealized losses—liability |
|
(22,372 |
) |
(35,035 |
) | ||
| |
|
|
|
| |||
| Net asset position |
$ |
17,931 |
|
30,122 |
| ||
| |
|
|
|
| |||
Our energy services contracts are primarily sales
commitments to industrial/commercial end users, logistical service contracts, and basis (geographical) differentials versus published indices (referred to as “swaps”). These commitments provide our customers both price risk management and
real time inventory management solutions via our web-based information systems.
Our risk
management contracts include forward purchases and sales, swaps, and other financial instruments to offset market exposure, primarily commodity price risk, on our energy trading contracts and inventories—discretionary volumes. In managing
market risks on these contracts and inventories, we evaluate the market exposure from an overall portfolio basis that considers both the open position in the energy services contracts and the related movement of certain physical inventory balances
(see Note 4 of Notes to Consolidated Financial Statements).
(6) |
Property, Plant and Equipment, net |
Property, plant and equipment, net is as follows (in thousands):
| June 30, 2002 |
June 30, 2001 |
||||||
| Land |
$ |
14,125 |
|
15,181 |
| ||
| Terminals, pipelines, and equipment |
|
277,393 |
|
320,127 |
| ||
| Technology and equipment |
|
12,658 |
|
12,654 |
| ||
| Furniture, fixtures, and equipment |
|
5,732 |
|
6,703 |
| ||
| Construction in progress |
|
2,444 |
|
3,592 |
| ||
| |
|
|
|
| |||
| |
312,352 |
|
358,257 |
| |||
| Less accumulated depreciation |
|
(60,921 |
) |
(54,025 |
) | ||
| |
|
|
|
| |||
| $ |
251,431 |
|
304,232 |
| |||
| |
|
|
|
| |||
58
Table of Contents
(7) |
Inventories—Minimum Volumes |
Inventories—minimum volumes are as follows (in thousands):
| June 30, 2002 |
June 30, 2001 |
||||||
| Products: |
|||||||
| At original cost basis |
$ |
76,579 |
|
76,579 |
| ||
| Adjustment for write-downs to lower of cost or market |
|
(31,281 |
) |
(18,318 |
) | ||
| |
|
|
|
| |||
| Inventories—minimum volumes |
$ |
45,298 |
|
58,261 |
| ||
| |
|
|
|
| |||
Our inventories—minimum volumes are required
to be held for operating balances in the conduct of our overall operating activities. We do not consider our inventories—minimum volumes to be a component of our energy trading and risk management activities. We do not intend to sell or
exchange these inventories in the ordinary course of business and, therefore, we do not hedge the market risks associated with this minimum inventory. Our inventories—minimum volumes are presented in the accompanying consolidated balance sheet
as non-current assets and are carried at the lower of cost or market. During the year ended June 30, 2002 and 2001, we recognized impairment losses of approximately $13.0 million and $18.3 million, respectively, due to lower of cost or
market write-downs on this minimum inventory. These write-downs are included in net revenues attributable to our Product supply, distribution, and marketing operations. At June 30, 2002 and 2001, the weighted average adjusted cost basis of our
inventories—minimum volumes was $0.54 and $0.69 per gallon, respectively.
Prior to July 1,
2000, we carried our inventories—minimum volumes at fair value because they were a component of our energy trading and risk management activities. Effective July 1, 2000, upon completion of a review of our inventory management strategies and
customer contracts, we designated 2.0 million barrels of Products as inventories—minimum volumes and we changed our risk management strategy associated with this minimum inventory. In accordance with our revised risk management strategy, we
removed the hedging contracts on the inventories—minimum volumes prior to July 1, 2000.
(8) |
Investments in Petroleum Related Assets |
Investments in petroleum related assets are as follows (in thousands):
| June 30, 2002 |
June 30, 2001 | ||||
| Lion Oil Company |
$ |
10,131 |
10,131 | ||
| ST Oil Company |
|
— |
1,677 | ||
| West Shore |
|
— |
35,952 | ||
| |
|
| |||
| $ |
10,131 |
47,760 | |||
| |
|
| |||
We own 18.04% of the common stock of Lion Oil
Company (“Lion”), an Arkansas based refinery. For financial reporting purposes, we carry our investment in Lion at the lower of cost or net realizable value. For the years ended June 30, 2002, 2001 and 2000, we recorded dividend income
from Lion of approximately $0.7 million, $0.8 million, and none, respectively.
In August
2000, we converted our note receivable and accrued interest from ST Oil Company into an additional 11.6% equity ownership position resulting in our owning a 30.02% equity ownership position. We accounted for our investment in ST Oil Company on the
equity method. For the years ended June 30, 2002 and 2001, we recorded equity in earnings from ST Oil Company of less than $0.1 million. On May 31, 2002, our investment in ST Oil Company was reacquired by ST Oil Company for cash consideration of
approximately $3.0 million, resulting in a net gain of approximately $1.4 million on the sale.
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
We owned 20.38% of the common stock of West Shore
Pipeline Company (“West Shore”). Although we owned 20.38%, we did not have the ability to significantly influence the activities of West Shore and, therefore, carried our investment at cost. On July 27, 2001, we sold 861 shares of the
common stock of West Shore, thereby reducing our ownership interest to 18.50%. The West Shore common stock was sold to Midwest Pipeline Company, LLC for cash consideration of approximately $2.9 million. We recognized a net loss of approximately $1.1
million on this sale. As a result of this transaction, we also recognized a loss on our remaining investment in West Shore of approximately $8.8 million. On October 29, 2001, we sold our remaining interest to Buckeye Partners L.P. for cash
consideration of approximately $23.1 million, which approximated our adjusted cost basis. For the years ended June 30, 2002, 2001 and 2000, we recognized dividend income from West Shore of approximately $0.7 million, $2.2 million, and $1.6 million,
respectively.
(9) |
Impairment of Long-Lived assets |
There were no impairment charges on long-lived assets for the years ended June 30, 2002 and 2001. For the year ended June 30, 2000, we recognized an
impairment charge on long-lived assets of approximately $50.1 million, before income taxes. The charge includes $31.9 million relating to certain of our Product terminals acquired in the 1998 acquisition of Louis Dreyfus Energy Corporation and $18.2
million relating to certain intangible assets recorded as a result of the same acquisition. In calculating this impairment charge, we estimated future cash flows by terminal, discounting those estimated future cash flows at a 10% rate, which
approximates our cost of capital, and then comparing the discounted future cash flows to the net book value of each terminal. The impairment charge resulted from the change in the planned use of certain terminals and the abandonment of a pipeline
that supplied one terminal, thereby significantly impacting the economic viability of such terminals. Each of these factors reduced or eliminated future cash flows. The $31.9 million impairment charge for the terminals reduced the book value of the
assets to their estimated fair value.
The additional $18.2 million impairment charge for the
intangible assets represented the unamortized balance of the intangible assets. Management’s review of the market location differentials associated with those intangible assets showed that we received little or no value from those assets in the
period ended June 30, 2000.
(10) Other Assets
Other assets are as follows (in thousands):
| June 30, 2002 |
June 30, 2001 | ||||
| Prepaid transportation |
$ |
2,644 |
2,601 | ||
| Commodity trading membership |
|
1,500 |
— | ||
| Deposits and other assets |
|
119 |
376 | ||
| |
|
| |||
| $ |
4,263 |
2,977 | |||
| |
|
| |||
Prepaid transportation relates to our contractual
transportation and deficiency agreements with three interstate Product pipelines (see Note 19 of Notes to Consolidated Financial Statements).
Commodity trading membership represents the purchase price we paid to acquire two seats on the NYMEX.
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
(11) Accrued Liabilities
Accrued liabilities are as follows (in thousands):
| June 30, 2002 |
June 30, 2001 | ||||
| Interest rate swap, at fair value |
$ |
5,429 |
3,107 | ||
| Accrued environmental obligations |
|
2,329 |
700 | ||
| Accrued corporate relocation and transition |
|
2,029 |
— | ||
| Accrued lease abandonment |
|
3,110 |
— | ||
| Accrued indemnities—NORCO |
|
1,300 |
— | ||
| Accrued transportation and deficiency obligations |
|
2,839 |
1,579 | ||
| Deferred revenue—energy services |
|
1,600 |
— | ||
| Accrued expenses |
|
4,838 |
5,903 | ||
| Deposits and other accrued liabilities |
|
1,834 |
2,881 | ||
| |
|
| |||
| $ |
25,308 |
14,170 | |||
| |
|
| |||
Interest Rate
Swap. We have a $150 million notional value “periodic knock-out” swap agreement with a money center bank to offset the exposure of an increase in variable interest rates. This swap agreement expires in August
2003. The swap settles monthly and contains a knock-out provision that is activated when the one-month LIBOR is at or above 6.75%. The swap agreement provides that we pay a fixed interest rate of 5.48% on the notional amount in exchange for
receiving a variable rate based on LIBOR so long as the one-month LIBOR interest rate does not rise above 6.75%. If the one-month LIBOR rate rises above 6.75%, the swap knocks out and no payments will be received by us under the agreement until such
time as the one-month LIBOR rate declines below 6.75%. At June 30, 2002 and 2001, the one-month LIBOR rate was 1.84% and 4.08%, respectively. For the years ended June 30, 2002, 2001 and 2000, we made net payments to (received net payments from) the
money center bank of approximately $4.6 million, $(0.7) million, and $(1.0) million, respectively, which is included in interest expense (income) in the accompanying consolidated statements of operations.
The interest rate swap is carried at fair value for financial reporting purposes as it does not qualify as a hedge. As of
June 30, 2002 and 2001, the fair value of the interest rate swap agreement was a liability of $5.4 million and $3.1 million, respectively. The changes in the fair value of the interest rate swap are recorded as “Unrealized gain (loss) on
interest rate swap” in the accompanying consolidated statements of operations. For the years ended June 30, 2002, 2001 and 2000, we recognized unrealized gains (losses) of approximately $(2.3) million, $(3.6) million and $1.6 million,
respectively, for changes in the fair value of the interest rate swap.
Accrued Corporate
Relocation and Transition. During the year ended June 30, 2002, we announced to our employees that our Product supply, distribution, and marketing operations in Atlanta, Georgia would be relocated to Denver, Colorado. On
March 19, 2002, we offered approximately 72 employees the opportunity to relocate to Denver, Colorado and we informed approximately 25 employees that they would not be offered the opportunity to relocate to Denver, Colorado. Ultimately, 36 employees
chose to relocate to Denver, Colorado. Those employees are entitled to receive a transition bonus and a relocation package payable upon transfer to the Denver office. The transition bonus is being accrued over the period from date of acceptance by
the employee to the expected date of arrival in Denver, Colorado. The relocation costs are being accrued as incurred/earned by the employee. Ultimately, 36 employees chose not to relocate and those employees are entitled to receive termination
benefits upon their termination date as determined by us. The
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
special termination benefits were accrued upon receipt of the notification from the employee that they did not intend to accept the offer to relocate to Denver, Colorado. For the year ended June
30, 2002, we accrued approximately $2.1 million of benefits due to employees, of which approximately $2.0 million remains unpaid as of June 30, 2002.
| Special charge |
Amounts paid |
Accrued liability at June 30, 2002 | ||||||
| Accrued severance payable to employees not relocating to Denver, Colorado |
$ |
1,512 |
(84 |
) |
1,428 | |||
| Accrued transition benefits payable to employees relocating to Denver, Colorado |
|
501 |
— |
|
501 | |||
| Relocation costs incurred during the period |
|
100 |
— |
|
100 | |||
| Other |
|
25 |
(25 |
) |
— | |||
| |
|
|
|
| ||||
| $ |
2,138 |
(109 |
) |
2,029 | ||||
| |
|
|
|
| ||||
We expect to pay the accrued liability of
approximately $2.0 million during the year ending June 30, 2003.
Accrued Lease
Abandonment. In connection with our corporate relocation and transition, we entered into an operating lease for new office space in Denver, Colorado. The new lease was executed on April 19, 2002. Prior to June 30, 2002, we
engaged commercial real estate agents to solicit prospective tenants to sublease our existing office space in Denver, Colorado and the vacated space in Atlanta, Georgia. We expect to vacate our existing office space in Denver, Colorado during
February 2003 and the space in Atlanta, Georgia during September 2002. The accrual for the abandonment of the office leases represents the excess of the remaining lease payments subsequent to vacancy of the space by us over the estimated sublease
rentals to be received based on current market conditions. The abandonment of leasehold improvements represents the carrying amount of those assets expected to be abandoned in connection with the abandonment of the office leases. For the year ended
June 30, 2002, we charged to income approximately $4.2 million for abandonment of office leases and leasehold improvements.
| Special charge |
Amounts paid or written-off |
Accrued liability at June 30, 2002 | ||||||
| Abandonment of office leases: |
||||||||
| Denver, Colorado |
$ |
1,150 |
— |
|
1,150 | |||
| Atlanta, Georgia |
|
1,960 |
— |
|
1,960 | |||
| Abandonment of leasehold improvements: |
||||||||
| Denver, Colorado |
|
550 |
(550 |
) |
— | |||
| Atlanta, Georgia |
|
518 |
(518 |
) |
— | |||
| |
|
|
|
| ||||
| $ |
4,178 |
(1,068 |
) |
3,110 | ||||
| |
|
|
|
| ||||
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
We expect to pay the accrued liability of
approximately $3.1 million, net of estimated sublease rentals, as follows:
| Years ending June 30: |
Lease payments |
Estimated sublease rentals |
Accrued liability | |||||
| 2003 |
$ |
745 |
(97 |
) |
648 | |||
| 2004 |
|
991 |
(562 |
) |
429 | |||
| 2005 |
|
1,020 |
(565 |
) |
455 | |||
| 2006 |
|
1,045 |
(569 |
) |
476 | |||
| 2007 |
|
948 |
(508 |
) |
440 | |||
| Thereafter |
|
1,243 |
(581 |
) |
662 | |||
| |
|
|
|
| ||||
| $ |
5,992 |
(2,882 |
) |
3,110 | ||||
| |
|
|
|
| ||||
Accrued
Indemnities—NORCO. In connection with the sale of the NORCO system to Buckeye on July 31, 2001, we accrued approximately $1.3 million for the estimated costs that we expect to incur in connection with satisfying
certain covenants and undertakings set forth in the sales agreement.
Deferred
Revenue—Energy Services. During the quarter ended March 31, 2002, we renegotiated and extended through February 2005 a fixed-price supply contract with a large industrial/commercial end-user and recognized
approximately $3.0 million in net revenues attributable to our Product supply, distribution and marketing operations associated with this contract extension. The $3.0 million in net revenues represents our estimate of the fair value of the supply
contract at the date of execution. The fair value of the supply contract was net of the estimated value of the supply chain management services that we are committed to provide this customer over the term of the supply contract. The estimated value
of the supply chain management services was approximately $1.7 million based on the prices charged to industrial/commercial customers who pay for supply chain management services separately. The deferred revenue—energy services is being
amortized into net revenues attributable to our Product supply, distribution and marketing operations on a straight line basis over the remaining term of the supply contract. For the year ended June 30, 2002, we recognized approximately $0.1 million
in net revenues from the amortization of the deferred revenue – energy services.
(12) Debt
Long-term debt is as follows (in thousands):
| June 30, 2002 |
June 30, 2001 |
||||||
| Commodity margin loan |
$ |
11,312 |
|
20,000 |
| ||
| Bank credit facility |
|
187,000 |
|
80,000 |
| ||
| Senior notes |
|
— |
|
50,000 |
| ||
| |
|
|
|
| |||
| |
198,312 |
|
150,000 |
| |||
| Less current debt |
|
(11,312 |
) |
(20,000 |
) | ||
| |
|
|
|
| |||
| Long-term debt |
$ |
187,000 |
|
130,000 |
| ||
| |
|
|
|
| |||
Commodity Margin
Loan. We currently have a commodity margin loan agreement with Salomon Smith Barney that allows us to borrow up to $20.0 million to fund certain initial and variation margin
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
requirements in commodities accounts maintained by us with Salomon Smith Barney. The entire unpaid principal amount of the loan, together with accrued interest, is due and payable on demand.
Outstanding loans bear interest at the average 90-day Treasury bill rate plus 1.75% (3.46% at June 30, 2002).
Bank Credit Facility. On June 28, 2002, we executed an amended and restated Senior Secured Credit Facility (“New Facility”) with a syndication of banks. The New Facility provides for a maximum
borrowing line of credit that is the lesser of (i) $300 million and (ii) the borrowing base. The borrowing base is a function of our accounts receivable, inventory, exchanges, margin deposits, open positions of energy services and risk management
contracts, outstanding letters of credit, and outstanding indebtedness as defined in the New Facility. Borrowings under the New Facility bear interest (at our option) based on the lender’s base rate plus a specified margin, or LIBOR plus a
specified margin; the specified margins are a function of our leverage ratio (as defined). Borrowings under the New Facility are secured by substantially all of our assets. The New Facility matures June 27, 2005. The terms of the New Facility
include financial covenants relating to fixed charge coverage, current ratio, maximum leverage ratio, consolidated tangible net worth, capital expenditures, cash distributions and open inventory positions that are tested on a quarterly and annual
basis. As of June 30, 2002, we were in compliance with all covenants included in the New Facility.
In connection with the New Facility, the Company paid approximately $2.7 million in costs to execute the financing. The costs are comprised of: $2.625 million in bank fees paid to the lenders, $28,000 paid to the financial examiners,
and $100,000 paid to the attorneys that drafted the New Facility.
Our former bank credit facility
consisted of a $240 million revolving credit facility and a $45 million letter of credit facility that was due December 31, 2003. Borrowings under the former credit facility bore interest, at our option, at the lender’s alternate base rate plus
a spread, or LIBOR plus a spread, as in effect at the time of the borrowings. The average interest rate under the bank credit facility was 5.13%, 6.6%, and 8.65% for the years ended June 30, 2002, 2001 and 2000, respectively. During the year ended
June 30, 2002, we wrote-off the unamortized deferred debt issuance costs of approximately $2.7 million associated with the former bank credit facility. During the year ended June 30, 2001, we wrote-off deferred debt issuance costs of approximately
$1.0 million associated with an amendment to the former bank credit facility.
Pursuant to
our bank credit facility, we had outstanding letters of credit with third parties in the amount of $11.5 million and $12.3 million at June 30, 2002 and 2001, respectively. At June 30, 2002, all outstanding letters of credit expire within one year.
Senior Notes. In April 1997, we entered into a Master Shelf
Agreement (Senior Notes) with an institutional lender. During the year ended June 30, 1998, we sold $50 million of 7.85% due April 17, 2003 and $25 million of 7.22% Senior Notes due October 17, 2004. On January 20, 2000, we repaid $25 million of
7.85% Senior Notes with a portion of the proceeds from the sale of BPEI (see Note 2 of Notes to Consolidated Financial Statements). At June 30, 2001, the outstanding balance of the Senior Notes was $50 million. During the year ended June 30,
2001, we wrote-off deferred debt issuance costs of approximately $2.9 million associated with the prepayment of a portion of the Senior Notes. During the year ended June 30, 2001, we also recognized a prepayment penalty of approximately $1.3 million
associated with the prepayment of a portion of the Senior Notes.
On July 6, 2001, we repaid and
retired the outstanding $25 million of 7.85% Senior Notes with a portion of the proceeds from the sale of the Little Rock facilities (see Note 2 of Notes to Consolidated Financial Statements). On June 28, 2002, we repaid and retired the outstanding
$25 million of 7.22% Senior
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
Notes with a portion of the proceeds from the New Facility. At June 30, 2002, no amounts remain outstanding on the Senior Notes. During the year ended June 30, 2002, we wrote-off deferred debt
issuance costs of approximately $0.3 million associated with the prepayment of the Senior Notes. During the year ended June 30, 2002, we also recognized a prepayment penalty of approximately $1.9 million associated with the prepayment of the Senior
Notes.
Maturities of long-term debt are as follows (in thousands):
| Years ending: |
|||
| June 30, 2003 |
$ |
11,312 | |
| June 30, 2004 |
|
— | |
| June 30, 2005 |
|
187,000 | |
| |
| ||
| $ |
198,312 | ||
| |
|
(13) Disclosures About Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of financial
instruments at June 30, 2002 and 2001.
Cash and Cash Equivalents, Trade Receivables and Trade
Accounts Payable. The carrying amount approximates fair value because of the short-term maturity of these instruments.
Debt. The carrying values of the commodity margin loan and bank credit facility approximate fair value since they bear interest at current market interest rates. The
carrying value of the Senior Notes approximates fair value since the interest rates approximate the current market rates for similar debt instruments.
(14) Preferred Stock
At June 30, 2002 and 2001, we
have authorized the issuance of up to 2,000,000 shares of preferred stock. Preferred stock is as follows (in thousands):
| June 30, 2002 |
June 30, 2001 | ||||
| Series A Convertible Preferred stock, par value $0.01 per share, 250,000 shares authorized, 24,421 shares issued and
outstanding at June 30, 2002, 174,825 shares issued and outstanding at June 30, 2001, liquidation preference of $24,421 and $174,825, respectively |
$ |
24,421 |
174,825 | ||
| |
|
| |||
| Series B Redeemable Convertible Preferred stock, par value $0.01 per share, 100,000 shares authorized, 72,890 shares
issued and outstanding at June 30, 2002, liquidation preference of $72,890 |
$ |
80,939 |
— | ||
| |
|
| |||
On March 25, 1999 and March 30, 1999, we closed a
private placement of $170.1 million of $1,000 Series A Convertible Preferred Stock Units (the “Units”). Each Unit consists of one share of 5% convertible preferred stock (“Series A Convertible Preferred Stock”), convertible at
any time by the holder into common stock at $15 per share, and 66.67 warrants, each warrant exercisable to purchase six-tenths of a share of
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
common stock at $14 per share. Dividends are cumulative and payable quarterly. The dividends are payable, at our option, in cash or additional shares of Series A Convertible Preferred Stock. If
the dividends are paid-in-kind with additional shares of Series A Convertible Preferred Stock, the number of additional shares issued in lieu of a cash payment is determined by multiplying the cash dividend that would have been paid by 110%. During
the year ended June 30, 2000, cash dividend payments were $8.5 million. During the year ended June 30, 2001, we elected to pay-in-kind a portion of the preferred dividends. For the year ended June 30, 2001, cash dividend payments were $4.3 million
and paid-in-kind dividends were $4.7 million. For the year ended June 30, 2002, paid-in-kind dividends were approximately $9.8 million.
On June 28, 2002, we entered into an agreement with the holders of the Series A Convertible Preferred Stock (the “Preferred Stock Recapitalization Agreement”) to redeem a portion of the
Series A Convertible Preferred Stock and warrants in exchange for cash, shares of common stock, and shares of a newly created and designated preferred stock (“Series B Redeemable Convertible Preferred Stock”).
The Preferred Stock Recapitalization Agreement resulted in the redemption of 157,715 shares of Series A Convertible
Preferred Stock and warrants to purchase 9,841,493 shares of common stock in exchange for the (i) issuance of 72,890 shares of Series B Redeemable Convertible Preferred Stock with a fair value of approximately $80.9 million, (ii) issuance
of 11,902,705 shares of common stock with a fair value of approximately $59.5 million, and (iii) a cash payment of $21.3 million. We retired the 157,715 shares of Series A Convertible Preferred Stock and associated warrants. The fair value of
the consideration paid to the holders of the Series A Convertible Preferred Stock and associated warrants was in excess of the financial statement carrying amount of the Series A Convertible Preferred Stock that was redeemed. That excess of
approximately $1.5 million has been treated in a manner similar to preferred stock dividends in the accompanying consolidated financial statements.
At June 30, 2002, there are 24,421 shares of Series A Convertible Preferred Stock that remain outstanding. We may redeem all, but not less than all, of the
then outstanding shares of the Series A Convertible Preferred Stock on December 31, 2003 at the liquidation value of $1,000 per share plus any accrued but unpaid dividends thereon through the redemption date (the “Mandatory Redemption
Price”). The Mandatory Redemption Price shall be paid, at our election, in cash or shares of common stock, or any combination thereof, subject to limitations on the total number of common shares permitted to be used in the exchange and issued
to any shareholder. For purposes of calculating the number of shares of common stock to be received, each such share of common stock shall be valued at 90 percent of the average market price for the common stock for the 20 consecutive business days
prior to the redemption date. If the Series A Convertible Preferred Stock remains outstanding after December 31, 2003, the dividend rate will increase to an annual rate of 16%. We may call the Series A Convertible Preferred Stock for redemption if
the market price of our common stock is greater than 175% of the conversion price at the date of the call.
The Series B Redeemable Convertible Preferred Stock has a liquidation value of $1,000 per share, bears dividends at the rate of 6% per annum of the liquidation value, and is mandatorily redeemable between June 30, 2007 and December
31, 2007 for shares of common stock and/or cash at our option, subject to limitations on the total number of common shares permitted to be used in the exchange and issued to any shareholder. Dividends are cumulative and payable quarterly. The
dividends are payable in cash, unless precluded by contract or the New Facility, in which case dividends are payable in additional shares of Series B Redeemable Convertible Preferred Stock. The Series B Redeemable Convertible Preferred Stock may be
put to us, at the option of the holder, for cash equal to the greater of its liquidation value or conversion value upon the future occurrence of a fundamental change (as defined). We may call the outstanding shares of Series B Redeemable Convertible
Preferred Stock after June 30, 2005 if certain specified conditions are met. The Series B Redeemable Convertible Preferred Stock is convertible, at the
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Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
option of the holder, into common stock at $6.60 per share, subject to adjustment upon the occurrence of specified future events. The holders of the Series B Redeemable Convertible Preferred
Stock have the right to vote on all matters (except the election of directors) with the holders of the common stock and the Series A Convertible Preferred Stock (voting collectively as a single class).
At June 30, 2002, there are 72,890 shares of Series B Redeemable Convertible Preferred Stock outstanding. The Series B
Redeemable Convertible Preferred Stock initially was recorded at its estimated fair value of approximately $80.9 million. The estimated fair value was determined by adding together (i) the present value of the expected dividend payments and
mandatory redemption value discounted at a risk-adjusted rate of approximately 15% and (ii) the value of the embedded conversion option using the Black-Scholes model with the following assumptions: exercise price of $6.60 per share, volatility
factor of 70%, contractual life of 5 years, no dividend yield, and a risk-free rate of 3.6%. In subsequent periods, the initial carrying amount of the Series B Redeemable Convertible Preferred Stock will be decreased ratably over its 5-year term
until it equals its liquidation value of approximately $72.9 million with an equal reduction in the amount of preferred stock dividends recorded for financial reporting purposes.
(15) Common Stock
At June 30, 2002 and 2001, we are authorized to issue up to 80,000,000 shares of common stock with a par value of $0.01 per share. In connection with the Preferred Stock Recapitalization Agreement, we repurchased approximately 4.1
million shares of our common stock from an institutional holder of the Series A Convertible Preferred Stock for cash consideration of approximately $20.4 million. At June 30, 2002 and 2001, there are 39,942,658 shares and 31,834,669 shares
issued and outstanding, respectively. Our New Facility and certificate of designations of our preferred stock contain restrictions on the payment of dividends on our common stock.
We have a restricted stock plan that provides for awards of common stock to certain key employees, subject to forfeiture if employment terminates prior to
the vesting dates. The market value of shares awarded under the plan is recorded in common stockholders’ equity as deferred compensation. Amortization of deferred compensation of approximately $1.5 million, $1.3 million and $0.4 million is
included in selling, general and administrative expense for the years ended June 30, 2002, 2001 and 2000, respectively.
During the year ended June 30, 2001, 261,280 shares of restricted common stock were issued to employees in exchange for the cancellation of 1,681,300 stock options with exercise prices ranging from $11.00 to $17.25 per share
that had been granted to employees in prior years. Information about restricted common stock activity for the years ended June 30, 2002, 2001 and 2000 is as follows:
| Total shares |
Vested shares |
Unvested shares |
|||||||
| Outstanding at June 30, 1999 |
68,000 |
|
68,000 |
|
— |
| |||
| Granted |
227,500 |
|
— |
|
227,500 |
| |||
| |
|
|
|
|
| ||||
| Outstanding at June 30, 2000 |
295,500 |
|
68,000 |
|
227,500 |
| |||
| Granted |
512,680 |
|
— |
|
512,680 |
| |||
| Cancelled |
(29,020 |
) |
— |
|
(29,020 |
) | |||
| Repurchased |
(201 |
) |
(201 |
) |
— |
| |||
| Vested |
— |
|
22,750 |
|
(22,750 |
) | |||
| |
|
|
|
|
| ||||
| Outstanding at June 30, 2001 |
778,959 |
|
90,549 |
|
688,410 |
| |||
| Granted |
420,500 |
|
— |
|
420,500 |
| |||
| Cancelled |
(104,170 |
) |
— |
|
(104,170 |
) | |||
| Repurchased |
(20,573 |
) |
(20,573 |
) |
— |
| |||
| Vested |
— |
|
90,772 |
|
(90,772 |
) | |||
| |
|
|
|
|
| ||||
| Outstanding at June 30, 2002 |
1,074,716 |
|
160,748 |
|
913,968 |
| |||
| |
|
|
|
|
|
67
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
(16) Stock Options
We have three stock option plans (the “1991 Plan”, the “1995 Plan” and the “1997 Plan”)
under which stock options have been granted to employees. Options granted under the 1991 Plan and the 1997 Plan expire no later than ten years from the date of grant and options under the 1995 Plan expire no later than seven years from the date of
grant. At June 30, 2002, options granted under the 1991 Plan and 1995 Plan and those granted through July 1998 under the 1997 Plan have vested. Options granted subsequent to March 1999 under the 1997 Plan vest 10% after the end of the first year,
20% after the end of the second year, 30% after the end of the third year, and 40% after the end of the fourth year. Information about stock option activity for the years ended June 30, 2002, 2001 and 2000 is as follows:
| 1991 Plan |
1995 Plan |
1997 Plan | |||||||||||||
| Shares |
Weighted average exercise price |
Shares |
Weighted average exercise price |
Shares |
Weighted average exercise price | ||||||||||
| Outstanding at June 30, 1999 |
11,000 |
|
6.10 |
731,950 |
|
3.96 |
2,743,400 |
|
12.71 | ||||||
| Granted |
— |
|
— |
— |
|
— |
733,000 |
|
7.91 | ||||||
| Cancelled |
— |
|
— |
(1,000 |
) |
5.50 |
(577,160 |
) |
13.06 | ||||||
| Exercised |
(8,000 |
) |
6.10 |
(14,000 |
) |
4.30 |
(2,000 |
) |
13.50 | ||||||
| |
|
|
|
|
|
|
|
| |||||||
| Outstanding at June 30, 2000 |
3,000 |
|
6.10 |
716,950 |
|
3.95 |
2,897,240 |
|
11.42 | ||||||
| Granted |
— |
|
— |
— |
|
— |
750,000 |
|
3.75 | ||||||
| Cancelled |
(3,000 |
) |
6.10 |
(46,500 |
) |
5.38 |
(2,478,410 |
) |
12.22 | ||||||
| Exercised |
— |
|
— |
(372,000 |
) |
2.70 |
— |
|
— | ||||||
| |
|
|
|
|
|
|
|
| |||||||
| Outstanding at June 30, 2001 |
— |
|
— |
298,450 |
|
5.28 |
1,168,830 |
|
4.81 | ||||||
| Granted |
— |
|
— |
— |
|
— |
75,000 |
|
5.05 | ||||||
| Cancelled |
— |
|
— |
(35,000 |
) |
5.50 |
(174,050 |
) |
6.68 | ||||||
| Exercised |
— |
|
— |
(33,000 |
) |
3.50 |
(7,000 |
) |
5.13 | ||||||
| |
|
|
|
|
|
|
|
| |||||||
| Outstanding at June 30, 2002 |
— |
|
— |
230,450 |
|
5.50 |
1,062,780 |
|
4.52 | ||||||
| |
|
|
|
|
|
|
|
| |||||||
| Exercisable at June 30, 2002 |
— |
|
— |
230,450 |
|
5.50 |
178,170 |
|
5.31 | ||||||
| |
|
|
|
|
|
|
|
| |||||||
Information about stock options outstanding at June
30, 2002 is as follows:
| Options exercisable | |||||||||||||
| Range of exercise prices |
Number outstanding |
Weighted average remaining life in years |
Weighted average exercise prices |
Number exercisable |
Weighted average exercise prices | ||||||||
| 1995 Plan |
$ |
5.50 |
230,450 |
0.7 |
5.50 |
230,450 |
5.50 | ||||||
| 1997 Plan |
|
3.75—7.25 11.00—13.50 15.00—17.25 |
1,044,900 16,880 1,000 |
8.5 6.4 5.2 |
4.40 11.44 17.25 |
165,650 11,520 1,000 |
4.80 11.65 17.25 | ||||||
| |
|
||||||||||||
| 1,293,230 |
408,620 |
||||||||||||
| |
|
||||||||||||
We account for our employee stock option plans and
restricted stock awards using the intrinsic value method pursuant to APB Opinion No. 25, Accounting for Stock Issued to Employees. We recognize deferred compensation on the date of grant if the quoted market price of the underlying common
stock exceeds the exercise price (zero exercise price in the case of an award of restricted common stock). Accordingly, no compensation cost has been recognized for the granting of stock options to employees because the exercise price was equal to
the quoted market price of the underlying common stock on the date of grant. If
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
compensation cost for our three stock-based compensation plans had been determined based on the fair value at the grant dates for awards under those plans pursuant to SFAS 123, Accounting for
Stock-Based Compensation, our net earnings and earnings per common share would have been reduced to the pro forma amounts indicated below (in thousands, except for per share amounts):
| Years ended June 30, |
|||||||||||
| 2002 |
2001 |
2000 |
|||||||||
| Net earnings (loss) attributable to common stockholders: |
|||||||||||
| As reported |
$ |
(2,793 |
) |
$ |
2,375 |
$ |
(46,443 |
) | |||
| Pro forma |
$ |
(3,003 |
) |
$ |
2,249 |
$ |
(47,721 |
) | |||
| Earnings (loss) per common share |
|||||||||||
| As reported |
|||||||||||
| Basic |
$ |
(0.09 |
) |
$ |
0.08 |
$ |
(1.52 |
) | |||
| Diluted |
$ |
(0.09 |
) |
$ |
0.08 |
$ |
(1.52 |
) | |||
| Pro forma |
|||||||||||
| Basic |
$ |
(0.10 |
) |
$ |
0.07 |
$ |
(1.56 |
) | |||
| Diluted |
$ |
(0.10 |
) |
$ |
0.07 |
$ |
(1.56 |
) | |||
The weighted average fair value at grant dates for
options granted during the years ended June 30, 2002, 2001 and 2000 was $3.08, $2.12 and $3.16, respectively. The primary assumptions used to estimate the fair value of options granted on the date of grant using the Black-Scholes option-pricing
model during the years ended June 30, 2002, 2001 and 2000 were as follows: no dividend yield, expected volatility of 79%, 61% and 36%, risk-free rates of 4.49%, 4.95% and 5.6%, and expected lives of 4 years, 5 years, and 7 years, respectively.
(17) Employee Benefit Plan
We have established a 401(k) retirement savings plan for all employees. The plan allows participants to contribute a percentage of their compensation
ranging from 1% to a maximum of 15%, subject to the maximum salary deferral allowed by the Internal Revenue Service, with our making discretionary contributions as determined by management based upon our financial performance. Employees vest 25% per
year in our discretionary contributions. Our discretionary contributions for the years ended June 30, 2002, 2001 and 2000 were approximately $0.5 million, $0.6 million and $0.8 million, respectively.
(18) Income Taxes
Income tax expense (benefit) consists of the following (in thousands):
| Years ended June 30, |
||||||||||
| 2002 |
2001 |
2000 |
||||||||
| Current: |
||||||||||
| Federal income taxes |
$ |
(240 |
) |
(288 |
) |
— |
| |||
| State income taxes |
|
643 |
|
735 |
|
272 |
| |||
| |
|
|
|
|
|
| ||||
| Current income taxes |
|
403 |
|
447 |
|
272 |
| |||
| |
|
|
|
|
|
| ||||
| Deferred: |
||||||||||
| Federal income taxes |
|
4,483 |
|
5,500 |
|
(17,393 |
) | |||
| State income taxes |
|
579 |
|
719 |
|
(2,046 |
) | |||
| |
|
|
|
|
|
| ||||
| Deferred income taxes |
|
5,062 |
|
6,219 |
|
(19,439 |
) | |||
| |
|
|
|
|
|
| ||||
| Income tax expense (benefit) |
$ |
5,465 |
|
6,666 |
|
(19,167 |
) | |||
| |
|
|
|
|
|
| ||||
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
Income tax expense (benefit) differs from the amount
computed by applying the federal corporate income tax rate of 35% to pretax earnings as a result of the following (in thousands):
| Years ended June 30, |
||||||||||
| 2002 |
2001 |
2000 |
||||||||
| Computed “expected” tax expense (benefit) |
$ |
4,908 |
|
6,458 |
|
(19,415 |
) | |||
| Increase (reduction) in income taxes resulting from: |
||||||||||
| Adjustment of prior year’s cumulative temporary differences |
|
(273 |
) |
(331 |
) |
1,858 |
| |||
| State income taxes, net of federal income tax benefit |
|
387 |
|
945 |
|
(1,171 |
) | |||
| Other, net |
|
443 |
|
(406 |
) |
(439 |
) | |||
| |
|
|
|
|
|
| ||||
| Income tax expense (benefit) |
$ |
5,465 |
|
6,666 |
|
(19,167 |
) | |||
| |
|
|
|
|
|
| ||||
The tax effects of temporary differences that give
rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows (in thousands):
| June 30, 2002 |
June 30, 2001 |
||||||
| Deferred tax assets: |
|||||||
| Net operating loss carry forwards |
$ |
31,224 |
|
44,386 |
| ||
| Allowance for doubtful accounts |
|
475 |
|
399 |
| ||
| Accrual for corporate relocation and transition plan |
|
1,953 |
|
165 |
| ||
| Other non-deductible accruals |
|
2,920 |
|
1,102 |
| ||
| Amortization of debt costs, principally due to differences in amortization methods |
|
1,327 |
|
831 |
| ||
| Intangible assets, principally due to differences in amortization methods and impairment allowances |
|
5,417 |
|
6,448 |
| ||
| Deferred compensation |
|
925 |
|
697 |
| ||
| Inventories—minimum volumes, principally due to lower of cost or market write-downs |
|
6,047 |
|
— |
| ||
| Accrued environmental obligations |
|
710 |
|
266 |
| ||
| Alternative minimum tax credit carry forwards |
|
59 |
|
335 |
| ||
| |
|
|
|
| |||
| Deferred tax assets |
|
51,057 |
|
54,629 |
| ||
| |
|
|
|
| |||
| Deferred tax liabilities: |
|||||||
| Plant and equipment, principally due to differences in depreciation methods and impairment allowances |
|
(43,175 |
) |
(41,431 |
) | ||
| Investments in affiliated companies, principally due to undistributed earnings |
|
— |
|
(254 |
) | ||
| |
|
|
|
| |||
| Deferred tax liabilities |
|
(43,175 |
) |
(41,685 |
) | ||
| |
|
|
|
| |||
| Net deferred tax assets |
$ |
7,882 |
|
12,944 |
| ||
| |
|
|
|
| |||
In assessing the realizability of deferred tax
assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income
during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment.
Based upon projections for future taxable income over the periods which the deferred tax assets are deductible,
management believes the “more likely than not” criteria has been satisfied as of June 30, 2002 and 2001, and that the benefits of future deductible differences will be realized.
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
At June 30, 2002, we have aggregate net operating
loss carry forwards for federal income tax purposes of approximately $81 million which were available to offset future federal taxable income, if any, through 2021.
(19) Commitments and Contingencies
Transportation and Deficiency Agreements. In connection with our June 30, 2001 sale of the two Product distribution facilities in Little Rock, Arkansas, we are potentially liable for payments of up to
$725,000 per year for a five-year period through June 30, 2006. The potential liability for each year is based on the actual throughput volumes of the facility for each year as compared to the contractual thresholds of 20,000 and 32,500 barrels per
day (“BPD”). If actual volumes exceed 32,500 BPD, we will not be obligated to pay any of the $725,000 for that given year. If actual volumes are between 20,000 and 32,500 BPD, we will be obligated to pay a prorated portion of the
$725,000 for that given year. If actual volumes are less than 20,000 BPD, we are obligated to pay the entire $725,000 for that given year. For the year ended June 30, 2002, our actual volumes were between 20,000 and 32,500 BPD. As a result, we
recognized an accrued liability of approximately $1.0 million with an offsetting reduction in net revenues attributable to our Product supply, distribution and marketing operations (see Note 11 of Notes to Consolidated Financial Statements). That
accrued liability represents our estimate of the future payments we expect to pay for the shortfall in our current year volumes and our estimated shortfall in volumes for the remainder of the term of the agreement.
We also are subject to three transportation and deficiency agreements (“T&D’s”) with three separate
Product interstate pipeline companies. Each agreement calls for guaranteed minimum shipping volumes over the term of the agreements. If actual volumes shipped are less than the guaranteed minimum volumes, we must make payment to the counterparty for
any shortfall at the contracted pipeline tariff. Such payments are accounted for as prepaid transportation, since we have a contractual timeframe, after the end of the term of the T&D, to apply the amounts to charges for using the interstate
pipeline. We monitor the actual volumes shipped against our obligations to determine if the T&D payments made will ultimately be recovered. In order to do this, we have to estimate our future shipping volumes.
During the year ended June 30, 2001, we made payments of approximately $3.2 million pursuant to the T&D agreements
because our actual volumes shipped during that year were less than the guaranteed minimum volumes for that year. We also recognized an accrued liability of approximately $1.6 million representing our estimate of the future payments we expect to pay
for the estimated shortfall in volumes for the remainder of the terms of the T&D agreements. At June 30, 2001, we included approximately $2.6 million of prepaid transportation in other assets (see Note 10 of Notes to Consolidated Financial
Statements) and we reduced net revenues attributable to our Product supply, distribution and marketing operations by approximately $2.2 million.
During the year ended June 30, 2002, we made payments of approximately $0.4 million pursuant to the T&D agreements because our actual volumes shipped during that year were less than the guaranteed
minimum volumes for that year. We also recognized an additional accrued liability of approximately $0.2 million representing a change in our estimate of the future payments we expect to pay for the estimated shortfall in volumes for the
remainder of the terms of the T&D agreements. For the year ended June 30, 2002, we reduced net revenues attributable to our Product supply, distribution and marketing operations by approximately $0.6 million. At June 30, 2002, prepaid
transportation of approximately $2.6 million remains in other assets and our accrued liability, representing our estimate of the future payments we expect to pay
71
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
for the estimated shortfall in volumes for the remainder of the terms of the T&D agreements, is approximately $1.8 million.
Operating Leases. On April 19, 2002, we executed a 10-year non-cancelable operating lease for new office space to accommodate
our corporate headquarters. We anticipate the lease will commence October 1, 2002 and March 1, 2003 with respect to approximately one-half of the total leased square footage, respectively. We also lease property and equipment under non-cancelable
operating leases that expire through January 2007, including ground at our Brownsville, Texas facility, pipeline capacity on an intrastate pipeline, and technology-related equipment. At June 30, 2002, future minimum lease payments under these
non-cancelable operating leases are as follows (in thousands):
| Years ending June 30: |
Office space |
Property and equipment | ||||
| 2003 |
$ |
— |
$ |
1,304 | ||
| 2004 |
|
524 |
|
1,294 | ||
| 2005 |
|
968 |
|
1,141 | ||
| 2006 |
|
968 |
|
324 | ||
| 2007 |
|
1,015 |
|
162 | ||
| Thereafter |
|
5,788 |
|
— | ||
| |
|
|
| |||
| $ |
9,263 |
$ |
4,225 | |||
| |
|
|
| |||
We also will continue to lease office space at our
existing locations until we vacate those premises to move to our new corporate headquarters. We anticipate that we will occupy the Denver, Colorado office space until March 1, 2003, one-half of the Atlanta, Georgia office space until October 1,
2002, and the remainder of the Atlanta, Georgia space until June 2010 when the lease expires. At June 30, 2002, future minimum lease payments under these non-cancelable operating lease agreements through the expected date of vacancy by us are as
follows (in thousands):
| Years ending June 30: |
|||
| 2003 |
$ |
1,143 | |
| 2004 |
|
407 | |
| 2005 |
|
415 | |
| 2006 |
|
423 | |
| 2007 |
|
432 | |
| Thereafter |
|
1,348 | |
| |
| ||
| $ |
4,168 | ||
| |
| ||
Rental expense under operating leases was $2.8
million, $2.9 million, and $2.3 million for the years ended June 30, 2002, 2001 and 2000, respectively.
(20) Litigation
We have been named as a defendant
in various lawsuits and a party to various other legal proceedings, in the ordinary course of business, some of which are covered in whole or in part by insurance. We believe that the outcome of such lawsuits and other proceedings will not
individually or in the aggregate have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
72
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
(21) Earnings Per Share
The following tables reconcile the computation of basic EPS and diluted EPS (in thousands, except per share amounts).
| Years ended June 30, |
||||||||||
| 2002 |
2001 |
2000 |
||||||||
| Net earnings (loss) |
$ |
8,558 |
|
11,338 |
|
(37,937 |
) | |||
| Preferred stock dividends |
|
(11,351 |
) |
(8,963 |
) |
(8,506 |
) | |||
| |
|
|
|
|
|
| ||||
| Net earnings (loss) attributable to common stockholders for basic and diluted EPS |
$ |
(2,793 |
) |
2,375 |
|
(46,443 |
) | |||
| |
|
|
|
|
|
| ||||
| Basic weighted average shares |
|
31,267 |
|
30,879 |
|
30,491 |
| |||
| Effect of dilutive securities: |
||||||||||
| Stock options |
|
— |
|
100 |
|
— |
| |||
| Stock purchase warrants |
|
— |
|
24 |
|
— |
| |||
| |
|
|
|
|
|
| ||||
| Diluted weighted average shares |
|
31,267 |
|
31,003 |
|
30,491 |
| |||
| |
|
|
|
|
|
| ||||
| Earnings (loss) per shares: |
||||||||||
| Basic |
$ |
(0.09 |
) |
0.08 |
|
(1.52 |
) | |||
| |
|
|
|
|
|
| ||||
| Diluted |
$ |
(0.09 |
) |
0.08 |
|
(1.52 |
) | |||
| |
|
|
|
|
|
| ||||
We exclude potentially dilutive securities from our
computation of diluted earnings per share when their effect would be anti-dilutive. The following securities were excluded from the earnings per share computation, as their inclusion would have been anti-dilutive:
| June 30, 2002 |
June 30, 2001 |
June 30, 2000 | ||||
| Restricted common stock subject to continuing vesting requirements |
913,968 |
688,410 |
227,500 | |||
| Common stock issuable upon exercise of stock options |
1,293,230 |
688,280 |
3,617,190 | |||
| Common stock issuable upon exercise of stock purchase warrants |
900,045 |
6,804,940 |
7,053,626 | |||
| Common stock issuable upon conversion of: |
||||||
| Series A Convertible Preferred Stock |
1,628,083 |
11,655,000 |
11,341,000 | |||
| Series B Redeemable Convertible Preferred Stock |
11,043,939 |
— |
— | |||
| |
|
| ||||
| 15,779,265 |
19,836,630 |
22,239,316 | ||||
| |
|
|
For the year ended June 30, 2001, shares of
restricted common stock subject to continuing vesting requirements were excluded from the computation of earnings per share because the associated unamortized deferred compensation exceeded the average quoted market price of our common stock during
those periods. For the year ended June 30, 2001, stock options and stock purchase warrants were excluded from the computation of earnings per share because their exercise prices exceeded the average quoted market
73
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TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
price of our common stock during those periods. For the years ended June 30, 2002 and 2000, all potentially dilutive securities were excluded because we reported a net loss for those years. For
the years ended June 30, 2002, 2001 and 2000, the stock options had weighted average exercise prices of $4.69, $6.24 and $9.94 per share, respectively, the stock purchase warrants had weighted average exercise prices of $14.00, $14.00 and
$13.63 per share, respectively, the Series A Convertible Preferred Stock had a conversion price of $15.00, and the Series B Redeemable Convertible Preferred Stock had a conversion price of $6.60.
(22) Concentration of Credit Risk and Trade Accounts Receivable
Our primary market areas are located in the Northeast, Midwest and Southeast regions of the United States. We have a concentration of trade receivable and
exchange receivable balances due from major integrated oil companies, independent oil companies, other wholesalers, waste management companies and transportation companies. These concentrations of customers may affect our overall credit risk in that
the customers may be similarly affected by changes in economic, regulatory or other factors. Our customers’ historical and future credit positions are analyzed prior to extending credit. We manage our exposure to credit risk through credit
analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions we may utilize letters of credit, prepayments and guarantees. We maintain allowances for potentially uncollectible accounts receivable.
Trade accounts receivable, net consists of the following (in thousands):
| June 30, 2002 |
June 30, 2001 |
||||||
| Trade accounts receivable |
$ |
174,986 |
|
80,100 |
| ||
| Less allowance for doubtful accounts |
|
(1,250 |
) |
(1,050 |
) | ||
| |
|
|
|
| |||
| $ |
173,736 |
|
79,050 |
| |||
| |
|
|
|
| |||
(23) Business Segments
We provide a broad range of integrated supply, distribution, marketing, terminal storage and transportation services to
refiners, distributors, marketers and industrial end-users of products, chemicals, crude oil and other bulk liquids (“Products”) in the midstream sector of the petroleum and chemical industries and in the upstream NGL sector prior to the
sale of BPEI. We conduct business in the following segments:
· |
Product supply, distribution, and marketing—consists of services for the supply and distribution of Products through Product exchanges, and bulk purchases
and sales in the physical and derivative markets, and the marketing of Products to retail, wholesale and industrial customers at truck terminal rack locations, and providing related value-added fuel procurement and management services.
|
· |
Terminals and pipelines—consists of an extensive terminal and pipeline infrastructure that handles Products with transportation connections via pipelines,
barges, rail cars and trucks to our facilities or to third-party facilities with an emphasis on transportation connections primarily through the Colonial, Plantation, Texas Eastern, Explorer and Williams pipeline systems.
|
· |
Natural gas services—consisted of services provided through the ownership and operation of natural gas pipeline gathering systems, processing plants and
related facilities for the gathering, processing, fractionating and reselling of natural gas and natural gas liquids. This segment was divested effective December 31, 1999. |
· |
Corporate—consists of our investments in non-controlled business ventures and general corporate items that are not allocated to specific segments (e.g.,
financing costs and income taxes). |
74
Table of Contents
TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
Information about our business segments is summarized below (in thousands):
| Year ended June 30, 2002 |
|||||||||||||||
| Product supply, distribution and marketing |
Terminals and pipelines |
Natural gas services |
Corporate |
Total consolidated |
|||||||||||
| Revenues from external customers |
$ |
68,747 |
|
29,732 |
|
— |
— |
|
98,479 |
| |||||
| Inter-segment revenues |
|
— |
|
33,654 |
|
— |
— |
|
33,654 |
| |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Revenues, net |
|
68,747 |
|
63,386 |
|
— |
— |
|
132,133 |
| |||||
| Lower of cost or market write- downs on minimum inventories |
|
(12,963 |
) |
— |
|
— |
— |
|
(12,963 |
) | |||||
| Direct operating costs and expenses |
|
— |
|
(27,668 |
) |
— |
— |
|
(27,668 |
) | |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Net operating margins |
|
55,784 |
|
35,718 |
|
— |
— |
|
91,502 |
| |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Selling, general and administrative |
|
(20,882 |
) |
(8,038 |
) |
— |
(6,291 |
) |
(35,211 |
) | |||||
| Depreciation and amortization |
|
(330 |
) |
(14,365 |
) |
— |
(1,861 |
) |
(16,556 |
) | |||||
| Corporate relocation and transition |
|
(4,597 |
) |
— |
|
— |
(1,719 |
) |
(6,316 |
) | |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| |
(25,209 |
) |
(22,403 |
) |
— |
(9,871 |
) |
(58,083 |
) | ||||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Operating income (loss) |
$ |
29,975 |
|
13,315 |
|
— |
(9,871 |
) |
33,419 |
| |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Identifiable assets |
$ |
455,115 |
|
253,417 |
|
— |
40,437 |
|
748,969 |
| |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Capital expenditures |
$ |
62 |
|
13,592 |
|
— |
2,155 |
|
15,809 |
| |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Year ended June 30, 2001 |
|||||||||||||||
| Product supply, distribution and marketing |
Terminals and pipelines |
Natural gas services |
Corporate |
Total consolidated |
|||||||||||
| Revenues from external customers |
$ |
46,318 |
|
40,646 |
|
— |
— |
|
86,964 |
| |||||
| Inter-segment revenues |
|
— |
|
41,659 |
|
— |
— |
|
41,659 |
| |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Revenues, net |
|
46,318 |
|
82,305 |
|
— |
— |
|
128,623 |
| |||||
| Lower of cost or market write- downs on minimum inventories |
|
(18,318 |
) |
— |
|
— |
— |
|
(18,318 |
) | |||||
| Direct operating costs and expenses |
|
— |
|
(36,415 |
) |
— |
— |
|
(36,415 |
) | |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Net operating margins |
|
28,000 |
|
45,890 |
|
— |
— |
|
73,890 |
| |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Selling, general and administrative |
|
(19,661 |
) |
(7,648 |
) |
— |
(6,763 |
) |
(34,072 |
) | |||||
| Depreciation and amortization |
|
(24 |
) |
(17,351 |
) |
— |
(2,135 |
) |
(19,510 |
) | |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| |
(19,685 |
) |
(24,999 |
) |
— |
(8,898 |
) |
(53,582 |
) | ||||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Operating income (loss) |
$ |
8,315 |
|
20,891 |
|
— |
(8,898 |
) |
20,308 |
| |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Identifiable assets |
$ |
308,736 |
|
332,717 |
|
— |
81,076 |
|
722,529 |
| |||||
| |
|
|
|
|
|
|
|
|
| ||||||
| Capital expenditures |
$ |
1,222 |
|
8,585 |
|
— |
1,735 |
|
11,542 |
| |||||
| |
|
|
|
|
|
|
|
|
| ||||||
75
Table of Contents
TRANSMONTAIGNE INC. AND SUBSIDIARIES
Notes To Consolidated Financial Statements—(Continued)
Years ended June 30, 2002, 2001 and 2000
| Year ended June 30, 2000 |
||||||||||||||||
| Product supply, distribution and marketing |
Terminals and pipelines |
Natural gas services |
Corporate |
Total consolidated |
||||||||||||
| Revenues from external customers |
$ |
18,853 |
|
16,522 |
|
18,249 |
|
— |
|
53,624 |
| |||||
| Inter-segment revenues |
|
— |
|
62,000 |
|
— |
|
— |
|
62,000 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Revenues, net |
|
18,853 |
|
78,522 |
|
18,249 |
|
— |
|
115,624 |
| |||||
| Direct operating costs and expenses |
|
— |
|
(34,268 |
) |
(7,759 |
) |
— |
|
(42,027 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Net operating margins |
|
18,853 |
|
44,254 |
|
10,490 |
|
— |
|
73,597 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Selling, general and administrative |
|
(19,468 |
) |
(8,157 |
) |
(1,923 |
) |
(12,132 |
) |
(41,680 |
) | |||||
| Depreciation and amortization |
|
(519 |
) |
(16,139 |
) |
(3,141 |
) |
(2,545 |
) |
(22,344 |
) | |||||
| Impairment of long-lived assets |
|
(18,236 |
) |
(31,900 |
) |
— |
|
— |
|
(50,136 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| |
(38,223 |
) |
(56,196 |
) |
(5,064 |
) |
(14,677 |
) |
(114,160 |
) | ||||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Operating income (loss) |
$ |
(19,370 |
) |
(11,942 |
) |
5,426 |
|
(14,677 |
) |
(40,563 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Identifiable assets |
$ |
375,271 |
|
318,611 |
|
— |
|
140,690 |
|
834,572 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Capital expenditures |
$ |
— |
|
32,954 |
|
24,264 |
|
4,046 |
|
61,264 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
(24) Financial Results by Quarter (Unaudited)
(in thousands, except per share amounts)
| Three months ended |
Year ended June 30,
2002 |
|||||||||||||||
| September 30, 2001 |
December 31, 2001
|
March 31, 2002 |
June 30, 2002 |
|||||||||||||
| Revenues, net |
$ |
43,115 |
|
28,904 |
|
35,870 |
|
24,244 |
|
132,133 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Net operating margins |
$ |
35,091 |
|
10,128 |
|
29,702 |
|
16,581 |
|
91,502 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Net earnings (loss) attributable to common stockholders |
$ |
7,227 |
|
(5,377 |
) |
6,265 |
|
(10,908 |
) |
(2,793 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Earnings (loss) per common share |
||||||||||||||||
| Basic |
$ |
0.23 |
|
(0.17 |
) |
0.19 |
|
(0.35 |
) |
(0.09 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Diluted |
$ |
0.22 |
|
(0.17 |
) |
0.19 |
|
(0.35 |
) |
(0.09 |
) | |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Three months ended |
Year ended June 30,
2001 |
|||||||||||||||
| September 30, 2000 |
December 31, 2000
|
March 31, 2001 |
June 30, 2001 |
|||||||||||||
| Revenues, net |
$ |
29,063 |
|
31,392 |
|
34,804 |
|
33,364 |
|
128,623 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Net operating margins |
$ |
16,134 |
|
20,543 |
|
22,920 |
|
14,293 |
|
73,890 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Net earnings (loss) attributable to common stockholders |
$ |
(1,857 |
) |
(384 |
) |
(1,875 |
) |
6,491 |
|
2,375 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Earnings (loss) per common share |
||||||||||||||||
| Basic |
$ |
(0.06 |
) |
(0.01 |
) |
(0.06 |
) |
0.20 |
|
0.08 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
| Diluted |
$ |
(0.06 |
) |
(0.01 |
) |
(0.06 |
) |
0.20 |
|
0.08 |
| |||||
| |
|
|
|
|
|
|
|
|
|
| ||||||
76
Table of Contents
There were no changes in and disagreements with accountants on
accounting and financial disclosures during the year ended June 30, 2002.
PART III
| ITEM 10. |
Incorporated by reference from the Proxy Statement for the Annual
Meeting of Stockholders to be held on November 21, 2002.
| ITEM 11. |
Incorporated by reference from the Proxy Statement for the Annual
Meeting of Stockholders to be held on November 21, 2002.
Incorporated by reference from the Proxy Statement for the Annual
Meeting of Stockholders to be held on November 21, 2002.
Incorporated by reference from the Proxy Statement for the Annual
Meeting of Stockholders to be held on November 21, 2002.
PART IV
(a) |
The following documents are filed as a part of this report. |
(1) |
Consolidated Financial Statements: |
TransMontaigne Inc. |
Independent Auditors’ Report
Consolidated Balance Sheets as of June 30, 2002 and June 30,
2001
Consolidated Statements of Operations for the years ended June 30, 2002, 2001 and 2000
Consolidated Statements of Prefered Stock and Common Stockholders’ Equity for the years ended June 30, 2002, 2001 and
2000
Consolidated Statements of Cash Flows for the years ended June 30, 2002, 2001 and 2000
Notes to Consolidated Financial Statements
(2) |
Financial Statement Schedules: Not Applicable |
77
Table of Contents
| ITEM 14. |
EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (continued) |
(3) Exhibits:
A list of the exhibits required by Item 601 of Regulation S-K to be filed as part of this report:
| Exhibit No. |
Description | |
| 2.1 |
Facilities Sale Agreement by and among TransMontaigne Inc., TransMontaigne Pipeline Inc., TransMontaigne Terminaling
Inc. and NORCO Pipeline Company, LLC and Buckeye Terminals, LLC dated July 31, 2001. Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on August 15,
2001. | |
| 3.1A |
Restated Articles of Incorporation and Certificate of Merger. Incorporated by reference to TransMontaigne Oil Company
Form 10-K (Securities and Exchange Commission File No. 001-11763) for the year ended April 30, 1996. | |
| 3.1B |
Certificate of Amendment of Restated Certificate of Incorporation of TransMontaigne Oil Company dated August 26,
1998. Incorporated by reference to TransMontaigne Inc. Form 10-Q (Securities and Exchange Commission File No. 001-11763) for the quarter ended September 30, 1998. | |
| 3.1C |
Certificate of Amendment of Restated Certificate of Incorporation of TransMontaigne Inc. dated December 18, 1998.
Incorporated by reference to TransMontaigne Inc. Form 10-Q (Securities and Exchange Commission File No. 001-11763) for the quarter ended December 31, 1998. | |
| 3.1D |
Certificate of Designations of Series A Convertible Preferred Stock. Incorporated by reference to TransMontaigne Inc.
Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on April 1, 1999. | |
| 3.1E |
Certificate of Designations of Series B Redeemable Convertible Preferred Stock. Incorporated by reference to
TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on July 15, 2002. | |
| 3.2A |
Amended and Restated By-Laws. Incorporated by reference to TransMontaigne Oil Company Form S-2 (Securities and
Exchange Commission File No. 333-18795). | |
| 3.2B |
Amendment to By-Laws dated August 14, 1998. Incorporated by reference to TransMontaigne Inc. Form 10-Q (Securities
and Exchange Commission File No. 001-11763) for the quarter ended September 30, 1999. | |
| 3.2C |
Amendment to By-Laws dated October 30, 1998. Incorporated by reference to TransMontaigne Inc. Form 10-Q (Securities
and Exchange Commission File No. 001-11763) for the quarter ended September 30, 1999. | |
| 3.2D |
Amendment to By-Laws dated December 2, 1998. Incorporated by reference to TransMontaigne Inc. Form 10-Q (Securities
and Exchange Commission File No. 001-11763) for the quarter ended September 30, 1999. | |
| 3.2E |
Amendment to By-Laws dated September 29, 1999. Incorporated by reference to TransMontaigne Inc. Form 10-Q (Securities
and Exchange Commission File No. 001-11763) for the quarter ended September 30, 1999. | |
| 4.1 |
Warrant Agreement between TransMontaigne and BankBoston, N.A., as the Warrant Agent, dated March 25, 1999.
Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on April 1, 1999. | |
| 10.1 |
The TransMontaigne Oil Company Amended and Restated 1995 Stock Option Plan. Incorporated by reference to
TransMontaigne Oil Company Form 10-K (Securities and Exchange Commission File No. 001-11763) for the year ended April 30, 1996. |
78
Table of Contents
| ITEM 14. |
EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (continued) |
| Exhibit No. |
Description | |
| 10.2 |
TransMontaigne Oil Company Equity Incentive Plan. Incorporated by reference to TransMontaigne Oil Company’s
Definitive Proxy Statement (Securities and Exchange Commission File No. 001-11763) filed in connection with the August 28, 1997 Annual Meeting of Shareholders. | |
| 10.3 |
Stock Purchase Agreement effective April 17, 1996 between TransMontaigne Oil Company and the investors named therein.
Incorporated by reference to TransMontaigne Oil Company Form 10-K (Securities and Exchange Commission File No. 001-11763) for the year ended April 30, 1996. | |
| 10.4 |
Anti-dilution Rights Agreement dated as of April 17, 1996 between TransMontaigne Oil Company and Waterwagon &
Co., nominee for Merrill Lynch Growth Fund. Incorporated by reference to TransMontaigne Oil Company Form 10-K (Securities and Exchange Commission File No. 001-11763) for the year ended April 30, 1996. | |
| 10.5 |
Agreement to Elect Directors dated as of April 17, 1996 between TransMontaigne Oil Company and the First Reserve
Investors named therein. Incorporated by reference to TransMontaigne Oil Company Form 10-K (Securities and Exchange Commission File No. 001-11763) for the year ended April 30, 1996. | |
| 10.6 |
Amendment to Agreement to Elect Directors dated as of April 17, 1996 dated June 26, 2002 between TransMontaigne Inc.
and the First Reserve Investors named therein. FILED HEREWITH. | |
| 10.7 |
Amended and Restated Institutional Investor Registration Rights Agreement dated June 27, 2002 by and among
TransMontaigne Inc. and the entities listed on the signature pages thereof. Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on July 15, 2002.
| |
| 10.8 |
Amended and Restated Louis Dreyfus Corporation Registration Rights Agreement dated June 27, 2002 between
TransMontaigne Inc. and Louis Dreyfus Corporation. Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on July 15, 2002. | |
| 10.9 |
Amended and Restated Preferred Stock Investor Registration Rights Agreement dated June 27, 2002 between
TransMontaigne Inc. and the entities listed on the signature pages thereof.Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on July 15, 2002. |
|
| 10.10 |
Form of Preferred Stock and Warrant Purchase Agreement (without exhibits). Incorporated by reference to
TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on April 1, 1999. | |
| 10.11 |
Form of Preferred Stock Recapitalization Agreement dated as of June 27, 2002 (without exhibits). Incorporated by
reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on July 15, 2002. | |
| 10.12 |
Stockholders’ Agreement dated as of June 28, 2002 among TransMontaigne Inc., Key Senior Executives, and the
Investors listed on the signature pages thereof.Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on July 15, 2002. | |
| 10.13 |
Fifth Amended and Restated Credit Agreement between TransMontaigne Inc. and Fleet National Bank as Administrative
Agent and Collateral Agent, dated as of June 27, 2002. Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on July 15, 2002. |
79
Table of Contents
| ITEM 14. |
EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (continued) |
| Exhibit No. |
Description | |
| 10.14 |
Stock Purchase Agreement dated as of September 13, 1998, between Louis Dreyfus Corporation and TransMontaigne Inc.
Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on November 13, 1998. | |
| 10.15 |
Amendment No. 1 to Stock Purchase Agreement dated as of October 30, 1998, between Louis Dreyfus Corporation and
TransMontaigne Inc. Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on November 13, 1998. | |
| 10.16 |
Letter Agreement dated as of June 27, 2002 between First Reserve Fund VI, Limited Partnership and TransMontaigne Inc.
Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) filed on July 15, 2002. | |
| 21 |
Schedule of TransMontaigne Inc. Subsidiaries. FILED HEREWITH. | |
| 23.1 |
Consent of KPMG LLP. FILED HEREWITH. | |
| 99.1 |
Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH. |
(b) Reports on Form 8-K.
There were no reports on Form 8-K filed during the three months ended June 30, 2002.
80
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| TRANSMONTAIGNE INC. | ||
| By: |
/s/ CORTLANDT S.
DIETLER | |
| Cortlandt S. Dietler Chairman | ||
Date: September 26, 2002
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report is signed below by the following persons on behalf of
the Registrant and in the capacities indicated on September 26, 2002.
| Name and Signature |
Title |
|||
| /s/ CORTLANDT S.
DIETLER Cortlandt S. Dietler |
Chairman and Director |
|||
| /s/ DONALD H.
ANDERSON Donald H. Anderson |
President, Chief Executive Officer, Chief Operating Officer, Vice Chairman and Director |
|||
| /s/ HAROLD R. LOGAN,
JR. Harold R. Logan, Jr. |
Executive Vice President, Chief Financial Officer, Treasurer and Director |
|||
| /s/ RANDALL J.
LARSON Randall J. Larson |
Executive Vice President, Controller and Chief Accounting Officer |
|||
| /s/ PETER B.
GRIFFIN Peter B. Griffin |
Director |
|||
| /s/ BEN A. GUILL
Ben A. Guill |
Director |
|||
| /s/ JOHN A. HILL
John A. Hill |
Director |
|||
| /s/ BRYAN H.
LAWRENCE Bryan H. Lawrence |
Director |
|||
| /s/ EDWIN H.
MORGENS Edwin H. Morgens |
Director |
81
Table of Contents
I, Donald H. Anderson, President, Chief Executive Officer and Chief
Operating Officer of TransMontaigne Inc., certify that :
1. I have reviewed this annual
report on Form 10-K of TransMontaigne Inc.;
2. Based on my knowledge, this annual report
does not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period
covered by this annual report; and
3. Based on my knowledge, the financial statements, and
other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.
Dated: September 26, 2002
| /s/ DONALD H.
ANDERSON | ||
| Donald H. Anderson President, Chief Executive Officer and Chief Operating Officer | ||
I, Harold R. Logan, Jr., Executive Vice President, Chief Financial
Officer and Treasurer of TransMontaigne Inc., certify that :
1. I have reviewed this
annual report on Form 10-K of TransMontaigne Inc.;
2. Based on my knowledge, this annual
report does not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the
period covered by this annual report; and
3. Based on my knowledge, the financial
statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual
report.
Dated: September 26, 2002
| /s/ HAROLD R. LOGAN,
JR. | ||
| Harold R. Logan, Jr. Executive Vice President, Chief Financial Officer and Treasurer | ||
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