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TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 2005 |
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OR |
|
/ / |
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the transition period to |
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Commission File Number 001-11763
TRANSMONTAIGNE INC.
(Exact name of registrant as specified in its charter)
| Delaware (State or other jurisdiction of incorporation or organization) |
06-1052062 (I.R.S. Employer Identification No.) |
|
Suite 3100, 1670 Broadway Denver, Colorado 80202 (Address, including zip code, of principal executive offices) |
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(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 | New York 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/
Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2) Yes /X/ No / /
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2) Yes / / No /X/
The aggregate market value of the voting stock held by non-affiliates of the Registrant was $348,342,753. The aggregate market value was computed by reference to the last sale price ($9.34 per share) of the Registrant's Common Stock on the New York Stock Exchange on August 29, 2005.
The number of shares of the registrant's Common Stock outstanding on August 29, 2005 was 50,146,738.
DOCUMENTS INCORPORATED BY REFERENCE
None.
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and any amendments to such reports, will be available free of charge on our website at www.transmontaigne.com under the heading "Investor Relations" "Financial Information" "SEC Filings", as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This annual report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934:
- i.
- certain
statements, including possible or assumed future results of operations, in "Management's Discussion and Analysis of Financial Condition and Results of Operations;"
- ii.
- any
statements contained herein or therein regarding the prospects for our business or any of our services;
- iii.
- any
statements preceded by, followed by or that include the words "may," "will," "seeks," "believes," "expects," "anticipates," "intends," "continues," "estimates," "plans" or
similar expressions; and
- iv.
- other statements contained herein or therein regarding matters that are not historical facts.
Our business and results of operations are subject to risks and uncertainties, many of which are beyond our ability to control or predict. Because of these risks and uncertainties, actual results may differ materially from those expressed or implied by forward-looking statements, and investors are cautioned not to place undue reliance on such statements, which speak only as of the date thereof.
In addition to the specific risk factors described in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors," important factors that could cause actual results to differ materially from our expectations include, but are not limited to:
- –>
- the
availability of adequate supplies of and demand for petroleum products in the areas in which we operate;
- –>
- the
effects of competition and our ability to renew customer contracts;
- –>
- the
impact of petroleum product price fluctuations on our sales margins and the effect of changes in commodity prices on our liquidity;
- –>
- the
success of our risk management policies;
- –>
- volumes
of refined petroleum product throughput or stored in our terminal facilities;
- –>
- TransMontaigne
Partners' inability to pay the minimum quarterly distribution on the subordinated units that we own;
- –>
- continued
creditworthiness of, and performance by, contract counterparties;
- –>
- the
tax and other effects of the exercise of TransMontaigne Partners' options to purchase our fixed assets;
- –>
- operational
hazards and availability and cost of insurance on our assets and operations;
- –>
- the
impact of any failure of our information technology systems;
- –>
- the
availability of acquisition opportunities and successful integration and future performance of acquired assets;
- –>
- the
threat of terrorist attacks or war;
- –>
- the
impact of current and future laws and governmental regulations;
- –>
- the
failure by TransMontaigne Partners to avoid federal income taxation as a corporation or the imposition of state level taxation;
- –>
- liability for environmental claims;
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- –>
- the
impact of the departure of any key officers; and
- –>
- general economic, market or business conditions.
We do not intend to update these forward-looking statements except as required by law.
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TransMontaigne Inc., formed in 1995, is a refined petroleum products terminaling, distribution and supply company with operations in the United States, primarily in the Gulf Coast, Florida, East Coast and Midwest regions. Our common stock is traded on the New York Stock Exchange under the symbol "TMG." Our executive offices are located at 1670 Broadway, Suite 3100, Denver, CO 80202; telephone number (303) 626-8200.
TransMontaigne Inc. is a holding company that conducts its operations through six primary subsidiaries: TransMontaigne Product Services Inc., which owns our terminaling facilities and conducts the majority of our supply, distribution and marketing operations; Coastal Fuels Marketing, Inc., which conducts supply, distribution and marketing operations principally to marine vessels and power generation plants; Coastal Tug and Barge, Inc., which owns and operates our fleet of tugboats and barges and provides transportation services; TransMontaigne Services Inc., which employs our employees and provides services to our other operating subsidiaries; TransMontaigne Transport Inc., which operates our turbo prop aircraft to transport our personnel among locations; and TransMontaigne Partners L.P., a publicly traded limited partnership in which we own a 2% general partnership interest and a 39.4% limited partnership interest.
TransMontaigne Inc. We provide integrated terminal, transportation, storage, supply, distribution and marketing services to refiners, wholesalers, distributors, marketers, and industrial and commercial end-users of refined petroleum products. Our principal activities consist of (1) terminal, pipeline and tug and barge operations, (2) supply, distribution and marketing and (3) supply chain management services, and (4) managing TransMontaigne Partners, a publicly traded master limited partnership that is engaged in terminal and pipeline operations. Although the assets, liabilities, and results of operations of TransMontaigne Partners are reflected on a consolidated basis in our accompanying financial statements, this description of our business describes separately the activities of TransMontaigne Inc. and its subsidiaries other than TransMontaigne Partners and its subsidiaries.
We predominantly handle refined petroleum products, with the balance being fertilizer, chemicals and other commercial liquids. The refined petroleum products we handle include gasoline, diesel fuel, heating oil, jet fuel and kerosene. In Florida, our product and service offerings also include the sale of bunker fuel, used to power ocean vessels, and No. 6 oil, for powering electricity generating plants, as well as the storage of crude oil and asphalt.
We own and operate terminal infrastructure that handles refined petroleum products and other commercial liquids with transportation connections by pipelines, tankers, barges, rail cars and trucks to our facilities or to third-party facilities. At our terminals, we provide throughput, storage, injection and distribution related services to distributors, marketers, retail gasoline station operators and industrial and commercial end-users of refined petroleum products and other commercial liquids. At June 30, 2005, we owned and operated 43 terminals, with an aggregate capacity of approximately 15.0 million barrels. In Florida, we also provide refined petroleum product transportation and delivery services by tug and barge and by truck. In addition, at Port Everglades, Florida, we deliver product to cruise ships and freight vessels by means of our pipeline delivery system.
In our supply, distribution and marketing operations, we purchase refined petroleum products and schedule them for delivery to our terminals, as well as terminals owned by third parties, in the Gulf
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Coast, Florida, East Coast and Midwest regions of the United States. We then sell our products primarily through a combination of rack spot sales and contract sales to cruise ship operators, commercial and industrial end-users, independent retailers, distributors, marketers, government entities and other wholesalers of refined petroleum products.
We also provide supply chain management services to industrial, commercial and governmental customers that have large ground vehicle fleets. We often combine these services with price management solutions to provide our customers an assured source of fuel at a predictable price. Our customer base includes companies involved in the manufacture and distribution of consumer products, express shipping services, waste disposal services, transportation services, and state and local government entities.
TransMontaigne Partners. At June 30, 2005, TransMontaigne Partners owned seven refined product terminals in Florida, one refined product terminal in each of Missouri and Arkansas and a 67-mile, interstate refined products pipeline between the Missouri and Arkansas terminals.
Product description
Refineries produce refined petroleum products by processing crude oil. Refined petroleum products generally are classified in two groups, "light oils" and "heavy oils." Light oils include gasoline and distillates, such as diesel fuel, heating oil, jet fuel and kerosene. Heavy oils include No. 6 oil and asphalt. When produced at the refinery, refined petroleum products of a specific grade and characteristics are substantially identical in composition from one refinery to the next and are referred to as being "fungible."
Regional production and consumption
The continental United States refined petroleum products market is divided in two distinct regions: the Western United States, which is primarily served by refineries located in the Pacific Coast region; and the Gulf Coast, Florida, East Coast and Midwest markets, which are primarily served by refineries located in the Gulf Coast region and imports of refined petroleum products from South America and Europe. Substantially all of our supply, distribution and marketing operations occur in the Gulf Coast, Florida, East Coast and Midwest regions.
The U.S. Department of Energy divides the United States into five geographic regions. These regions are referred to as Petroleum Administration Defense Districts or PADDs. PADD III, which is the Gulf Coast region of the United States, is the largest petroleum refining hub in the U.S. with 55 refineries, responsible for approximately 47% of total U.S. daily refining capacity. The Gulf Coast historically has had an excess supply of refined petroleum products, which are shipped mainly to the East Coast, Florida and the Midwest. For the year ended December 31, 2004, the Gulf Coast had average refined petroleum production of approximately 8.1 million barrels per day and average refined petroleum product consumption of approximately 3.9 million barrels per day.
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PADD II, which is the Midwest region, is the second largest PADD in terms of crude oil throughput capacity. Production of petroleum product by refiners located in the Midwest region historically has been less than the demand for such product within that region, resulting in product being supplied from surrounding regions, primarily from the Gulf Coast via common carrier pipelines including the Explorer, TEPPCO, Seaway, Phillips and Centennial pipelines. Supply also is available via barge transport up the Mississippi River with significant deliveries into local markets along the Ohio River. For the year ended December 31, 2004, the Midwest region had average refined petroleum production of approximately 3.4 million barrels per day and average refined petroleum product consumption of approximately 4.8 million barrels per day.
PADD I is the East Coast region, and includes the Florida, Southeast, Mid-Atlantic and Northeast regions. Production of petroleum product by refiners located in the East Coast region historically has
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been less than the demand for such product within that region, resulting in product being supplied from surrounding regions, primarily from the Gulf Coast via the Colonial and Plantation pipelines, barges and marine vessels and imports from foreign producers directly into Florida and East Coast ports. For the year ended December 31, 2004, the East Coast region had average refined petroleum production of approximately 2.1 million barrels per day and average refined petroleum product consumption of approximately 6.2 million barrels per day.
We believe that our geographically diverse terminal infrastructure and our ability to direct significant volumes of product for delivery along the major common carrier pipelines reduces the risk that economic circumstances in any one geographic area will have a substantial effect on our operations taken as a whole.
Refining and distribution
Refining. Refineries in the Gulf Coast region, which are owned predominantly by major and large independent oil companies, refine crude oil into products that have various characteristics, such as sulfur content, octane level, Reid-vapor pressure, and other chemical characteristics. The refined products initially are stored at the refineries' own terminal facilities. The refineries then schedule for delivery some of their product output to satisfy their own retail delivery obligations, at branded gasoline stations, for example, and sell the remainder of their product output to independent marketing and distribution companies, such as TransMontaigne Inc. and our independent supply partners, for resale. The major refineries typically prefer to sell their excess product to independent marketing and distribution companies rather than to other refineries and integrated oil companies, which are their primary competitors.
Transportation. An independent marketing and distribution company must first schedule that product, at least five to eight days in advance, on common carrier pipelines for delivery to its terminals. Common carrier pipelines are pipelines with published tariff rates that are regulated by the Federal Energy Regulatory Commission ("FERC"). These pipelines ship product in batches, with each batch consisting of fungible product owned by several different companies. Once in the pipeline, a
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product may take twenty or more days to move from the Gulf Coast to the New York market, with much of the product in the batch being delivered to terminals located along the routes of the common carrier pipelines. A batch of one product, gasoline for example, will then be followed by a batch of different product, such as diesel fuel.
During periods of high demand for a particular product, companies may seek to ship more volume of product than space available in the pipelines, in which case the common carrier pipelines will allocate volume based on the historical shipping history of each company seeking to ship. Companies that consistently ship significant amounts of product on common carrier pipelines are allocated space on these regulated pipelines for future shipments. Companies without significant shipping histories are not guaranteed similar space on the pipelines and have more difficulty shipping their product to various locations around the country when there is high demand for pipeline capacity to those locations. Our product supply arrangement with Morgan Stanley Capital Group, Inc. utilizes our historical shipping history and allows us to schedule product for delivery along these pipelines during periods of high demand for pipeline capacity.
As a batch of co-mingled product is shipped on a pipeline, each terminal along the way draws the volume of fungible product that is scheduled for that facility as the batch passes in the pipeline. Consequently, each terminal operator must monitor the type of product in the common carrier pipeline at any time to determine when to draw product scheduled for delivery to that terminal. In addition, both the common carrier pipeline and the terminal operator monitor the volume of product drawn to ensure that the precise amount scheduled for delivery at that location is actually received.
Product shipped to marine terminals is primarily transported by tankers or barges.
At both inland and marine terminals, the various refined petroleum products are segregated and stored in tanks. Because the characteristics of gasoline are required to be changed at least twice per year in many locations to meet government regulations, regular unleaded gasoline produced for winter cannot be stored in a tank together with regular unleaded gasoline produced for summer.
Delivery. Each inland terminal has a tanker truck loading facility commonly referred to as a "rack." Often, commercial and industrial end-users and independent retailers will rely on independent trucking companies to pick up product at the rack and transport it to the end-user or retailer at its location. Each truck holds an aggregate of approximately 8,000 gallons of various products in different compartments. The driver will swipe a magnetic card that identifies the customer purchasing the product, the carrier and the driver as well as the products to be pumped into the truck. Our computerized system electronically reviews the credentials of the carrier, including insurance and certain necessary certifications, the credit of the customer and confirms the customer is within scheduled allocation limits. When all conditions are verified as being current and correct, the system authorizes the delivery of the product to the truck. As product is being loaded into the truck, additives are blended into products, including all gasoline, to conform to government specifications and individual customer requirements. If a truck is loading gasoline for retail sale by an independent gasoline station, generic additives will be added to the gasoline as it is loaded into the truck. If the gasoline is for delivery to a branded retail gasoline station, the proprietary additive compound of that particular retailer will be added to the gasoline as it is loaded. The type and amount of additive are electronically and mechanically controlled by equipment located at the truck loading rack.
At marine terminals, the product is stored in tanks and may be delivered to tanker trucks over a rack in the same manner as inland terminals. Product also may be delivered to cruise ships and other vessels, known as "bunkering," either at the dock, through a pipeline delivery system or truck, or by barge. Cruise ships typically purchase approximately 6,000 to 8,000 barrels, the equivalent of
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approximately 42 truckloads, of product per refueling. Bunker fuel is a mixture of diesel fuel and No. 6 oil. Each large vessel essentially requires its own mixture of bunker fuel to match the distinct characteristics of that ship's engines. Because the mixture for each ship requires precision to mix and deliver, cruise ships often prefer to refuel in United States ports with experienced marketing companies.
We conduct business in the following business segments:
- –>
- Terminals, pipelines, and tugs and barges—consists of a terminal infrastructure that handles refined
petroleum products with transportation connections via pipelines, barges, vessels, rail cars and trucks to our facilities or to third-party facilities with an emphasis on transportation connections
primarily through the Colonial, Plantation, TEPPCO, Explorer and Magellan pipeline systems.
- –>
- Supply, distribution and marketing—consists of services for the supply, distribution and marketing of
refined petroleum products through rack spot sales, contract sales and bulk sales in the physical markets, with retail, wholesale, industrial and commercial customers using our terminal racks and
marine refueling equipment, and providing related value-added fuel procurement and supply chain management services.
- –>
- TransMontaigne Partners L.P.—consists of a terminal and pipeline infrastructure that handles refined petroleum products through seven terminals in Florida, a 67-mile, interstate refined products pipeline and two refined product terminals at either end of the pipeline, one located in Mt. Vernon, Missouri and the other located in Rogers, Arkansas.
Terminals, pipelines, and tugs and barges
The refined petroleum product distribution system in the United States links refineries to end-users of gasoline and other refined petroleum products through a network of terminals, pipelines, tankers, barges, rail cars and trucks. At June 30, 2005, we own and operate terminal infrastructure of 43 terminals with approximately 15.0 million barrels of aggregate capacity that handles refined petroleum products and other commercial liquids. We also operate for TransMontaigne Partners nine terminals with approximately 6.2 million barrels of aggregate capacity that handle refined petroleum products and crude oil. At these terminals, we provide throughput, storage, injection and other distribution related services to wholesalers, distributors, marketers, retail gasoline station operators and industrial and commercial end-users of refined petroleum products and other commercial liquids. We currently own and operate the following terminal facilities:
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terminals with approximately 8.9 million barrels of capacity, located at various points along the Plantation and Colonial pipeline corridor, which extends
from the Gulf Coast through the Southeast, Mid-Atlantic and Northeast regions;
- –>
- 11
terminals with approximately 3.2 million barrels of capacity, located in the Midwest and upper and lower Mississippi River areas; and
- –>
- 1 terminal complex in Brownsville, Texas with approximately 2.2 million barrels of capacity.
Our network of terminals is geographically diverse with our largest terminal, the Brownsville complex, accounting for approximately 15% of the total capacity of our terminals. Brownsville handles a large volume of liquid product movements between Mexico and south Texas.
In Florida, we currently own and operate 11 tugboats and 13 barges and a proprietary pipeline delivery system in Port Everglades, which we use to transport our product to cruise ships and other
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marine vessels for refueling. We also use our tugs and barges to transport third party product and to relocate our product among the Florida terminals owned by TransMontaigne Partners. We use tank capacity provided to us by TransMontaigne Partners at its Florida terminals to blend diesel fuel and No. 6 oil into bunker fuel meeting our customers' specifications. In addition, we use our diesel fuel and No. 6 oil pipeline delivery system at Port Everglades to blend these products at dockside for direct delivery into our customers' vessels.
Along the Mississippi River we own and operate a dock facility in Baton Rouge, Louisiana that is interconnected to the Colonial Pipeline. This connection provides the ability to load product originating from the Colonial Pipeline onto barges for distribution up the Mississippi River, as well as serves as an injection point into the Colonial Pipeline for product unloaded from barges transporting it down the Mississippi River.
We generate revenues in our terminal, pipeline and tug and barge operations from throughput and additive injection fees, storage fees, additization fees, pipeline transportation fees, barge and ship-assist fees, management fees and cost reimbursements and fees from other ancillary services.
Throughput and Additive Injection Fees. We earn throughput fees for each barrel of refined petroleum product that is distributed at our terminals. A significant majority of the throughput at our terminals consists of product that our supply, distribution and marketing segment has purchased, marketed, sold and dispensed over the rack at our terminals. The remainder of the throughput volume at our terminals is generated from exchange agreements and throughput arrangements with third parties. Terminal throughput fees are based on the volume of products distributed at the facility's truck loading racks, generally at a standard rate per barrel of product. Unlike common-carrier pipeline services, terminal services are not subject to price (tariff) regulations, allowing the marketplace to determine the prices that are charged for services.
For example, our supply, distribution and marketing business may enter into a sale agreement for a specific volume of product in Virginia. The product may be shipped to our terminals serving that area for delivery to the customer or the delivery obligation may be satisfied from our existing inventory in those terminals. In either event, the delivery of product to the third-party from our terminal over the truck rack constitutes throughput. Third-party throughput operates in the same manner except that it is a third party that directs the product delivery to our terminals rather than our own supply, distribution and marketing business.
Exchange agreements generally are term agreements that involve our receipt of a specified volume of product at one location in exchange for delivery by us of product at a different location. We enter into exchange agreements with major oil companies to increase throughput at our terminals. We generally receive a fee based on the volume of the product exchanged and delivered through our terminals. The exchange fee takes into account the terminal throughput fee, the cost of transportation from the receipt location to the delivery location, as well as a fee for "regrading" if we deliver one type of product and receive a different type of product. For example, if a major oil company has a one-year agreement to deliver premium gasoline in Atlanta, but does not have a terminal there, that company may enter into an exchange agreement with us whereby we will provide the product at our truck rack in Atlanta and, in exchange, they will provide us with product, which may be the same or a different grade of gasoline, in the Gulf Coast and pay us a negotiated fee.
Additization or injection is the process of injecting refined petroleum products with additives and dyes. Some injected products, such as detergent additives, are standard and are required to comply with governmental regulations, while other injected products are proprietary to certain of our customers. We provide injection services to our customers in connection with the delivery of product at our
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terminals. These fees are generally based on the volume of product injected and delivered over the rack at our terminals.
Storage Revenues. We lease storage capacity at our terminals to third parties and our supply, distribution and marketing operation and earn a storage fee based on the volume of the storage capacity leased. Terminal storage fees generally are based on a per barrel of leased capacity per month rate and will vary with the duration of the storage arrangement (remaining lease terms range from month-to-month to less than 8 years at June 30, 2005), the type of product stored and special handling requirements, particularly when certain types of chemicals and other commercial liquids are involved. For example, the entire 2.2 million barrel capacity at our Brownsville terminal facility is leased, or available for lease, to third parties.
Pipeline Revenues. We earn transportation fees at our Port Everglades pipeline delivery system based on the volume of product delivered to cruise ships and freight vessels. The Port Everglades pipeline delivery system allows a more efficient refueling process than barge to ship refueling. Our supply, distribution and marketing segment is the only shipper of product on the Port Everglades pipeline delivery system.
Barge and Ship-Assist Revenues. Our barges earn transportation fees from third parties at negotiated rates based on the volume of product that is shipped and the distance to the delivery point. Our barges also provide marine vessel fueling services, referred to as bunkering, from TransMontaigne Partners' Port Everglades/Ft. Lauderdale, Cape Canaveral, Port Manatee/Tampa and Fisher Island/Miami terminals. Bunkering fees are based on the volume and type of product delivered to the cruise ships and freight vessels. Our tugboats also earn fees for providing docking and other ship-assist services to cruise and cargo ships and other vessels in South Florida ports based on a per docking per tug basis.
Management Fees and Cost Reimbursements. We manage and operate for a major oil company 17 terminals that are adjacent to our Southeast facilities and receive a reimbursement of costs. We manage and operate for another major oil company certain tank capacity at TransMontaigne Partners' Port Everglades (South) terminal and receive a reimbursement of costs. We also manage and operate for a foreign oil company a bi-directional products pipeline connected to our Brownsville, Texas terminal facility.
Other Service Revenues. In addition to providing storage and distribution services, we also provide ancillary services including heating and mixing of stored products and product transfer services. Many heavy oil products, such as No. 6 oil, bunker fuel and asphalt require heating to keep them in a liquid state suitable for shipping. For example, heavy oil products may be transported to a terminal in non-insulated tank rail cars and, therefore, must be re-heated before being transferred into terminal storage tanks or into trucks or barges. We provide these heating services to our customers and charge negotiated fees based on the type and volume of product heated. We also earn transfer fees for transferring product between tanks and transportation equipment. For example, we would charge a fee to transfer product from a rail car or a barge to a storage tank at a customer's request. We also recognize revenues upon the sale of product to our supply, distribution, and marketing operation resulting from the excess of product deposited by third parties into our terminals over the amount of product that the customer is contractually permitted to withdraw from those terminals.
Supply, distribution and marketing
Prior to the implementation of our product supply arrangement with Morgan Stanley Capital Group, Inc. during the three months ended March 31, 2005, we generally purchased our inventory of refined petroleum products at prevailing prices from refiners and marketers at production points and
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common trading locations along the Gulf Coasts of Texas and Louisiana. We now purchase substantially all of our light oil products for sale through our terminals located along the Colonial and Plantation pipelines and TransMontaigne Partners' Florida terminals from Morgan Stanley Capital Group, Inc. under a product supply agreement that expires on December 31, 2011. For the remainder of our and TransMontaigne Partners' terminals, and for our heavy oil supply needs, we contract to purchase our inventory at prevailing prices from refiners and marketers. In each case, we direct shipments for delivery via pipelines and vessels to our terminals, as well as terminals owned by TransMontaigne Partners and third parties with which we have storage or throughput agreements. From these terminal locations, we then sell our products to customers primarily through three types of arrangements: rack spot sales, contract sales, and bulk sales.
Rack Spot Sales. Rack spot sales are sales that do not involve continuing contractual obligations to purchase or deliver product. Rack spot sales are priced and delivered on a daily basis through truck loading racks or marine fueling equipment. At the end of each day for each of the terminals that we market from, we establish the next day selling price for each product for each of our delivery locations. We announce or "post" to independent local jobbers via facsimile, website, e-mail, and telephone communications the rack spot sale price of various products for the following morning. Typical rack spot sale purchasers include commercial and industrial end-users, independent retailers and small, independent marketers, referred to as "jobbers," who resell product to retail gasoline stations or other end-users. Our selling price of a particular product on a particular day is a function of our supply at that delivery location or terminal, our estimate of the costs to replenish the product at that delivery location, and our desire to reduce inventory levels at that particular location that day.
We manage the physical quantity of our inventories of product through rack spot sales. Our rack spot sales volume for a particular product is sensitive to changes in price. If our objective is to increase rack spot sales volume for a particular product of ours at a specific delivery location, then we would post the selling price of that product at the low end of the range of competitive prices being offered in the applicable market to induce purchasers in that market to choose to buy our product as opposed to product offered by competitors in that market. This would occur if, for example, we expect that wholesale margins for that product will decrease at that location in the near future or if we have significant deliveries scheduled to arrive at that location in the near term.
Contract Sales. Contract sales are made pursuant to negotiated contracts, generally ranging from one to twelve months in duration, that we enter into with local market wholesalers, independent gasoline station chains, heating oil suppliers, cruise ship operators and other customers. Contract sales provide these customers with a specified volume of product during the term of the agreement. Delivery of product sold under these arrangements generally is at our truck racks or via our marine fueling equipment. The pricing of the product delivered under a majority of our contract sales is based on published index prices, and vary based on changes in the applicable indices. In addition, at the customer's option, the contract price may be fixed at a stipulated price per gallon.
For example, we may enter into an agreement with a retail heating oil supplier in the Northeast to provide the supplier with heating oil, for delivery at our truck rack or a rack owned by a third party, during the high demand winter months at a fixed price.
Bulk Sales. Bulk sales generally involve the sale of products in large quantities in the major cash markets including the Houston Gulf Coast and New York Harbor. A bulk sale of products also may be made while the product is being transported in the common carrier pipelines or by barge or vessel.
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Supply Chain Management Services. Industrial, commercial and governmental entities with significant ground fleets need to ensure adequate fuel supplies for their fleet vehicles. For many of these companies and governmental entities, the cost of fuel is a significant expenditure and the administration and record keeping involved is burdensome. Some companies also maintain their own proprietary refueling facilities, which requires monitoring fuel levels, scheduling deliveries, controlling inventories and filing excise tax returns. Other companies use retail gasoline stations to refuel their vehicles, resulting in extensive payment handling as well as exposure to price fluctuations in the market. In response to these market needs, we developed our supply chain management service offerings. We provide supply chain management services to companies and governmental entities that desire to outsource their fuel supply function to focus their efforts on their core competencies and to reduce the price volatility associated with their fuel supplies for budgetary reasons. These services often include price management solutions that provide our customers an assured source of fuel at a predictable price. Our customer base includes companies involved in the manufacture and distribution of consumer products, express shipping services, waste disposal services, transportation services, and state and local government entities.
These customers use our proprietary web-based technology, which provides them the ability to budget their fuel costs while outsourcing all or a portion of their procurement, scheduling, routing, excise tax and payment processes. Using electronic metering equipment, we can monitor the amounts of product stored and delivered at our customers' proprietary refueling locations. In addition, through our strategic relationship with a credit card processing company, we can monitor the volume of fuel purchased by our customers' ground fleet vehicles at retail truck stops and service stations.
We currently offer three types of supply chain management services: delivered fuel price management, retail price management and logistical supply chain management services.
Delivered fuel price management contracts involve the sales of committed quantities of specific motor fuels delivered to our customer's proprietary fleet refueling locations, at fixed prices for terms up to three years. On a daily basis, for each of our customer's facilities, we procure product, schedule delivery, manage local inventory quantities and summarize each customer's purchases by location and vehicle. Typical customers for delivered fuel price management services have large fleets of vehicles that drive fixed, scheduled routes, making refueling at a proprietary refueling location an attractive choice.
For example, we may enter into a delivered fuel price management contract with a customer that has storage and refueling facilities at its fleet operations centers. We will agree to deliver diesel fuel directly to the customer's proprietary refueling location at a fixed price per gallon. We then monitor the customer's fuel usage and schedule additional fuel deliveries as needed. We will provide the customer with a single invoice for all of the fuel deliveries that includes reconciliation of all bills of lading against deliveries and breaks out accumulated third-party transportation costs. This information is available to the customer on a customized web-based portal.
Retail price management contracts typically are entered into for a period of up to 18 months with customers that require flexibility in refueling locations, either because they do not have proprietary refueling facilities or because they generally do not operate along fixed routes. Under these arrangements, customers commit to a specific monthly notional quantity of product within one or more metropolitan areas. The customer's drivers will purchase fuel at a retail gasoline station within the metropolitan area and use their fleet credit card to pay the retail price at that station. We then settle with our customer the net financial difference between a stipulated retail price index for that metropolitan area and our customer's contract price on a monthly basis. If the contract price is less than the average indexed price, we will pay the customer the net difference. If the contract price exceeds the average indexed price, the customer will pay us the net difference. In either case, the
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customer will have effectively managed its exposure to fuel costs at the contract price. Through our proprietary web-based software, our customers receive a monthly report of each of these activities. Typical customers for retail price management services include companies that have large fleets that are dispatched to specific service or delivery locations on an as-needed basis.
For example, we may enter into a retail price management contract with a customer for a price per gallon of gasoline equal to a stipulated retail price index plus a negotiated fee. The customer's fleet drivers are able to purchase fuel at almost any retail gasoline station using their fleet credit card. At the time of purchase, the driver pays for the gasoline using the company fleet card, and the vehicle number and the amount and price of fuel purchased are recorded. A credit card processing company sends daily electronic reports to us indicating a summary of the data collected by the credit cards. This information is made available to the customer on our proprietary web-site. We then settle the net difference between the indexed price and the customer's contract price on a monthly basis.
Under our logistical supply chain management arrangements, we provide our proprietary web-based refined petroleum product procurement, inventory management, scheduling, routing, excise tax and consolidated billing services to customers on a stand alone basis without any delivery or price management products. These services also are often integrated with a credit card processing company, thereby affording our customers complete flexibility to obtain their supply of products at almost any retail gasoline station. These services typically are charged to the customer on a per gallon basis or at negotiated rates. Typical logistical service customers include governments and customers that are seeking to outsource or streamline record keeping functions but are willing to continue to bear price fluctuations. Often, a customer will initially contract for logistical supply chain management services and later use our delivered fuel price management or retail price management services.
For example, a customer may want the benefits of a single invoice for all fuel purchases and the ability to manage its fuel usage on-line. We provide access to fuel purchase data in real time, providing an automated platform for analysis tailored to each customer. In addition, many customers have diverse logistical requirements, buying fuel in bulk, at retail locations and through mobile refueling services. We can provide integrated management of all supply and logistical requirements for our customers' bulk locations and use our relationship with a credit card processing company to manage the retail and mobile refueling volumes. The customer's fleet card would capture the fueling transaction data for the bulk, retail and mobile refueling activity facilitating customized reporting on our proprietary web site. Our customers benefit from a single resource for the procurement, pricing and reporting of all fuel data regardless of the logistical requirements.
We have received a revenue ruling from the Internal Revenue Service that allows us to provide state and local government vehicle fleets with a simplified process for managing and obtaining fuel tax exemptions. State and local governments are exempt from paying federal excise taxes on the fuel consumed by their vehicle fleets. Normally, fleet vehicles would purchase gasoline at retail gasoline stations, where excise taxes are included in the price of gasoline, and the government agency would file a tax return to obtain a refund of excise taxes paid. By using our supply chain management services, these tax-exempt government fleets can purchase fuel at almost any retail location using their fleet credit card. The credit card processing company pays the merchant and transfers the balance to our account. We then bill our customer net of federal excise taxes. We file all necessary excise tax returns on behalf of these customers with the applicable taxing authorities and we receive a credit against our excise tax payment obligations. We believe that this additional service gives us a competitive advantage that will allow us to attract additional government fleet customers.
Risk Management. Our risk management committee, composed of senior executives of TransMontaigne Inc., has established risk management policies to monitor and manage commodity
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price risks. For additional information about our risk management policies and practices, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk," included elsewhere in this annual report.
Company Overview. TransMontaigne Partners L.P., is a publicly traded master limited partnership that provides refined petroleum product terminaling and transportation services. TransMontaigne Partners' common units are traded on the New York Stock Exchange under the symbol "TLP." An indirectly wholly-owned subsidiary of TransMontaigne Inc. is the general partner of TransMontaigne Partners. We own a 2% general partnership interest and a 39.4% limited partnership interest in TransMontaigne Partners. TransMontaigne Partners owns nine terminal facilities with approximately 6.2 million barrels of aggregate capacity that handle refined petroleum products and crude oil. TransMontaigne Partners does not take ownership of or market products that it handles or transports and, therefore, TransMontaigne Partners is not directly exposed to changes in commodity prices. TransMontaigne Partners currently owns, and we operate on its behalf, the following terminal and pipeline facilities:
- –>
- seven
refined product terminals located in Florida, with an aggregate storage capacity of approximately 5.8 million barrels, that provide integrated
terminaling services to us, other distribution and marketing companies and the United States government;
- –>
- a
67-mile, interstate refined products pipeline with a capacity of approximately 30,000 barrels per day, which we refer to as the Razorback Pipeline,
that currently transports gasoline and distillates for our use from Mt. Vernon, Missouri to Rogers, Arkansas; and
- –>
- two refined product terminals, one located in Mt. Vernon, Missouri and the other located in Rogers, Arkansas, with an aggregate storage capacity of approximately 400,000 barrels, that are connected to the Razorback Pipeline and provide integrated terminaling services to us.
We currently are the sole shipper on the Razorback Pipeline. The Rogers terminal, together with the Mt. Vernon terminal and Razorback Pipeline, allows us to ship product from the Gulf Coast to this Midwest market via its connection to the Explorer Pipeline.
Omnibus Agreement. As part of the initial public offering of limited partnership units of TransMontaigne Partners, we entered into an omnibus agreement, dated May 27, 2005 (the "Omnibus Agreement"), with TransMontaigne Partners, its general partner and certain of its subsidiaries. Pursuant to the Omnibus Agreement, subject to the detailed terms and conditions set forth therein:
- –>
- We
provide TransMontaigne Partners with administrative services, such as legal, accounting, treasury, insurance administration and claims processing, health, safety
and environmental compliance, information technology, human resources, credit, payroll, taxes and engineering and other corporate services. The administrative service arrangement has a
three-year term, subject to renewal for two-year periods, after which the general partner of TransMontaigne Partners will determine the general and administrative expenses that
will be allocated to TransMontaigne Partners.
- –>
- We also provide TransMontaigne Partners with insurance coverage. The insurance coverage arrangement also has an initial three-year term subject to renewal for subsequent two-year periods.
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- –>
- TransMontaigne
Partners has exclusive options to purchase from us additional refined product terminals and operations, including:
- –>
- our
terminal complex located in Brownsville, Texas with a current aggregate storage capacity of approximately 2.2 million barrels;
- –>
- our
refined product terminals located at various points along the Plantation and Colonial pipeline corridors, which extend from the Gulf Coast through the Southeast
and Mid-Atlantic regions, with a current aggregate storage capacity of approximately 8.9 million barrels; and
- –>
- our
refined product terminals located along the Mississippi and Ohio River areas, with a current aggregate storage capacity of approximately 3.2 million
barrels.
- –>
- We
have agreed to offer to sell to TransMontaigne Partners certain assets acquired or constructed by us in the future.
- –>
- We
have agreed to indemnify TransMontaigne Partners for certain liabilities related to environmental law compliance and real estate title matters.
- –>
- We have a right of first refusal to purchase assets owned by TransMontaigne Partners that are in the same line of business in which we are engaged, and certain storage capacity that becomes available in the future.
The option with respect to the Brownsville complex will be exercisable for one year beginning in January 2006. The option with respect to the terminals along the Plantation and Colonial pipeline corridors will be exercisable for one year beginning in December 2007. The option with respect to the terminals along the Mississippi and Ohio River areas will be exercisable for one year beginning in December 2008. The exercise of any of the options will be subject to the negotiation of a purchase price and a terminaling services agreement relating to the terminals proposed to be purchased and conditioned upon receipt of any necessary governmental or third party consents. If we cannot agree on a purchase price, we will have the right to seek an alternative purchaser willing to pay at least 105% of the purchase price proposed by TransMontaigne Partners. If an alternative transaction on such terms has not been consummated within six months, TransMontaigne Partners will have the right to purchase the assets at the price it originally proposed.
Additionally, subject to certain exclusions and conditions, we have agreed to offer to sell to TransMontaigne Partners any tangible assets having a value in excess of $10 million that we acquire or construct, related to the storage, transportation or terminaling of refined petroleum products in the United States. If TransMontaigne Partners declines any such offer, we will be free to retain and use the asset. If TransMontaigne Partners indicates a desire to purchase the assets, but we do not agree to all of the terms of the transaction, including the purchase price, after negotiating in good faith, we would have the right to seek an alternative purchaser willing to pay at least 105% of the purchase price proposed by TransMontaigne Partners. If an alternative transaction on such terms has not been consummated within six months, TransMontaigne Partners would have the right to purchase the assets at the purchase price originally proposed and on the other fundamental terms specified in the term sheet previously provided by us.
We also have agreed (1) to indemnify TransMontaigne Partners for five years against certain potential environmental claims, losses and expenses attributable to pre-closing operations, subject to a maximum liability for this indemnification obligation of $15.0 million, and (2) to indemnify TransMontaigne Partners for losses attributable to title defects, retained assets and liabilities and income taxes attributable to pre-closing operations.
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The Omnibus Agreement also provides that, if TransMontaigne Partners proposes to sell any assets that are in the same line of business in which we are engaged, we will have a right of first refusal to purchase such assets, provided that we agree to pay no less than 105% of the purchase price offered by a third-party bidder. We also will have a right of first refusal with respect to any petroleum product storage capacity that is put into commercial service by TransMontaigne Partners after May 27, 2005, and under certain other circumstances.
Terminaling and Transportation Services Agreement. Also in connection with TransMontaigne Partners' initial public offering, two of our operating subsidiaries, entered into a terminaling and transportation services agreement, dated May 27, 2005 (the "Terminaling Services Agreement"), with TransMontaigne Partners. Pursuant to the Terminaling Services Agreement, we agreed to transport product on the Razorback Pipeline and to throughput product in terminals owned by TransMontaigne Partners a volume of refined product that will result in minimum revenues to TransMontaigne Partners of $5.0 million per calendar quarter. In exchange for our minimum transportation and throughput commitment, TransMontaigne Partners agreed to provide us approximately 2.0 million barrels of light oil storage capacity and approximately 1.4 million barrels of heavy oil storage capacity at certain of TransMontaigne Partners' Florida terminals. If as a result of a force majeure event a party to the Terminaling Services Agreement is unable to perform under the agreement for a period over one year, then any party can terminate the Terminaling Services Agreement. After the initial term, the Terminaling Services Agreement will automatically renew for subsequent one-year periods, subject to either party's right to terminate with six months' notice. Upon termination of the Terminaling Services Agreement, we will have a right of first refusal giving us the right to enter into a new terminaling and transportation services agreement with TransMontaigne Partners, pursuant to which we will have the right to obtain any commercial terms offered to TransMontaigne Partners by a third party, provided we pay no less than 105% of the fees offered by such third party.
Petroleum imports and Gulf Coast production
United States crude oil production has declined from 6.8 million barrels per day in 1993 to 5.4 million barrels per day in 2004. Imports of crude oil from the Middle East, Europe, South America and elsewhere have increased substantially over this period from 6.8 million barrels per day in 1993 to 10.1 million barrels per day in 2004. Domestic crude oil production may be refined at any of the regional refineries around the United States. However, the imported crude oil generally is shipped by vessel into the Gulf Coast for processing at the large refining complexes. Crude oil production in the Gulf of Mexico, one of the largest sources of domestic production, also is refined primarily in these Gulf Coast refineries. The refined petroleum products then are shipped to other regions of the United States. We believe that this trend will lead to more refined petroleum product shipment from the Gulf Coast to the East Coast, Florida and Midwest, requiring additional transportation and storage capacity in the East Coast, Florida and Midwest.
Additionally, imports of refined petroleum products from Europe, South America and elsewhere have increased substantially from 1.8 million barrels per day in 1993 to 3.1 million barrels per day in 2004 to cover the shortfall in domestic refining capacity. Imports of refined petroleum products initially are unloaded at marine terminals generally in the Gulf Coast, Florida and East Coast. We believe that this trend of increasing imports of refined petroleum products will require additional transportation and storage capacity at marine terminals to the facilitate the distribution of refined product.
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Ownership of Terminals and Pipelines by Public Partnerships
Terminals and pipelines used in the petroleum industry increasingly have been acquired by publicly traded master limited partnerships. Master limited partnerships, or "MLPs," enjoy favorable tax treatment and therefore, generally have a lower cost of capital when compared to corporations. MLPs generally are required to distribute substantially all of their earnings to their unit holders. Most MLPs avoid commodity price risk and other risks because they seek business activities that generate stable and predictable earnings to permit the payment of a stable and predictable cash distribution. We believe that this trend of aggregation and ownership of mid-stream petroleum assets, such as terminals and pipelines, by MLPs will continue. To take advantage of this trend, we formed TransMontaigne Partners, a publicly traded master limited partnership, which completed its initial public offering on May 27, 2005. We believe that our ability to accept commodity price risk and other risks, combined with the favorable tax treatment afforded TransMontaigne Partners, gives us an advantage in negotiating for the acquisition of terminals and pipelines that other MLPs might not seek to acquire because of the associated commodity price risk and other risks.
The significance of Gulf Coast refining capacity has resulted in part from consolidation in the petroleum industry to take advantage of economies of scale associated with operating larger, concentrated refineries. The growth in refining capacity and increased product flow attributable to the Gulf Coast region has created a need for additional transportation, storage and distribution facilities in the Gulf Coast, East Coast, Florida and Midwest regions.
New sulfur regulations
In February 2002, the Environmental Protection Agency ("EPA"), promulgated the Tier 2 Motor Vehicle Emissions Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline. These regulations mandate that the average sulfur content of gasoline for highway use produced at any refinery not exceed 30 parts per million during any calendar year by January 1, 2006. In addition, in January 2001, the EPA promulgated its on-road diesel regulations, which will require a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006. Regulations for off-road diesel equipment also are pending. The stricter regulations will require refining companies to make significant capital expenditures to upgrade their facilities to comply with the new standards. Because of the technical sophistication and the capital outlays that will be required for compliance with such regulations, the large oil companies with major refining operations in the Gulf Coast are expected to be better prepared to meet the new standards than the smaller independent refiners. We believe that these trends will lead to more refined petroleum product shipments from the Gulf Coast to the Midwest and East Coast, requiring additional transportation and storage capacity in the Midwest and East Coast.
Consolidation and specialization
In the 1990's, the petroleum industry entered a period of consolidation and specialization.
- –>
- Refiners and marketers began to pursue development of large-scale, cost-efficient operations, thus leading to several refinery acquisitions, alliances and joint ventures. The companies involved in several of the mergers of large oil companies have sold retail and terminal assets in order to rationalize merged operations, and to comply with legal requirements to divest assets in certain geographic markets.
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- –>
- Major oil companies also began to re-deploy their resources to focus on their core competencies of exploration and production, refining and retail marketing. Industry participants have sought to sell portions of their proprietary transportation and storage and distribution networks.
This industry trend towards consolidation and specialization has created opportunities to capitalize on storage and distribution services. We expect that acquisition opportunities will continue to be generated as this trend continues.
Hypermarkets and alternative retail gasoline outlets
The retail distribution of gasoline is experiencing a transformation as consumer consumption patterns are moving away from gasoline distributed at the retail outlets of large oil companies, or "branded gasoline," toward unbranded gasoline from independent retail outlets offering lower prices and convenient locations. For example, many hypermarkets, grocery stores, convenience stores, discount retailers and wholesale outlets have installed gasoline pumps in their parking lots as a way to expand their product and service offerings and to allow their customers the benefit of "one-stop shopping." The increase in popularity of unbranded outlets has created new sales and distribution opportunities for independent petroleum marketing and distribution companies.
High refined product prices and concerns regarding availability of supply
In recent periods, prices for crude oil and refined petroleum products have increased substantially. In addition, market participants are concerned that various factors, including limited global refining capacity, political instability and other circumstances, may lead to reduced supply relative to demand. These factors are leading more distributors and end-users of refined petroleum products to seek reliable, committed sources for their supply. This increased demand for contracted volumes has created additional sales opportunities for independent petroleum marketing and distribution companies.
We believe that we have the following competitive strengths, which allow us to take advantage of the industry trends outlined above:
Significant asset base and shipping history
The Gulf Coast is a large shipper of refined petroleum products to the East Coast, Florida and Midwest regions. We have access to a geographically diverse network of terminals that allows us to take advantage of the differences between supply in the Gulf Coast and demand in the East Coast, Florida and Midwest. The size of this network of terminals, both in terms of number of terminals and total storage capacity, compares favorably with any integrated oil company.
This geographic diversity also allows us to quickly sell our product inventory from time to time in one or more locations while maximizing value to us. Our product supply agreement with Morgan Stanley Capital Group, Inc. allows us to direct the delivery of large volumes of products over the Colonial and Plantation pipelines to our terminals and third-party terminals. This arrangement provides us the benefit of allocated space on these common carrier pipelines during high demand periods, which is a competitive advantage when pipeline capacity is over-subscribed.
We believe that we will be able to further capitalize on our network of terminals and terminal capacity in the Gulf Coast, East Coast, Florida and Midwest following implementation of the new sulfur standards promulgated by the EPA. We anticipate that refining companies will be required to make significant capital expenditures to upgrade facilities to comply with such new sulfur regulations. Because of the technical sophistication and the capital outlays that will be required for compliance
20
with such regulations, we expect that the large oil companies with major refining operations in the Gulf Coast will gain a competitive advantage over the smaller independent refiners. We believe that this will lead to an increase in the volume of petroleum product shipments from the Gulf Coast to the East Coast, Florida and Midwest and require additional storage capacity in the East Coast, Florida and Midwest, providing additional growth opportunities for us.
Ability to link asset base, product supply and management services
Our supply, distribution and marketing operations and our terminal, pipeline and tug and barge operations each utilize and benefit from each other, creating opportunities to realize additional value in each of our business segments that could not be realized if each business segment were operated independently.
Our supply, distribution and marketing operations generally use our terminal and tug and barge infrastructure and TransMontaigne Partner's terminal and pipeline infrastructure to market various products and provide specialized supply, logistical and risk management services to our customers. A significant portion of the throughput on our terminal infrastructure is driven by our own supply, distribution and marketing business. As a result, we do not rely solely on third parties for our throughput activity.
We own and operate terminals located throughout the regions served by four major petroleum product pipelines along which we can direct the delivery of significant volumes of product. Also, we own and operate a dock strategically located on the Mississippi River with an interconnection to the Colonial Pipeline. We also have substantial experience in managing complex petroleum product supply and demand arrangements, utilizing equipment and software that allow us to monitor supplies in all of our facilities on a daily basis.
Because we link our asset base with our supply, distribution and marketing operations, we have the flexibility to market product during adverse market conditions to meet our contractual volume obligations and generate throughput revenues.
Supply chain management services
In order to operate more efficiently and to reduce overhead costs, many companies and governmental entities have begun to outsource their fuel supply function. This trend is creating an emerging market for services that allow these customers to focus their efforts on their core competencies and to reduce the price volatility associated with fuel supply for budgetary reasons. We provide a broad scope of services that include fuel supply, monitoring, excise tax administration and price management solutions, allowing our customers to obtain all of the required fuel supply chain management functions from a single source. We believe that we are the only significant independent fuel supply chain management services provider in the United States offering this extensive suite of services.
Technology and back-office infrastructure
We have assembled monitoring equipment and software to create an integrated, flexible system that allows us to effectively manage petroleum products throughout all of the terminals that we market from on a real time basis.
All of our and TransMontaigne Partners' terminals are equipped with equipment to monitor product supplies and outflows as well as for any environmentally harmful releases of product, such as leaks or spills. This equipment is interconnected electronically with our central inventory management office and automatically reports inventory levels in each facility several times daily. The electronic linkage
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between the terminals and our supply, distribution and marketing operations creates an inherent competitive strength by allowing us to make real time decisions on product purchases and sales.
We use a magnetic card system at each terminal that allows us to control product sales deliveries and also allows us to manage our credit risk exposure. Each of our rack customers is given a magnetic card that can be used only at the terminals we operate. Upon arrival at the rack, the driver of the truck swipes the magnetic card and inputs a product and volume request. This information is processed through our computerized inventory management system to determine the credentials of the carrier and whether the driver's product and volume request is within the customer's allocation of product for that month. The system also determines if the customer is current in its payments to us. If it is determined that the customer's allocation of product already has been drawn or if the customer is delinquent in paying its invoices to us, then the sale will not be allowed. The magnetic card system at each terminal is interconnected with our inventory management and billing system.
We also use a proprietary web-based system in our supply chain management services business that allows us to provide refined petroleum product procurement, inventory management, scheduling, routing and excise tax and consolidated billing services to our customers. Through our relationship with a credit card processing company, we provide integrated billing services to our supply chain management services customers. These customers receive fleet credit cards that are distributed to their fleet vehicle operators for use in purchasing gasoline at any retail gasoline station that accepts credit cards as a method of payment. On a daily basis, we receive information on these accounts electronically from the credit card processing company into our billing system. This information is posted on our web-based system, which can be accessed by our supply chain management services customers, allowing them to closely monitor fuel usage and costs by vehicle on a real time basis.
The refined petroleum products that arrive at terminals do not have excise taxes included in their price. At the time the products are sold over the rack, however, excise tax must be added to the price and paid by the purchasers of our products. The process of calculating, collecting, paying and reporting the excise taxes imposed by state and federal authorities requires extensive knowledge, expertise and administrative infrastructure. For example, we may make a delivery of gasoline at our rack that is located in one state to a truck that will transport the fuel to a neighboring state. Because taxation rules differ among locations, we must keep track of where the fuel will be ultimately delivered, charge the appropriate excise tax and file excise tax returns in the appropriate jurisdictions. We have developed an infrastructure to administer excise taxes on product that we handle.
The goal of our business strategies is to enhance our position as a leading independent provider of integrated refined petroleum products terminal, storage, supply, distribution and marketing services. To achieve this goal, our strategies are:
- –>
- To
procure adequate supplies of refined petroleum products to deliver to our customers in order to generate more contract sales and secure favorable marketing
margins.
- –>
- To
market our supply chain management services to additional customers with large ground transportation fleets.
- –>
- To
actively market our supply chain management solution for managing and obtaining excise tax exemptions on fuel purchases to government fleet customers.
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- To capitalize on our product supply arrangement with Morgan Stanley Capital Group, Inc., which allows us to reduce our investment in inventories of refined products and the related borrowings
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under our senior secured working capital credit facility. The resulting increase in borrowing capacity allows us to focus our financial resources on expanding our business, including through acquisitions and organic expansion.
- –>
- To
acquire additional terminal and storage facilities that will either complement our existing asset base and distribution capabilities, or provide entry into new
markets. We intend to expand the number and size of our terminal facilities, particularly marine facilities, to
handle the importation of refined petroleum products. To the extent these facilities produce qualifying income and have a value in excess of $10 million, these additional facilities will be
subject to an option in favor of TransMontaigne Partners to purchase them at fair value under the Omnibus Agreement between us and TransMontaigne Partners.
- –>
- To
capitalize on our infrastructure by linking our and TransMontaigne Partners' significant asset base to our supply, distribution and marketing business.
- –>
- To use our significant terminal storage capacity to meet the growing demand for boutique blends of gasoline spurred by recent and anticipated changes in government regulations.
Environmental and Regulatory 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 in the future. The trend in environmental regulation is to place more restrictions and limitations on activities that may impact the environment, such as 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 the costs of compliance with environmental laws and regulations may continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We do not anticipate 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 of compliance.
TransMontaigne Inc.'s operations require environmental permits under various federal, state and local environmental statutes and regulations. The cost involved in obtaining and renewing these permits is not material.
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 for various civil and criminal penalties and liabilities in the event 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
23
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. A containment berm is an earthen or cement barrier, impervious to liquids, which surrounds a storage tank holding between 1,000 and 500,000 gallons of petroleum products or other hazardous materials and used to prevent spilling and extensive damage to the environment. The berm is a form of secondary containment with the storage tank itself being the primary instrument of containment.
Contamination resulting from spills or releases of refined petroleum products is an inherent risk in 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 often unpredictable and are site specific and, therefore, the effect may 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. 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 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 obtain permits to discharge certain storm water run-off. Storm water discharge permits also may be required by certain states in which we operate. Such permits may require us to monitor and sample the effluent from our operations. We believe that we are in material compliance with effluent limitations at our facilities.
Water permits are required for various types of terminal storm water discharges. There are no TransMontaigne Inc. terminal locations that discharge any type of process wastewater. Terminal storm water discharges generally fall into two categories: petroleum contact and non-contact. The sources of contact water are the truck loading operations at some of the terminals. Many TransMontaigne Inc. terminal locations do not have contact water discharges, and thus no need for discharge permits, by virtue of employment of closed-loop water handling systems. The water generated in these systems is transported offsite and reclaimed. At locations where contact water is discharged on site, permit conditions dictate control technology requirements, effluent limitations and confirmation sampling. Non-contact storm water is generated at most terminal locations, primarily from rainfall collection in aboveground storage tank secondary containment enclosures or dikes. Various types of permits regulate these discharges, with most being "General" state-wide industry specific mechanisms. The cost involved in obtaining and renewing these permits is not material.
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 require most industrial operations in the United States to incur capital expenditures 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 to install various levels of control technology on sources of pollutants. Some of our facilities have been included within the categories of hazardous
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air pollutant sources. The Clean Air Act regulations are still being implemented by the EPA and state agencies. We believe that we are in material compliance with existing standards and regulations pursuant to the Clean Air Act and similar state and local laws, and we do not anticipate that implementation of additional regulations will have a material adverse effect on us.
Air permits are required for TransMontaigne Inc.'s terminaling operations that result in the emission of regulated air contaminants. These operations in general include fugitive volatile organic compounds (primarily hydrocarbons) from truck loading activities and tank working losses. The sources of these emissions are strictly regulated through the permitting process. Such regulation includes stringent control technology, extensive permit review and periodic renewal. The cost involved in obtaining and renewing these permits is not material.
CERCLA
Other than Coastal Fuels Marketing Inc. ("CFMI"), neither TransMontaigne Inc. nor any of its subsidiaries is a named party in any Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") related action. CFMI, which is now a wholly owned subsidiary of TransMontaigne Inc., had been named as a PRP in four State of Florida CERCLA actions which originated from waste disposal by third parties at off-site locations prior to TransMontaigne Inc.'s acquisition of CFMI from El Paso Corporation in 2003. TransMontaigne Inc. has been indemnified by El Paso for any costs TransMontaigne Inc. may incur for these issues. Due diligence research at the time of the acquisition of CFMI indicated that El Paso would not be likely to incur any future costs related to these actions; a worst-case analysis estimated El Paso's potential exposure at a total of $850,000. The likelihood of a worst-case scenario developing continues to diminish with the passage of time. CFMI transferred the former CFMI terminals in Florida to TransMontaigne Partners in connection with TransMontaigne Partners' formation and initial public offering transactions. In connection with that transfer, pursuant to the omnibus agreement between TransMontaigne Inc. and TransMontaigne Partners, TransMontaigne Inc. agreed to indemnify TransMontaigne Partners for a period of five years against up to $15 million of environmental liabilities that arise as a result of past activities. Similarly, TransMontaigne Partners agreed to indemnify TransMontaigne Inc. against environmental liabilities arising from activities occurring after May 27, 2005.
All of TransMontaigne Inc.'s terminal facilities are classified by the United States EPA as Conditionally Exempt Small Quantity Generators and do not generate hazardous waste except on isolated and infrequent cases. At such times, only third party disposal sites, which have been audited and approved by TransMontaigne Inc., are used.
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 and also to permit access to and copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that we are in material compliance with these HLPSA regulations.
OPS regulations require qualification of pipeline personnel. These regulations require 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
25
qualification requirements for individuals performing covered tasks, and amends certain training requirements in existing regulations. We believe that we are in material compliance with these OPS regulations.
We also are subject to OPS regulation for High Consequence Areas ("HCAs"), 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. 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, which is owned by TransMontaigne Partners and operated by TransMontaigne Inc.; (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. 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. The program requires periodic review of pipeline segments in HCAs to ensure adequate preventative and mitigative measures exist. Through this program, we evaluated 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 date. We believe that we are in material compliance with the OPS regulation of HCAs.
We also are subject to the requirements of the federal Occupational Safety and Health Act ("OSHA"), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, 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. 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.
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. Although we cannot estimate the magnitude of such expenditures at this time, we do not believe that they will have a material adverse impact on our results of operations.
Other Regulations
We also are subject to the Jones Act and the Merchant Marine Act of 1936 because of our ownership and operation of ocean vessels. Numerous other federal, state and local rules regulate our operations pursuant to which governmental agencies have the ability to suspend, curtail or modify our operations. We believe that we are in material compliance with these regulations.
Operational Hazards and Insurance
Our terminal and pipeline facilities may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of
26
property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and properties.
The insurance covers all of our assets in amounts that we consider to be reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. The events of September 11, 2001, and their overall effect on the insurance industry have adversely impacted the availability and cost of coverage. Due to these events, insurers have excluded acts of terrorism and sabotage from our insurance policies. On certain of our key assets, we have purchased a separate insurance policy for acts of terrorism and sabotage.
Competition
We face intense competition in our terminal and pipeline operations as well as in our supply and marketing operations. Our competitors include other terminal and pipeline companies, the major integrated oil companies, their marketing affiliates and independent gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours, and control greater supplies of refined petroleum products. For additional information on how these competitive factors may affect our operations, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors."
Employees
We had 727 employees at August 29, 2005, of which 36 employees are subject to representation by a union for collective bargaining purposes. Such employees recently joined us through the acquisition of Radcliff/Economy Marine Services, Inc. on August 1, 2005.
Market and Industry Data
Market and industry data and other statistical information used throughout this report are based on independent industry publications by market research firms or other published independent sources. Some data are also based on our good faith estimates, which are derived from our review of internal surveys, as well as the independent sources. Although we believe these sources are reliable, we have not independently verified the information derived from independent sources.
27
The locations and approximate shell capacity of our terminals (all of which are owned by us or TransMontaigne Partners) as of June 30, 2005 are as follows:
| Locations |
Approximate Shell Capacity (in barrels) |
|
|---|---|---|
| Southeast Facilities: | ||
| Albany, GA | 131,000 | |
| Americus, GA | 31,000 | |
| Athens, GA | 77,000 | |
| Atlanta, GA | 116,000 | |
| Bainbridge, GA | 99,000 | |
| Belton, SC | 130,000 | |
| Belton, SC—Piedmont | 297,000 | |
| Birmingham, AL | 370,000 | |
| Charlotte, NC | 223,000 | |
| Charlotte, NC—Piedmont | 324,000 | |
| Collins, MS | 138,000 | |
| Collins, MS (Pipeline Injection Facility) | 1,470,000 | |
| Doraville, GA—Piedmont | 436,000 | |
| Fairfax, VA | 502,000 | |
| Greensboro, NC | 181,000 | |
| Greensboro, NC—Piedmont | 435,000 | |
| Griffin, GA | 51,000 | |
| Lookout Mountain, GA | 109,000 | |
| Macon, GA | 100,000 | |
| Meridian, MS | 82,000 | |
| Montgomery, AL | 59,000 | |
| Montvale, VA | 489,000 | |
| Norfolk, VA | 673,000 | |
| Purvis, MS | 1,000,000 | |
| Richmond, VA | 459,000 | |
| Rome, GA | 59,000 | |
| Selma, NC—Piedmont | 507,000 | |
| Spartanburg, SC | 85,000 | |
| Spartanburg, SC—Piedmont | 305,000 | |
| Total | 8,938,000 | |
Other Facilities: |
||
| Rensselaer, NY | 530,000 | |
| Chippewa Falls, WI | 126,000 | |
| Total | 656,000 | |
River Facilities: |
||
| Baton Rouge, LA—Dock facility | — | |
| Arkansas City, AR | 773,000 | |
| Greenville, MS Complex | 528,000 | |
| Evansville, IN | 239,000 | |
| Greater Cincinnati, KY (Covington) | 191,000 | |
| Henderson, KY | 273,000 | |
| New Albany, IN | 219,000 | |
| Louisville, KY | 138,000 | |
| Cape Girardeau, MO | 140,000 | |
| East Liverpool, OH | 219,000 | |
| Owensboro, KY | 152,000 | |
| Paducah, KY Complex | 306,000 | |
| Total | 3,178,000 | |
Brownsville Facilities: |
||
| Brownsville, TX Complex | 2,240,000 | |
| Total | 2,240,000 | |
TransMontaigne Partners Facilities: |
||
| Mount Vernon, MO | 220,000 | |
| Rogers, AR | 180,000 | |
| Jacksonville, FL | 390,000 | |
| Cape Canaveral, FL | 730,000 | |
| Port Everglades (North), FL | 1,600,000 | |
| Port Everglades (South), FL | 370,000 | |
| Fisher Island, FL | 670,000 | |
| Port Manatee, FL | 1,530,000 | |
| Tampa, FL | 500,000 | |
| Total | 6,190,000 | |
| TOTAL CAPACITY | 21,202,000 | |
28
The name, approximate length in miles and geographical location of TransMontaigne Partners' pipeline as of June 30, 2005 is as follows:
| Pipeline Name |
Approximate Miles of Pipeline |
Geographical Location |
||
|---|---|---|---|---|
| Razorback | 67 | Mt. Vernon, Missouri south to Rogers, Arkansas | ||
Our executive offices are located at 1670 Broadway, Suite 3100, Denver, CO 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.
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. Coastal Fuels Marketing, Inc. "CFMI", a wholly-owned subsidiary, has been named as a potentially responsible party in four State of Florida CERCLA actions, which originated from waste disposal by third parties at off-site locations prior to our acquisition of CFMI from El Paso Corporation in 2003. El Paso Corporation has agreed to indemnify us for any costs we may incur for these matters. For a more detailed discussion of this matter, see "Item 1. Business—Environmental and Regulatory Matters; CERCLA." 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the TransMontaigne Inc. Annual Meeting of Stockholders held on May 5, 2005, the stockholders of TransMontaigne Inc. elected nine directors to serve until the next Annual Meeting of Stockholders and until their successors have been elected and qualified.
The following persons were elected as directors:
| |
Votes For |
Votes Withheld |
||
|---|---|---|---|---|
| Cortlandt S. Dietler | 31,134,623 | 1,107,584 | ||
| Donald H. Anderson | 31,254,912 | 987,295 | ||
| John A. Hill | 31,472,857 | 769,350 | ||
| Bryan H. Lawrence | 28,803,765 | 2,438,442 | ||
| Harold R. Logan, Jr. | 31,132,668 | 1,109,539 | ||
| Edwin H. Morgens | 28,872,565 | 3,369,642 | ||
| Wayne W. Murdy | 31,294,668 | 947,539 | ||
| Walter P. Schuetze | 31,294,168 | 948,039 | ||
There were no other directors whose term of office continued after the meeting.
29
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock currently is traded on the New York Stock Exchange under the symbol "TMG." Through May 4, 2005 our common stock traded on the American Stock Exchange. 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 applicable stock exchange.
| |
Low |
High |
||||
|---|---|---|---|---|---|---|
| July 1, 2003 through September 30, 2003 | $ | 5.14 | $ | 6.20 | ||
| October 1, 2003 through December 31, 2003 | $ | 5.78 | $ | 6.45 | ||
| January 1, 2004 through March 31, 2004 | $ | 5.50 | $ | 7.23 | ||
| April 1, 2004 through June 30, 2004 | $ | 4.65 | $ | 6.43 | ||
July 1, 2004 through September 30, 2004 |
$ |
5.15 |
$ |
7.25 |
||
| October 1, 2004 through December 31, 2004 | $ | 5.26 | $ | 6.34 | ||
| January 1, 2005 through March 31, 2005 | $ | 6.10 | $ | 9.12 | ||
| April 1, 2005 through June 30, 2005 | $ | 6.95 | $ | 10.50 | ||
As of August 29, 2005, there were 464 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.
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 Senior Secured Working Capital Credit Facility, 91/8% Senior Subordinated Notes due 2010 and certificate of designations of our Series B Redeemable Convertible Preferred stock contain restrictions on the payment of dividends on our common stock. Our Senior Secured Working Capital Credit Facility and Senior Subordinated Notes restrict the payment of cash dividends on our common stock unless we comply with certain financial covenants relating to restricted payments. Our Series B Redeemable Convertible 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 Series B Redeemable Convertible Preferred stock.
30
Following is a summary of common stock repurchases for the quarter ended June 30, 2005 (in thousands, except average price per share):
| Period |
Total Number of Shares Purchased |
Average Price Paid per Share |
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |
Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs |
||||||
|---|---|---|---|---|---|---|---|---|---|---|
| April 1, 2005 through April 30, 2005 | — | — | — | — | ||||||
| May 1, 2005 through May 31, 2005 | 1,514 | $ | 7.51 | N/A | (1) | N/A | (1) | |||
| June 1, 2005 through June 30, 2005 | — | — | — | — | ||||||
| Total | 1,514 | $ | 7.51 | |||||||
No common stock was repurchased for the periods April 1, 2005 through April 30, 2005 and June 1, 2005 through June 30, 2005.
For information on our equity compensation plans, see "Item 12. Security Ownership of Certain Beneficial Owners of Management—Equity Compensation Plan Information."
- (1)
- Common stock was repurchased from employees during the above period for withholding taxes as a result of vesting of common stock under our restricted stock plan (see Note 13 of Notes to consolidated financial statements).
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data for each of the years in the five-year period ended June 30, 2005, has been derived from our consolidated financial statements. You should not expect the results for any prior periods to be indicative of the results that may be achieved in future periods. You should read the following information together with our consolidated financial statements and related notes and with "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this annual report.
| |
Years Ended June 30, |
|||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003(4) |
2002 |
2001 |
|||||||||||
| |
(dollars in thousands) |
|||||||||||||||
| Statement of Operations Data: | ||||||||||||||||
| Supply, distribution and marketing: | ||||||||||||||||
| Revenues | $ | 8,437,795 | $ | 7,626,814 | $ | 5,520,684 | $ | 3,937,108 | $ | 3,793,339 | ||||||
| Less costs of products sold and other direct costs and expenses | (8,295,864 | ) | (7,554,012 | ) | (5,467,836 | ) | (3,868,361 | ) | (3,747,021 | ) | ||||||
| Net operating margin(1) | 141,931 | 72,802 | 52,848 | 68,747 | 46,318 | |||||||||||
| Terminals, pipelines, and tugs and barges: | ||||||||||||||||
| Revenues | 111,575 | 106,288 | 84,202 | 68,285 | 84,911 | |||||||||||
| Direct operating costs and expenses | (61,592 | ) | (57,181 | ) | (41,338 | ) | (32,567 | ) | (39,021 | ) | ||||||
| Net operating margin(1) | 49,983 | 49,107 | 42,864 | 35,718 | 45,890 | |||||||||||
| Total net operating margins(1) | $ | 191,914 | $ | 121,909 | $ | 95,712 | $ | 104,465 | $ | 92,208 | ||||||
31
| |
Years Ended June 30, |
||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003(4) |
2002 |
2001 |
||||||||||||
| |
(dollars in thousands) |
||||||||||||||||
| Total net operating margins(1) | $ | 191,914 | $ | 121,909 | $ | 95,712 | $ | 104,465 | $ | 92,208 | |||||||
| Costs and expenses: | |||||||||||||||||
| Selling, general and administrative | (42,849 | ) | (37,532 | ) | (38,328 | ) | (35,211 | ) | (34,072 | ) | |||||||
| Depreciation and amortization | (24,215 | ) | (23,015 | ) | (19,371 | ) | (16,556 | ) | (19,510 | ) | |||||||
| Lower of cost or market write-downs on product linefill and tank bottom volumes | — | (60 | ) | (633 | ) | (12,963 | ) | (18,318 | ) | ||||||||
| Corporate relocation and transition | — | — | (1,449 | ) | (6,316 | ) | — | ||||||||||
| Gain (loss) on disposition of assets, net | 129 | (978 | ) | — | (13 | ) | 22,146 | ||||||||||
| Operating income | 124,979 | 60,324 | 35,931 | 33,406 | 42,454 | ||||||||||||
| Interest expense, net | (24,244 | ) | (26,272 | ) | (14,419 | ) | (11,837 | ) | (15,215 | ) | |||||||
| Other expense, net | (5,102 | ) | (3,463 | ) | (4,902 | ) | (7,546 | ) | (9,235 | ) | |||||||
| Earnings before income taxes and non-controlling interests | 95,633 | 30,589 | 16,610 | 14,023 | 18,004 | ||||||||||||
| Income taxes | (39,253 | ) | (12,060 | ) | (8,510 | ) | (5,465 | ) | (6,666 | ) | |||||||
| Non-controlling interests share in earnings of TransMontaigne Partners | (562 | ) | — | — | — | — | |||||||||||
| Earnings before cumulative effect of a change in accounting principle | 55,818 | 18,529 | 8,100 | 8,558 | 11,338 | ||||||||||||
| Cumulative effect adjustment, net of tax benefit | — | — | (1,297 | ) | — | — | |||||||||||
| Net earnings | $ | 55,818 | $ | 18,529 | $ | 6,803 | $ | 8,558 | $ | 11,338 | |||||||
| Earnings (loss) per common share: | |||||||||||||||||
| Basic | $ | 1.10 | $ | 0.37 | $ | 0.07 | $ | (0.09 | ) | $ | 0.08 | ||||||
| Diluted | $ | 1.07 | $ | 0.36 | $ | 0.07 | $ | (0.09 | ) | $ | 0.08 | ||||||
| |
Years Ended June 30, |
|||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003(4) |
2002 |
2001 |
|||||||||||
| |
(dollars in thousands) |
|||||||||||||||
| Other Financial Data: | ||||||||||||||||
| Net cash provided (used) by operating activities | $ | 50,723 | $ | 69,704 | $ | 33,323 | $ | (101,512 | ) | $ | 51,936 | |||||
| Net cash provided (used) by investing activities | $ | (15,565 | ) | $ | (18,283 | ) | $ | (170,625 | ) | $ | 102,778 | $ | (18,969 | ) | ||
| Net cash provided (used) by financing activities | $ | (11,595 | ) | $ | (73,232 | ) | $ | 134,419 | $ | 3,811 | $ | (61,130 | ) | |||
| Total debt to total capital | 37.8 | % | 50.5 | % | 56.7 | % | 39.0 | % | 30.5 | % | ||||||
| Ratio of earnings to fixed charges(2) | 3.6 | x | 1.7 | x | 1.7 | x | 1.6 | x | 1.6 | x | ||||||
| |
June 30, |
||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003(4) |
2002 |
2001 |
||||||||||
| |
(dollars in thousands) |
||||||||||||||
| Balance Sheet Data: | |||||||||||||||
| Cash and cash equivalents | $ | 29,721 | $ | 6,158 | $ | 27,969 | $ | 30,852 | $ | 25,775 | |||||
| Working capital(3) | $ | 319,636 | $ | 118,320 | $ | 79,325 | $ | 168,092 | $ | 31,934 | |||||
| Total assets | $ | 1,141,981 | $ | 974,356 | $ | 1,020,466 | $ | 735,328 | $ | 712,365 | |||||
| Total debt | $ | 228,307 | $ | 311,923 | $ | 379,534 | $ | 198,312 | $ | 150,000 | |||||
| Total preferred stock | $ | 49,249 | $ | 77,719 | $ | 79,329 | $ | 105,360 | $ | 174,825 | |||||
| Non-controlling interests in TransMontaigne Partners | $ | 81,440 | $ | — | $ | — | $ | — | $ | — | |||||
| Total common stockholders' equity | $ | 326,484 | $ | 228,289 | $ | 210,269 | $ | 205,350 | $ | 167,550 | |||||
- (1)
- Net
operating margins represents revenues, less cost of product sold and other direct operating costs and expenses.
- (2)
- For
purposes of computing the ratio of earnings to fixed charges, "earnings" consists of earnings before income taxes plus fixed charges. "Fixed charges" represent interest incurred
(whether expensed or capitalized), amortization of deferred financing costs, and that portion of rental expense on operating leases deemed to be the equivalent of interest.
- (3)
- Working
capital is defined as current assets less current liabilities.
- (4)
- The consolidated financial statements include the results of operations of the Coastal Fuels assets from the closing date of the transaction (February 28, 2003).
32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of the results of operations and financial condition should be read in conjunction with the accompanying consolidated financial statements included elsewhere in this annual report.
CRITICAL ACCOUNTING POLICIES AND 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 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 that 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, 2005, our allowance for doubtful accounts was approximately $0.6 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, the customer's current financial condition, the current economic environment and the economic outlook for the future. At June 30, 2005, our trade accounts receivable balances that were more than 30 days past due totaled less than $5.0 million.
Inventories—Discretionary Volumes. At June 30, 2005, we held inventories—discretionary volumes with a cost basis of approximately $274.8 million and a fair value of approximately $277.1 million. Our inventories—discretionary volumes are carried at the lower of cost or market value in the accompanying consolidated balance sheet. For purposes of evaluating the financial performance of our business segments, our inventories—discretionary volumes held for immediate sale or exchange are reflected at market value. The market value of our inventories—discretionary volumes is based on quoted prices, when available. Our refined petroleum products inventories are traded in 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.
However, quoted prices are not available from brokers for all delivery locations in which we maintain discretionary volumes. When quoted prices are not available, the market value of our inventories—discretionary volumes held for immediate sale or exchange is based on the nearest quoted market price, plus quoted basis differentials to the various bulk market areas, plus the transportation cost to deliver the product from the bulk trading market to the city-specific markets. We utilize this valuation methodology for inventories—discretionary volumes held for immediate sale or exchange, along with any valuation of a related exchange imbalance with an exchange partner. At June 30, 2005, a $0.05 per gallon change in basis differentials would have changed the fair value of our inventories—discretionary volumes held for immediate sale or exchange by approximately $5.1 million.
33
Derivative Contracts. At June 30, 2005, we are a party to certain derivative contracts that require us to receive and deliver physical quantities of refined petroleum products over a specified term at a specified price. Our derivative contracts are carried at fair value in the accompanying consolidated balance sheets. At June 30, 2005, our net unrealized losses on derivative contracts were approximately $39.8 million. The valuation of our derivative 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 a combination of published 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, a throughput agreement or an exchange arrangement, fair value is determined by adding the near month NYMEX futures quote to the appropriate basis 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 differentials for certain deferred trading months and city-specific locations because we cannot secure a forward traded basis differential quote from a broker. In those situations, our mark-to-market model estimates the basis differentials based on a rolling historical average, which is updated quarterly. For our derivative contracts that settle against wholesale and retail pricing indices, we use a rolling historical average difference between the pricing index (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. For market locations in which we do not have access to product via our terminals, dedicated pipeline capacity, a throughput agreement or an 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 the bulk trading locations and the city-specific 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 differential to each city-specific location. At June 30, 2005, a $0.05 per gallon change in basis differentials would have changed the fair value of our derivative contracts, exclusive of risk management contracts, by approximately $3.5 million.
The estimated fair value of our delivered fuel price management and retail price management contracts at origination is deferred because our estimate of the fair value is not evidenced by quoted market prices or current market transactions for the contracts in their entirety. The deferred revenue is amortized into income over the respective terms of the contracts as the products are delivered to the ground fleet customers. Subsequent changes in the fair value of our delivered fuel price management and retail price management contracts are included in net operating margins attributable to our supply, distribution, and marketing operations.
Accrued Environmental Obligations. At June 30, 2005, our estimate of the future environmental costs to be incurred to remediate existing conditions attributable to past operations ranged from $2.8 million to $10.9 million. At June 30, 2005, we have an accrued liability of approximately $6.1 million as our best estimate of the undiscounted 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.
34
SIGNIFICANT DEVELOPMENTS DURING THE YEAR ENDED JUNE 30, 2005
On September 13, 2004, we entered into a new $400 million Senior Secured Working Capital Credit Facility among Wachovia Bank, National Association, as Agent, a syndicate of seventeen banks and other institutional lenders, JPMorgan Chase Bank and UBS AG Stamford Branch, as Syndication Agents, and Société Générale, New York Branch, and Wells Fargo Foothill, LLC, as Documentation Agents. Our operating subsidiaries, except for TransMontaigne Partners and its subsidiaries, have guaranteed our obligations under the Senior Secured Working Capital Credit Facility. The Senior Secured Working Capital Credit Facility replaced our $275 million Former Credit Facility.
On November 4, 2004, we executed a product supply agreement with Morgan Stanley Capital Group, Inc. ("MSCG"). The product supply agreement expires on December 31, 2011, subject to provisions for early termination. Under the terms of the product supply agreement, MSCG is our principal supplier of gasoline and distillate to our existing marketing and distribution business at terminals connected to the Colonial and Plantation pipelines and TransMontaigne Partners' Florida waterborne terminals at market-based rates. MSCG began supplying certain of these terminals during January 2005 and the remainder during February 2005.We accept title and risk of loss to the products from MSCG upon discharge of the products from the delivering pipelines and vessels into our tank storage capacity at the respective terminals. The product supply agreement resulted in us reducing our base operating inventory volumes from approximately 4.1 million barrels to approximately 2.0 million barrels. That reduction in base operating inventory volumes resulted principally from the liquidation of substantially all of our in-transit light oil volumes on common carrier pipelines to our Southeast terminal facilities and our in-transit light oil volumes on freight vessels to TransMontaigne Partners' Florida terminal facilities. As of June 30, 2005, our base operating volumes are represented principally by volumes stored in terminal facilities as safety stock to ensure an adequate supply of inventory to meet our delivery obligations to our customers, especially our contract customers. Product run-outs result from unexpected delays in the receipt of new shipments (e.g., weather delays, reduction in pipeline capacity, refinery outages) and product liftings by our contract customers in excess of their product allocations.
On November 23, 2004, in connection with the closing of the product supply agreement and as partial consideration for MSCG entering into the product supply agreement, we issued warrants to MSCG to purchase 5.5 million shares of our common stock at an exercise price equal to $6.60 per share, subject to adjustments in accordance with the terms and conditions of the warrant certificate.
On May 5, 2005, shares of our common stock began trading on the New York Stock Exchange under the symbol "TMG." Prior to May 5, 2005, shares of our common stock traded on the American Stock Exchange.
On May 27, 2005, TransMontaigne Partners, a consolidated subsidiary, completed its initial public offering of common units. TransMontaigne Partners received net proceeds of approximately $73.0 million for the issuance and sale of 3,852,500 common units, after giving effect to the exercise of the underwriters' over-allotment option, at the initial public offering price of $21.40 per common unit, and the payment of the underwriting discount, structuring fee and other offering costs of approximately $9.5 million.
On May 27, 2005, TransMontaigne Partners received approximately $7.9 million for the issuance and sale of 450,000 subordinated units to an affiliate of MSCG in a separate private placement at a price of $17.65 per subordinated unit.
We contributed seven refined products terminals located in Florida, the Razorback Pipeline, and two refined products terminals located in Mt. Vernon, Missouri and Rogers, Arkansas to TransMontaigne
35
Partners in exchange for a 2% general partner interest, 2,872,266 subordinated units, and a distribution of $111.5 million. We also entered into an omnibus agreement and terminaling and transportation services agreement with TransMontaigne Partners. The omnibus agreement sets forth the terms on which we will provide TransMontaigne Partners with certain general and administrative services, insurance coverage and environmental and other indemnification, among other terms. We also have agreed to provide TransMontaigne Partners with certain options and rights of first refusal to purchase additional refined peteroleum product terminal assets, and TransMontaigne Partners has agreed to provide us certain rights of first refusal with respect to its assets and additional terminal capacity added by TransMontaigne Partners in the future. Pursuant to the terminaling and transportation services agreement, we agreed to transport on TransMontaigne Partners' Razorback Pipeline and to throughput in TransMontaigne Partners' terminals a volume of refined product that will result in minimum revenues to TransMontaigne Partners of $5.0 million per calendar quarter. For additional information regarding the Omnibus Agreement and the Terminaling and Transportation Services Agreement, see "Item 1. Business—TransMontaigne Partners."
During the three months ended June 30, 2005, we revised our risk management policy to permit management the discretion to manage the commodity price risk relating to all discretionary volumes, including those volumes designated as base operating volumes and the undelivered in-transit volumes supplied to our terminals under the product supply agreement with MSCG. At June 30, 2005, we were managing the commodity price risk associated with approximately 1.0 million barrels of undelivered in-transit volumes supplied to our terminals under the product supply agreement with MSCG and approximately 0.5 million barrels of base operating volumes.
On July 20, 2005, TransMontaigne Partners announced that it declared a distribution of $0.15 per unit payable on August 9, 2005 to the unitholders of record on July 29, 2005.
On August 1, 2005, we announced the closing of the acquisition of Radcliff/Economy Marine Services, Inc. ("Radcliff") for a purchase price of approximately $53.4 million. The purchase price is composed of approximately $41 million payable in cash plus the assumption of Radcliff's existing outstanding debt of approximately $12.4 million. The acquisition includes three petroleum products terminals, two in Mobile, Alabama and one in Pensacola, Florida, with combined aggregate storage capacity of approximately 350,000 barrels. In addition, we acquired 2 tugboats, 7 barges, 12 tractors and associated trailers and approximately $22 million in net working capital. For the year ended December 31, 2004 and the seven months ended July 31, 2005, Radcliff generated earnings before depreciation, amortization, income taxes and interest expense of approximately $6.1 million and $5.1 million, respectively.
On August 16, 2005, we announced the signing of purchase agreements to acquire certain LPG assets and refined petroleum products tank capacity in Brownsville, Texas and Matamoros, Mexico from Rio Vista Energy Partners L.P. and Penn Octane Corporation for a total purchase price of approximately $27.5 million. The acquisition is anticipated to close on or before October 31, 2005 upon our completion of additional due diligence.
Subsequent to June 30, 2005, an additional 29,773 shares of Series B Redeemable Convertible Preferred stock were converted into approximately 4.5 million shares of common stock resulting in approximately 17,422 shares of Series B Redeemable Convertible Preferred stock outstanding as of August 23, 2005.
36
On August 29, 2005, Hurricane Katrina caused severe damage along the United States Gulf Coast and into the southeastern United States. Our facilities in the affected area, specifically our terminals in Mobile, Alabama, Pensacola, Florida and Collins, Mississippi, were flooded and without power for several days. Currently, these facilities have power and are delivering product in their respective markets. We currently are not aware of any significant long-term damage to these facilities.
RESULTS OF OPERATIONS—MARKET CONDITIONS
During the year ended June 30, 2005, we experienced a significant increase in refined petroleum product prices and the continued volatility of refined petroleum product prices.
Prices for refined petroleum products were higher during the three months and year ended June 30, 2005, as compared to the same periods in 2004, resulting in higher per unit revenues from the sales of refined petroleum products. Prices for gasoline and heating oil for the three months and year ended June 30, 2005 and 2004 are as follows (in $/gallon):
| |
Three months ended June 30, |
Year ended June 30, |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2005 |
2004 |
|||||||||
| Unleaded gasoline: | |||||||||||||
| High | $ | 1.6818 | $ | 1.4005 | $ | 1.6818 | $ | 1.4005 | |||||
| Low | $ | 1.3273 | $ | 1.0518 | $ | 0.9325 | $ | 0.7220 | |||||
| Average | $ | 1.4754 | $ | 1.2078 | $ | 1.3043 | $ | 0.9931 | |||||
Heating oil: |
|||||||||||||
| High | $ | 1.6468 | 1.0290 | 1.6468 | 1.0290 | ||||||||
| Low | $ | 1.3278 | 0.8195 | 1.0253 | 0.6690 | ||||||||
| Average | $ | 1.4914 | 0.9506 | 1.3306 | 0.8561 | ||||||||
37
Relative month-end commodity prices per gallon from June 30, 2001 to June 30, 2005 (near-month NYMEX close on the last day of the month) are as follows ($/gallon):
Our light oil marketing margins are affected by the supply and demand for light oil products in the wholesale delivery locations (e.g., terminal truck racks). While demand for light oil products may be influenced by seasonality (e.g., higher demand for gasoline during the summer driving season and higher demand for heating oil during the winter heating season), we believe that the availability of supply of light oil products in the wholesale delivery markets has the most significant impact on our ability to generate favorable light oil marketing margins. The availability of supply of light oil products in the wholesale delivery markets is impacted by a variety of factors, including the availability of crude oil supplies, current utilization of refining capacity, the shape of the forward price curve in the futures market, refinery crack spreads, and availability of pipeline and vessel shipping capacity. For example, adequate crude oil supplies, high utilization of refining capacity, an increasing forward price curve, favorable refinery crack spreads and available shipping capacity would likely result in an abundance of light oil products in the wholesale delivery markets. An abundance of light oil products in the wholesale delivery locations generally produces lower marketing margins. Conversely, tight crude oil supplies, refinery outages, a decreasing forward price curve, moderate refinery crack spreads and limited shipping capacity would likely result in tight supply of light oil products in the wholesale delivery markets. A tight supply of light oil products in the wholesale delivery locations generally produces higher marketing margins.
During the three months ended June 30, 2005, the NYMEX futures market anticipated rising gasoline and heating oil prices as the prices in the prompt month (i.e., the immediately succeeding month) were slightly higher than the prices in the current month. The combination of anticipated higher future prices (referred to as a "contango" market) and refinery crack spreads at historic highs encouraged refiners to maximize production and ship their gasoline and distillate production to the wholesale
38
delivery markets. The availability of gasolines and distillates in the wholesale delivery markets resulted in limited margin opportunities on gasoline and distillate sales in the wholesale delivery markets.
The value of petroleum products in any local delivery market is the sum of the commodity price as reflected on the NYMEX and the basis differential for that local delivery market. The basis differential for any local delivery market is the spread between the cash price in the physical market and the quoted price in the futures markets for the prompt month. For those physical and derivative positions as to which we choose to manage the associated commodity price risk, the primary objective of our risk management strategy is to minimize the financial impact on us from changes in petroleum commodity prices affected by world-wide crude oil and petroleum products supply and demand disruptions (e.g., the Iraq war, OPEC production quotas, disruptions due to hurricanes and other weather-related occurrences, foreign country work stoppages, and major refinery outages). We utilize NYMEX futures contracts to manage the financial impact on us from changes in commodity prices due to "world-wide" events. NYMEX futures contracts are obligations to purchase or sell a specific volume of inventory at a fixed price at a future date. We believe that the utilization of NYMEX futures contracts to manage commodity price risk minimizes the financial impact on us from changes in "world-wide" commodity prices. We generally do not manage the financial impact on us from changes in basis differentials affected by local market supply and demand disruptions (e.g., local pipeline delivery disruptions, local refinery outages, periodic change in local government specifications for gasolines and distillates, local seasonality in product demand, and disruptions due to local weather related occurrences). The impacts on us from changes in basis differentials are as follows:
| Basis Differential |
Change in Basis Differential |
Net Physical Position |
Financial Impact |
|||
|---|---|---|---|---|---|---|
| Futures price in excess of physical market price ("negative basis differential") | Increasing | Long | Loss | |||
| Futures price in excess of physical market price | Increasing | Short | Gain | |||
| Futures price in excess of physical market price | Decreasing | Long | Gain | |||
| Futures price in excess of physical market price | Decreasing | Short | Loss | |||
| Physical market price in excess of futures price ("positive basis differential") | Increasing | Long | Gain | |||
| Physical market price in excess of futures price | Increasing | Short | Loss | |||
| Physical market price in excess of futures price | Decreasing | Long | Loss | |||
| Physical market price in excess of futures price | Decreasing | Short | Gain | |||
39
The spread between the month-end basis differential (quoted near-month NYMEX futures price and the cash price in the United States Gulf Coast market) and the monthly average basis differential from June 30, 2002 to June 30, 2005 are as follows ($/gallon):
When we nominate refined petroleum products to be supplied by third parties at our terminals, we enter into futures contracts (i.e., short futures contracts) to sell a corresponding amount of product to protect against price fluctuations for the underlying commodity. When we ultimately sell the underlying inventory to a customer, we unwind the related risk management contract. In order to effectively manage commodity price risk, we must predict when we will sell the underlying product. When we enter into a forward sale commitment to deliver product to a customer in the future at a fixed price, we enter into a futures contract (i.e., a long futures contract) to purchase a corresponding amount of product to protect against price fluctuations for the underlying commodity. When we ultimately deliver the underlying product to a customer, we unwind the related risk management contract. We believe that the uncertainties of crude oil supply caused in part by the Iraq war, the possibility of unplanned refinery outages and the increased participation of hedge funds in the futures markets periodically results in a lack of correlation between the cash market and the futures market (i.e., the physical cash markets are driven by supply and demand, whereas, the futures markets are driven by geopolitical events and expectations). We continue to believe that there is a reasonably possible likelihood that in the future the refined petroleum products market will experience decreases in the correlation between the cash market and the futures market, similar to the decreases in correlation that occurred in August 2003 and May 2004 and the decrease in correlation that is occurring due to hurricane Katrina.
40
Because of the overall high level of commodity prices combined with the possibility of an increase in the cost of managing the commodity price risk associated with our discretionary inventories, we distributed and transported fewer barrels of discretionary inventories through our terminal infrastructure during the year ended June 30, 2005, which resulted in lower inventory volumes available for rack spot sales.
RESULTS OF OPERATIONS—BUSINESS SEGMENTS
We are required to report measures of profit and loss that are used by our chief operating decision maker (our Chief Executive Officer or CEO) in assessing the financial performance of our reportable segments. Our CEO assesses the financial performance of each of our reportable segments using a financial performance measure, which we refer to as "adjusted net operating margins."
Terminals, pipelines, tugs and barges—adjusted net operating margins
Our adjusted net operating margins for the terminal, pipelines, tugs and barges segment are identical to the net operating margins for such segment described under "Results of Operations—Historical Financial Statements." Selected quarterly adjusted net operating margins for the terminal, pipelines, tugs and barges segment for each of the quarters in the years ended June 30, 2005, 2004 and 2003 are summarized below (in thousands):
| |
Three Months Ended |
|
||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2005 |
|||||||||||||||||
| |
September 30, 2004 |
December 31, 2004 |
March 31, 2005 |
June 30, 2005 |
||||||||||||||
| Terminals, pipelines, tugs and barges: | ||||||||||||||||||
| TransMontaigne Partners L.P. facilities: | ||||||||||||||||||
| Revenues | $ | 8,392 | $ | 8,300 | $ | 9,714 | $ | 9,687 | $ | 36,093 | ||||||||
| Direct operating costs and expense | (4,086 | ) | (3,987 | ) | (4,059 | ) | (3,710 | ) | (15,842 | ) | ||||||||
| Net operating margins | 4,306 | 4,313 | 5,655 | 5,977 | 20,251 | |||||||||||||
| Brownsville facilities: | ||||||||||||||||||
| Revenues | 2,178 | 2,493 | 2,462 | 2,504 | 9,637 | |||||||||||||
| Direct operating costs and expense | (1,328 | ) | (1,289 | ) | (1,232 | ) | (1,255 | ) | (5,104 | ) | ||||||||
| Net operating margins | 850 | 1,204 | 1,230 | 1,249 | 4,533 | |||||||||||||
| Southeast facilities: | ||||||||||||||||||
| Revenues | 9,331 | 9,684 | 9,640 | 9,127 | 37,782 | |||||||||||||
| Direct operating costs and expense | (4,320 | ) | (3,886 | ) | (4,198 | ) | (4,873 | ) | (17,277 | ) | ||||||||
| Net operating margins | 5,011 | 5,798 | 5,442 | 4,254 | 20,505 | |||||||||||||
| River facilities: | ||||||||||||||||||
| Revenues | 2,234 | 2,240 | 2,668 | 2,434 | 9,576 | |||||||||||||
| Direct operating costs and expense | (1,583 | ) | (1,938 | ) | (1,523 | ) | (1,687 | ) | (6,731 | ) | ||||||||
| Net operating margins | 651 | 302 | 1,145 | 747 | 2,845 | |||||||||||||
| Other: | ||||||||||||||||||
| Revenues | 4,337 | 4,805 | 4,770 | 4,575 | 18,487 | |||||||||||||
| Direct operating costs and expense | (3,090 | ) | (4,354 | ) | (4,435 | ) | (4,759 | ) | (16,638 | ) | ||||||||
| Net operating margins | 1,247 | 451 | 335 | (184 | ) | 1,849 | ||||||||||||
| Total net operating margins | $ | 12,065 | $ | 12,068 | $ | 13,807 | $ | 12,043 | $ | 49,983 | ||||||||
41
| |
Three Months Ended |
|
||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2004 |
|||||||||||||||||
| |
September 30, 2003 |
December 31, 2003 |
March 31, 2004 |
June 30, 2004 |
||||||||||||||
| Terminals, pipelines, tugs and barges: | ||||||||||||||||||
| TransMontaigne Partners L.P. facilities: | ||||||||||||||||||
| Revenues | $ | 8,812 | $ | 8,020 | $ | 8,797 | $ | 8,808 | $ | 34,437 | ||||||||
| Direct operating costs and expense | (3,937 | ) | (3,079 | ) | (3,874 | ) | (3,923 | ) | (14,813 | ) | ||||||||
| Net operating margins | 4,875 | 4,941 | 4,923 | 4,885 | 19,624 | |||||||||||||
| Brownsville facilities: | ||||||||||||||||||
| Revenues | 2,156 | 1,888 | 2,243 | 2,206 | 8,493 | |||||||||||||
| Direct operating costs and expense | (1,539 | ) | (1,090 | ) | (1,382 | ) | (1,139 | ) | (5,150 | ) | ||||||||
| Net operating margins | 617 | 798 | 861 | 1,067 | 3,343 | |||||||||||||
| Southeast facilities: | ||||||||||||||||||
| Revenues | 8,814 | 9,085 | 9,000 | 8,323 | 35,222 | |||||||||||||
| Direct operating costs and expense | (3,843 | ) | (4,280 | ) | (4,278 | ) | (4,475 | ) | (16,876 | ) | ||||||||
| Net operating margins | 4,971 | 4,805 | 4,722 | 3,848 | 18,346 | |||||||||||||
| River facilities: | ||||||||||||||||||
| Revenues | 2,874 | 2,360 | 2,155 | 2,380 | 9,769 | |||||||||||||
| Direct operating costs and expense | (1,478 | ) | (1,395 | ) | (1,550 | ) | (1,795 | ) | (6,218 | ) | ||||||||
| Net operating margins | 1,396 | 965 | 605 | 585 | 3,551 | |||||||||||||
| Other: | ||||||||||||||||||
| Revenues | 4,526 | 4,725 | 4,608 | 4,508 | 18,367 | |||||||||||||
| Direct operating costs and expense | (3,348 | ) | (2,565 | ) | (4,132 | ) | (4,079 | ) | (14,124 | ) | ||||||||
| Net operating margins | 1,178 | 2,160 | 476 | 429 | 4,243 | |||||||||||||
| Total net operating margins | $ | 13,037 | $ | 13,669 | $ | 11,587 | $ | 10,814 | $ | 49,107 | ||||||||
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| |
Three Months Ended |
|
||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2003 |
|||||||||||||||||
| |
September 30, 2002 |
December 31, 2002 |
March 31, 2003 |
June 30, 2003 |
||||||||||||||
| Terminals, pipelines, tugs and barges: | ||||||||||||||||||
| TransMontaigne Partners L.P. facilities: | ||||||||||||||||||
| Revenues | $ | 2,069 | $ | 2,370 | $ | 4,490 | $ | 8,246 | $ | 17,175 | ||||||||
| Direct operating costs and expense | (581 | ) | (540 | ) | (1,522 | ) | (3,624 | ) | (6,267 | ) | ||||||||
| Net operating margins | 1,488 | 1,830 | 2,968 | 4,622 | 10,908 | |||||||||||||
| Brownsville facilities: | ||||||||||||||||||
| Revenues | 2,259 | 2,774 | 2,528 | 2,089 | 9,650 | |||||||||||||
| Direct operating costs and expense | (1,243 | ) | (1,585 | ) | (1,714 | ) | (1,694 | ) | (6,236 | ) | ||||||||
| Net operating margins | 1,016 | 1,189 | 814 | 395 | 3,414 | |||||||||||||
| Southeast facilities: | ||||||||||||||||||
| Revenues | 8,573 | 7,954 | 9,022 | 8,718 | 34,267 | |||||||||||||
| Direct operating costs and expense | (3,538 | ) | (3,475 | ) | (3,809 | ) | (3,845 | ) | (14,667 | ) | ||||||||
| Net operating margins | 5,035 | 4,479 | 5,213 | 4,873 | 19,600 | |||||||||||||
| River facilities: | ||||||||||||||||||
| Revenues | 3,279 | 2,988 | 2,810 | 3,260 | 12,337 | |||||||||||||
| Direct operating costs and expense | (1,669 | ) | (1,403 | ) | (1,300 | ) | (1,418 | ) | (5,790 | ) | ||||||||
| Net operating margins | 1,610 | 1,585 | 1,510 | 1,842 | 6,547 | |||||||||||||
| Other: | ||||||||||||||||||
| Revenues | 1,539 | 1,659 | 2,972 | 4,603 | 10,773 | |||||||||||||
| Direct operating costs and expense | (956 | ) | (1,081 | ) | (1,943 | ) | (4,398 | ) | (8,378 | ) | ||||||||
| Net operating margins | 583 | 578 | 1,029 | 205 | 2,395 | |||||||||||||
| Total net operating margins | $ | 9,732 | $ | 9,661 | $ | 11,534 | $ | 11,937 | $ | 42,864 | ||||||||
Supply, distribution and marketing—adjusted net operating margins
Our presentation of "adjusted net operating margins" for the supply, distribution and marketing segment differs from net operating margins for that segment as presented in our accompanying historical consolidated statement of operations due to the treatment of our inventories—discretionary volumes (which includes both volumes held for immediate sale or exchange and volumes held for base operating requirements) and purchase commitments under the MSCG supply agreement. Inventories—discretionary volumes held for immediate sale or exchange are reflected at fair value, which matches the treatment of our derivative contracts (e.g., volumes due to others under exchange agreements, forward purchase and sale agreements) and risk management contracts (principally NYMEX futures contracts). Because our inventories—discretionary volumes are composed of refined petroleum products, which are commodities with established trading markets and readily ascertainable market prices, we believe that the financial performance of our supply, distribution and marketing segment can be appropriately evaluated using the mark-to-market method. Our inventories—discretionary volumes are carried at the lower of cost or market in the accompanying historical consolidated balance sheets, while our derivative and risk management contracts are carried at fair value. As a result, if refined petroleum product prices are increasing during the end of a quarter, we may report in the accompanying historical statement of operations significant losses on derivative and risk management contracts and significant deferred gains on discretionary inventory volumes held for immediate sale or exchange at the end of that quarter and report significant gains on our beginning inventories—discretionary volumes held for immediate sale or exchange when they are sold in the following quarter.
43
Therefore, the effects of changes in the fair value of our inventories—discretionary volumes held for immediate sale or exchange are included in "adjusted net operating margins" attributable to our supply, distribution and marketing segment in the period in which the fair value actually changes.
Additionally, for purposes of computing our "adjusted net operating margins," our discretionary inventories—base operating volumes and the undelivered in-transit volumes supplied to our terminals by MSCG are maintained at original cost.
Marketing margins. Light oil and heavy oil marketing margins are based on the actual selling price to the customer, the cost of product sold and the standard cost of transportation and throughput. For purposes of computing our light oil margins, the cost of product sold is based on the prior day's market value of the product as determined in the United States Gulf Coast bulk market.
Supply chain management services margins include margins from the sale of refined petroleum products under delivered fuel price management contracts, net gains and losses from the settlement of retail price management contracts and fees from logistical supply chain management services. Margins under delivered fuel price management contracts are based on the relationship of the spread between the futures price and the physical wholesale market price at the date the contract was executed with the customer (referred to as "basis sold") and the spread between the futures price and the physical wholesale market price at the date the product was lifted by the customer (referred to as "basis bought"). Net gains and losses from the settlement of retail price management contracts are based on basis sold and basis bought in the retail market. Fees from logistical supply chain management services are charged on a per gallon basis for the use of our proprietary web-based inventory management system.
Bulk Activities and Other. Other financial and costing variances, net include the financial variances (favorable and unfavorable) associated with the correlation between the physical market and the futures market, the variance between our actual transportation and throughput charges and our standard costs, and the net margins generated from bulk transactions. During periods of strong correlation between the physical and futures markets, we will recognize nominal variances. During periods of expanding spreads between the cash price in the physical market and the quoted price in the futures markets for the prompt month, we will recognize gains (losses) if we are net short (long) in the physical market. During periods of contracting spreads between the cash price in the physical market and the quoted price in the futures markets for the prompt month, we will recognize gains (losses) if we are net long (short) in the physical market.
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The adjusted net operating margins attributable to our supply, distribution and marketing segment were $74.9 million in 2005, $35.7 million in 2004, and $58.1 million in 2003.
| |
Three Months Ended |
|
||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2005 |
|||||||||||||||||
| |
September 30, 2004 |
December 31, 2004 |
March 31, 2005 |
June 30, 2005 |
||||||||||||||
| Distribution and marketing: | ||||||||||||||||||
| Light oils—marketing margins: | ||||||||||||||||||
| TransMontaigne Partners L.P. facilities | $ | 2,700 | $ | 4,246 | $ | 1,666 | $ | 1,322 | $ | 9,934 | ||||||||
| Brownsville facilities | — | — | — | — | — | |||||||||||||
| Southeast facilities | 993 | 7,603 | 2,744 | 2,849 | 14,189 | |||||||||||||
| River facilities | 759 | 759 | 525 | 791 | 2,834 | |||||||||||||
| Other facilities | 36 | 136 | 60 | 79 | 311 | |||||||||||||
| 4,488 | 12,744 | 4,995 | 5,041 | 27,268 | ||||||||||||||
| Heavy oils—marketing margins | 2,570 | 5,406 | 2,980 | 2,164 | 13,120 | |||||||||||||
| Supply chain management services margins | 3,040 | 3,608 | 6,067 | 783 | 13,498 | |||||||||||||
| 10,098 | 21,758 | 14,042 | 7,988 | 53,886 | ||||||||||||||
Bulk activities and other: |
||||||||||||||||||
| Storage fees for light oil tank capacity | (2,245 | ) | (2,200 | ) | (857 | ) | (395 | ) | (5,697 | ) | ||||||||
| Other financial and costing variances, net | (2,204 | ) | 12,232 | 6,286 | (4,241 | ) | 12,073 | |||||||||||
| (4,449 | ) | 10,032 | 5,429 | (4,636 | ) | 6,376 | ||||||||||||
| Trading and risk management activities, net | (1,003 | ) | 10,649 | (181 | ) | 5,154 | 14,619 | |||||||||||
| Adjusted net operating margins | $ | 4,646 | $ | 42,439 | $ | 19,290 | $ | 8,506 | $ | 74,881 | ||||||||
Our light oil marketing margins in points ($0.0001) per gallon for each of the quarters in the year ended June 30, 2005 are as follows:
| |
Three Months Ended |
|
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2005 |
||||||||||
| |
September 30, 2004 |
December 31, 2004 |
March 31, 2005 |
June 30, 2005 |
|||||||
| Light oils—marketing margins: | |||||||||||
| TransMontaigne Partners' facilities | 110 | 184 | 64 | 48 | 98 | ||||||
| Southeast facilities | 18 | 150 | 51 | 51 | 66 | ||||||
| River facilities | 200 | 200 | 196 | 175 | 192 | ||||||
| Other facilities | 2 | 16 | 8 | 12 | 8 | ||||||
| 46 | 148 | 55 | 53 | 74 | |||||||
45
Our light oil marketing volumes in average barrels per day for each of the quarters in the year ended June 30, 2005 are as follows:
| |
Three Months Ended |
|
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2005 |
||||||||||
| |
September 30, 2004 |
December 31, 2004 |
March 31, 2005 |
June 30, 2005 |
|||||||
| Light oils—marketing volumes: | |||||||||||
| TransMontaigne Partners' facilities | 63,256 | 59,565 | 68,725 | 72,297 | 65,961 | ||||||
| Southeast facilities | 142,928 | 131,418 | 143,751 | 146,395 | 141,123 | ||||||
| River facilities | 9,800 | 9,800 | 7,091 | 11,816 | 9,627 | ||||||
| Other facilities | 38,104 | 21,875 | 19,901 | 17,369 | 24,312 | ||||||
| 254,088 | 222,658 | 239,468 | 247,877 | 241,023 | |||||||
During the three months ended March 31, 2005, we commenced purchasing light oil product from MSCG for our Florida and Southeast marketing activities. In anticipation of the liquidation of certain in-transit product inventory volumes upon complete implementation of the MSCG supply agreement, we entered into short positions in the NYMEX options market. Included in trading and risk management activities, net for the three months ended December 31, 2004, are net gains of approximately $10.6 million on the NYMEX options. Pursuant to the terms of the MSCG supply agreement, the unit cost of the products is determined prior to their actual delivery to our terminals. We generally do not manage the commodity price risk associated with the undelivered in-transit volumes supplied to our terminals under the MSCG supply agreement. Consequently, during rising commodity prices, we will recognize gains between the date the product is priced and the date of its receipt because the MSCG supply agreement qualifies as a derivative contract (see Note 1(g) of Notes to consolidated financial statements). During declining commodity prices, we will recognize losses between the pricing date and the date of receipt. At June 30, 2005, we were managing the commodity price risk associated with approximately 1.0 million barrels of the approximately 3.0 million barrels of undelivered in-transit volumes supplied to our terminals under the MSCG supply agreement.
We maintain base operating inventory volumes in terminal facilities as safety stock to ensure an adequate supply of inventory to meet our delivery obligations to our customers. We generally do not manage the commodity price risk associated with these inventory volumes. During periods of rising commodity prices, we will recognize increases in the value of these volumes, whereas during periods of declining commodity prices, we will recognize decreases in the value of these volumes. At June 30, 2005, we were managing the commodity price risk associated with approximately 0.5 million barrels of the approximately 2.0 million barrels of base operating inventory volumes in anticipation of the liquidation of certain base operating inventory volumes.
Included in trading and risk management activities, net for the three months ended June 30, 2005, are net gains of approximately $5.2 million on the risk management contracts used to manage the commodity price risk associated with base operating inventory volumes and light oil volumes nominated under the MSCG supply agreement.
Storage fees for light oil tank capacity decreased during the year ended June 30, 2005, due principally to the commencement of our terminaling services agreements with MSCG for tank capacity at our Southeast facilities that historically had been leased to our supply, distribution and marketing operations.
During the three months ended December 31, 2004, we purchased discretionary inventory volumes at a significant spread between the cash price in the physical market and the quoted price in the futures
46
markets for the prompt month. During the three months ended December 31, 2004 and March 31, 2005, we experienced a contracting spread between the cash price in the physical market and the quoted price in the futures markets for the prompt month during the liquidation of our discretionary inventory volumes, which resulted in the recognition of favorable financial and costing variances, net.
A reconciliation of adjusted net operating margins to net operating margins, as presented in the accompanying consolidated statement of operations for each of the quarters in the year ended June 30, 2005, is as follows (in thousands):
| |
Three Months Ended |
|
|||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2005 |
||||||||||||||||
| |
September 30, 2004 |
December 31, 2004 |
March 31, 2005 |
June 30, 2005 |
|||||||||||||
| Reconciliation to net operating margins: | |||||||||||||||||
| Adjusted net operating margins | $ | 4,646 | $ | 42,439 | $ | 19,290 | $ | 8,506 | $ | 74,881 | |||||||
| Gains recognized on beginning inventories—discretionary volumes held for immediate sale or exchange | 2,330 | 4,405 | 6,093 | 10,311 | 2,330 | ||||||||||||
| Gains deferred on ending inventories—discretionary volumes held for immediate sale or exchange | (4,405 | ) | (6,093 | ) | (10,311 | ) | (2,125 | ) | (2,125 | ) | |||||||
| Increase (decrease) in value of light oil volumes nominated under the MSCG supply agreement prior to delivery at our terminals | — | — | 36,632 | (9,497 | ) | 27,135 | |||||||||||
| Increase (decrease) in FIFO cost basis of base operating inventory volumes | 21,585 | (18,715 | ) | 32,769 | 8,339 | 43,978 | |||||||||||
| Lower of cost or market write-downs on base operating inventory volumes | — | (2,496 | ) | — | (1,772 | ) | (4,268 | ) | |||||||||
| Net operating margins—historical financial statements | $ | 24,156 | $ | 19,540 | $ | 84,473 | $ | 13,762 | $ | 141,931 | |||||||
Because of the significant increase in commodity prices experienced during the three months ended March 31, 2005, we recognized approximately $36.6 million of gains on approximately 3.0 million barrels, which represents the average volume of barrels priced under the terms of the MSCG supply agreement but not yet delivered to our terminals. During the three months ended June 30, 2005, we recognized approximately $9.5 million of losses due to declining commodity prices.
We maintain base operating inventory volumes in terminal facilities as safety stock to ensure an adequate supply of inventory to meet our delivery obligations to our customers. We generally do not manage the commodity price risk associated with these inventory volumes. During periods of rising commodity prices, we will recognize increases in the value of these volumes, whereas during periods of declining commodity prices, we will recognize decreases in the value of these volumes. During the year ended June 30, 2005, we increased the FIFO cost basis of our base operating inventory volumes by approximately $44.0 million due to rising commodity prices.
47
Selected quarterly adjusted net operating margins for the supply, distribution and marketing segment for each of the quarters in the year ended June 30, 2004, are summarized below (in thousands):
| |
Three Months Ended |
|
||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2004 |
|||||||||||||||||
| |
September 30, 2003 |
December 31, 2003 |
March 31, 2004 |
June 30, 2004 |
||||||||||||||
| Distribution and marketing: | ||||||||||||||||||
| Light oils—marketing margins: | ||||||||||||||||||
| TransMontaigne Partners L.P. facilities | $ | 803 | $ | 958 | $ | 3,548 | $ | 5,137 | $ | 10,446 | ||||||||
| Brownsville facilities | — | — | — | — | — | |||||||||||||
| Southeast facilities | (861 | ) | 2,670 | 4,128 | 3,100 | 9,037 | ||||||||||||
| River facilities | 1,237 | 828 | 1,078 | 2,025 | 5,168 | |||||||||||||
| Other facilities | 902 | 1,234 | 2,037 | 1,656 | 5,829 | |||||||||||||
| 2,081 | 5,690 | 10,791 | 11,918 | 30,480 | ||||||||||||||
| Heavy oils—marketing margins | 1,440 | 3,424 | 5,416 | 3,376 | 13,656 | |||||||||||||
| Supply chain management services margins | 2,351 | 4,070 | 2,783 | (580 | ) | 8,624 | ||||||||||||
| 5,872 | 13,184 | 18,990 | 14,714 | 52,760 | ||||||||||||||
| Bulk activities and other: | ||||||||||||||||||
| Storage fees for light oil tank capacity | (2,522 | ) | (2,495 | ) | (2,385 | ) | (2,309 | ) | (9,711 | ) | ||||||||
| Other financial and costing variances, net | 6,133 | 5,135 | (2,067 | ) | (15,694 | ) | (6,493 | ) | ||||||||||
| 3,611 | 2,640 | (4,452 | ) | (18,003 | ) | (16,204 | ) | |||||||||||
| Trading and risk management activities, net | 2,131 | 457 | (2,582 | ) | (829 | ) | (823 | ) | ||||||||||
| Adjusted net operating margins | $ | 11,614 | $ | 16,281 | $ | 11,956 | $ | (4,118 | ) | $ | 35,733 | |||||||
Our light oil marketing margins in points ($0.0001) per gallon for each of the quarters in the year ended June 30, 2004 are as follows:
| |
Three Months Ended |
|
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2004 |
||||||||||
| |
September 30, 2003 |
December 31, 2003 |
March 31, 2004 |
June 30, 2004 |
|||||||
| Light oils—marketing margins: | |||||||||||
| TransMontaigne Partners' facilities | 33 | 38 | 132 | 189 | 101 | ||||||
| Southeast facilities | (14 | ) | 44 | 66 | 51 | 37 | |||||
| River facilities | 142 | 131 | 176 | 259 | 178 | ||||||
| Other facilities | 43 | 71 | 106 | 93 | 77 | ||||||
| 18 | 52 | 95 | 104 | 67 | |||||||
48
Our light oil marketing volumes in average barrels per day for each of the quarters in the year ended June 30, 2004 are as follows:
| |
Three Months Ended |
|
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2004 |
||||||||||
| |
September 30, 2003 |
December 31, 2003 |
March 31, 2004 |
June 30, 2004 |
|||||||
| Light oils—marketing volumes: | |||||||||||
| TransMontaigne Partners' facilities | 62,392 | 65,456 | 70,108 | 71,117 | 67,268 | ||||||
| Southeast facilities | 161,070 | 157,366 | 164,297 | 160,209 | 160,736 | ||||||
| River facilities | 22,498 | 16,372 | 16,072 | 20,469 | 18,853 | ||||||
| Other facilities | 54,459 | 44,750 | 50,367 | 46,748 | 49,081 | ||||||
| 300,419 | 283,944 | 300,844 | 298,543 | 295,938 | |||||||
The adjusted net operating margins from our supply chain management services for the three months ended June 30, 2004 were adversely impacted by unfavorable retail basis spreads, principally in the West Coast markets.
During the three months ended June 30, 2004, we recognized net losses of approximately $14.5 million due to a lack of correlation between the cash and futures markets related to our gasoline volumes held for immediate sale or exchange.
A reconciliation of adjusted net operating margins to net operating margins, as presented in the accompanying consolidated statement of operations for each of the quarters in the year ended June 30, 2004, is as follows (in thousands):
| |
Three Months Ended |
|
|||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2004 |
||||||||||||||||
| |
September 30, 2003 |
December 31, 2003 |
March 31, 2004 |
June 30, 2004 |
|||||||||||||
| Reconciliation to net operating margins: | |||||||||||||||||
| Adjusted net operating margins | $ | 11,614 | $ | 16,281 | $ | 11,956 | $ | (4,118 | ) | $ | 35,733 | ||||||
| Gains recognized on beginning inventories—discretionary volumes held for immediate sale or exchange | 5,855 | 3,067 | 15,469 | 6,039 | 5,855 | ||||||||||||
| Gains deferred on ending inventories—discretionary volumes held for immediate sale or exchange | (3,067 | ) | (15,469 | ) | (6,039 | ) | (2,330 | ) | (2,330 | ) | |||||||
| Increase in FIFO cost basis of base operating inventory volumes | 214 | 5,504 | 21,494 | 11,666 | 38,878 | ||||||||||||
| Lower of cost or market write-downs on base operating inventory volumes | (2,062 | ) | (271 | ) | (128 | ) | (2,873 | ) | (5,334 | ) | |||||||
| Net operating margins—historical financial statements | $ | 12,554 | $ | 9,112 | $ | 42,752 | $ | 8,384 | $ | 72,802 | |||||||
During the year ended June 30, 2004, we increased the FIFO cost basis of our base operating inventory volumes by approximately $38.9 million due to rising commodity prices.
49
Selected quarterly adjusted net operating margins for the supply, distribution and marketing segment for each of the quarters in the year ended June 30, 2003, are summarized below (in thousands):
| |
Three Months Ended |
|
||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2003 |
|||||||||||||||||
| |
September 30, 2002 |
December 31, 2002 |
March 31, 2003 |
June 30, 2003 |
||||||||||||||
| Supply, distribution and marketing: | ||||||||||||||||||
| Light oils—marketing margins: | ||||||||||||||||||
| TransMontaigne Partners L.P. facilities | $ | 206 | $ | 502 | $ | 3,974 | $ | 7,627 | $ | 12,309 | ||||||||
| Brownsville facilities | — | — | — | — | — | |||||||||||||
| Southeast facilities | 2,909 | 2,170 | 4,210 | 5,045 | 14,334 | |||||||||||||
| River facilities | — | 28 | 686 | 2,554 | 3,268 | |||||||||||||
| Other facilities | 839 | 1,232 | 2,106 | 3,006 | 7,183 | |||||||||||||
| 3,954 | 3,932 | 10,976 | 18,232 | 37,094 | ||||||||||||||
| Heavy oils—marketing margins | — | — | 2,489 | 3,810 | 6,299 | |||||||||||||
| Supply chain management services margins | 4,382 | 3,158 | 3,530 | 1,947 | 13,017 | |||||||||||||
| 8,336 | 7,090 | 16,995 | 23,989 | 56,410 | ||||||||||||||
| Bulk activities and other: | ||||||||||||||||||
| Storage fees for light oil tank capacity | (2,185 | ) | (2,167 | ) | (2,394 | ) | (2,288 | ) | (9,034 | ) | ||||||||
| Other financial and costing variances, net |
4,858 | 8,402 | 27 | (1,445 | ) | 11,842 | ||||||||||||
| 2,673 | 6,235 | (2,367 | ) | (3,733 | ) | 2,808 | ||||||||||||
| Trading and risk management activities, net | (2,595 | ) | 640 | 30 | 786 | (1,139 | ) | |||||||||||
| Adjusted net operating margins | $ | 8,414 | $ | 13,965 | $ | 14,658 | $ | 21,042 | $ | 58,079 | ||||||||
Our light oil marketing margins in points ($0.0001) per gallon for each of the quarters in the year ended June 30, 2003 are as follows:
| |
Three Months Ended |
|
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2003 |
||||||||||
| |
September 30, 2002 |
December 31, 2002 |
March 31, 2003 |
June 30, 2003 |
|||||||
| Light oils—marketing margins: | |||||||||||
| TransMontaigne Partners' facilities | 18 | 38 | 219 | 338 | 188 | ||||||
| Southeast facilities | 50 | 41 | 71 | 87 | 63 | ||||||
| River facilities | (53 | ) | 24 | 244 | 288 | 253 | |||||
| Other facilities | 46 | 63 | 103 | 145 | 91 | ||||||
| 45 | 45 | 109 | 165 | 96 | |||||||
50
Our light oil marketing volumes in average barrels per day for each of the quarters in the year ended June 30, 2003 are as follows:
| |
Three Months Ended |
|
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2003 |
||||||||||
| |
September 30, 2002 |
December 31, 2002 |
March 31, 2003 |
June 30, 2003 |
|||||||
| Light oils—marketing volumes: | |||||||||||
| TransMontaigne Partners' facilities | 29,561 | 34,610 | 47,962 | 59,125 | 42,815 | ||||||
| Southeast facilities | 151,901 | 136,834 | 156,175 | 151,790 | 149,175 | ||||||
| River facilities | 9 | 3,079 | 7,445 | 23,184 | 8,429 | ||||||
| Other facilities | 47,079 | 50,500 | 54,066 | 54,282 | 51,482 | ||||||
| 228,550 | 225,023 | 265,648 | 288,381 | 251,901 | |||||||
On February 28, 2003, we acquired the Coastal Fuels assets, which contributed approximately $6.3 million in heavy oils—marketing margins.
A reconciliation of adjusted net operating margins to net operating margins, as presented in the accompanying consolidated statement of operations for each of the quarters in the year ended June 30, 2003, is as follows (in thousands):
| |
Three Months Ended |
|
|||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2003 |
||||||||||||||||
| |
September 30, 2002 |
December 31, 2002 |
March 31, 2003 |
June 30, 2003 |
|||||||||||||
| Reconciliation to net operating margins: | |||||||||||||||||
| Adjusted net operating margins | $ | 8,414 | $ | 13,965 | $ | 14,658 | $ | 21,042 | $ | 58,079 | |||||||
| Gains recognized on beginning inventories—discretionary volumes held for immediate sale or exchange | — | 12,644 | 33,490 | — | 12,644 | ||||||||||||
| Gains deferred on ending inventories—discretionary volumes held for immediate sale or exchange | — | (33,490 | ) | — | (5,855 | ) | (5,855 | ) | |||||||||
| Increase (decrease) in FIFO cost basis of base operating inventory volumes | — | (1,421 | ) | 9,723 | (7,887 | ) | 415 | ||||||||||
| Lower of cost or market write-downs on base operating inventory volumes |
— | — | (12,412 | ) | (23 | ) | (12,435 | ) | |||||||||
| Net operating margins—historical financial statements | $ | 8,414 | $ | (8,302 | ) | $ | 45,459 | $ | 7,277 | $ | 52,848 | ||||||
Prior to October 1, 2002, our inventories—discretionary volumes held for immediate sale or exchange were carried at fair value with changes in fair value included in net operating margins in the period of the change in value. Effective October 1, 2002, we adjusted the carrying amount of inventories—discretionary volumes to the lower of cost (FIFO) or market pursuant to the requirements of EITF 02-03. As of October 1, 2002, the fair value of our inventories—discretionary volumes held for immediate sale or exchange exceeded their cost basis by approximately $12.6 million.
Prior to October 1, 2002, our base operating inventory volumes were carried at original cost adjusted for impairment write-downs to current market values. Effective October 1, 2002, we adjusted the carrying amount of our base operating inventory to the lower of cost (FIFO) or market pursuant to the requirements of EITF 02-03. During the three months ended March 31, 2003 and June 30, 2003, we recognized impairment losses of approximately $12.4 million and $23,000, respectively, due to the application of the lower of cost or market rule on certain of our base operating inventory volumes.
51
RESULTS OF OPERATIONS—HISTORICAL FINANCIAL STATEMENTS
Selected annual results of operations data are summarized below (in thousands):
| |
Years ended June 30, |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
|||||||||
| Net operating margins(1): | ||||||||||||
| Supply, distribution and marketing | $ | 141,931 | $ | 72,802 | $ | 52,848 | ||||||
| Terminals, pipelines and tugs and barges | 49,983 | 49,107 | 42,864 | |||||||||
| Total net operating margins | 191,914 | 121,909 | 95,712 | |||||||||
| Selling, general and administrative expenses | (42,849 | ) | (37,532 | ) | (38,328 | ) | ||||||
| Depreciation and amortization | (24,215 | ) | (23,015 | ) | (19,371 | ) | ||||||
| Lower of cost or market write-downs on product linefill and tank bottom volumes | — | (60 | ) | (633 | ) | |||||||
| Corporate relocation and transition | — | — | (1,449 | ) | ||||||||
| Gain (loss) on disposition of assets, net | 129 | (978 | ) | — | ||||||||
| Operating income | 124,979 | 60,324 | 35,931 | |||||||||
| Dividend income | 389 | 6 | 374 | |||||||||
| Interest income | 557 | 205 | 286 | |||||||||
| Interest expense and other financing costs, net | (30,292 | ) | (29,946 | ) | (19,981 | ) | ||||||
| Earnings before income taxes and non-controlling interests | 95,633 | 30,589 | 16,610 | |||||||||
| Income tax expense | (39,253 | ) | (12,060 | ) | (8,510 | ) | ||||||
| Non-controlling interests share in earnings of TransMontaigne Partners | (562 | ) | — | — | ||||||||
| Earnings before cumulative effect adjustment | 55,818 | 18,529 | 8,100 | |||||||||
| Cumulative effect of a change in accounting principle, net | — | — | (1,297 | ) | ||||||||
| Net earnings | $ | 55,818 | $ | 18,529 | $ | 6,803 | ||||||
- (1)
- Net operating margins represents revenues, less cost of product sold and other direct operating costs and expenses.
Selected quarterly results of operations data for each of the quarters in the three-year period ended June 30, 2005, are summarized below (in thousands):
| |
Three months ended |
|
|||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year ended June 30, 2005 |
||||||||||||||||
| |
September 30, 2004 |
December 31, 2004 |
March 31, 2005 |
June 30, 2005 |
|||||||||||||
| Net operating margins: | |||||||||||||||||
| Supply, distribution and marketing | $ | 24,156 | $ | 19,540 | $ | 84,473 | $ | 13,762 | $ | 141,931 | |||||||
| Terminals and pipelines | 12,065 | 12,068 | 13,807 | 12,043 | 49,983 | ||||||||||||
| Total net operating margins | 36,221 | 31,608 | 98,280 | 25,805 | 191,914 | ||||||||||||
| Selling, general, and administrative | (10,433 | ) | (11,802 | ) | (9,885 | ) | (10,729 | ) | (42,849 | ) | |||||||
| Depreciation and amortization | (5,807 | ) | (5,727 | ) | (6,274 | ) | (6,407 | ) | (24,215 | ) | |||||||
| Gain (loss) on disposition of assets, net | (3,599 | ) | — | 2,993 | 735 | 129 | |||||||||||
| Operating income | 16,382 | 14,079 | 85,114 | 9,404 | 124,979 | ||||||||||||
| Other expense, net | (10,001 | ) | (6,998 | ) | (6,672 | ) | (5,675 | ) | (29,346 | ) | |||||||
| Income tax expense | (2,553 | ) | (2,832 | ) | (31,377 | ) | (2,491 | ) | (39,253 | ) | |||||||
| Non-controlling interests share in earnings of TransMontaigne Partners | — | — | — | (562 | ) | (562 | ) | ||||||||||
| Net earnings | $ | 3,828 | $ | 4,249 | $ | 47,065 | $ | 676 | $ | 55,818 | |||||||
52
| |
Three months ended |
|
|||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year ended June 30, 2004 |
||||||||||||||||
| |
September 30, 2003 |
December 31, 2003 |
March 31, 2004 |
June 30, 2004 |
|||||||||||||
| Net operating margins: | |||||||||||||||||
| Supply, distribution and marketing | $ | 12,554 | $ | 9,112 | $ | 42,752 | $ | 8,384 | $ | 72,802 | |||||||
| Terminals, pipelines and tugs and barges |
13,037 | 13,669 | 11,587 | 10,814 | 49,107 | ||||||||||||
| Total net operating margins | 25,591 | 22,781 | 54,339 | 19,198 | 121,909 | ||||||||||||
| Selling, general, and administrative | (9,525 | ) | (10,157 | ) | (10,452 | ) | (7,398 | ) | (37,532 | ) | |||||||
| Depreciation and amortization | (5,537 | ) | (5,932 | ) | (5,738 | ) | (5,808 | ) | (23,015 | ) | |||||||
| Lower of cost or market write-downs on product linefill and tank bottom volumes |
(32 | ) | (17 | ) | (11 | ) | — | (60 | ) | ||||||||
| Loss on disposition of assets, net | — | (805 | ) | — | (173 | ) | (978 | ) | |||||||||
| Operating income | 10,497 | 5,870 | 38,138 | 5,819 | 60,324 | ||||||||||||
| Other expense, net | (7,203 | ) | (7,442 | ) | (7,518 | ) | (7,572 | ) | (29,735 | ) | |||||||
| Income tax (expense) benefit | (1,318 | ) | 629 | (12,248 | ) | 877 | (12,060 | ) | |||||||||
| Net earnings (loss) | $ | 1,976 | $ | (943 | ) | $ | 18,372 | $ | (876 | ) | $ | 18,529 | |||||
| |
Three months ended |
|
|||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year ended June 30, 2003 |
||||||||||||||||
| |
September 30, 2002 |
December 31, 2002 |
March 31, 2003 |
June 30, 2003 |
|||||||||||||
| Net operating margins: | |||||||||||||||||
| Supply, distribution and marketing | $ | 8,414 | $ | (8,302 | ) | $ | 45,459 | $ | 7,277 | $ | 52,848 | ||||||
| Terminals, pipelines and tugs and barges |
9,732 | 9,661 | 11,534 | 11,937 | 42,864 | ||||||||||||
| Total net operating margins | 18,146 | 1,359 | 56,993 | 19,214 | 95,712 | ||||||||||||
| Selling, general, and administrative | (8,937 | ) | (8,313 | ) | (9,924 | ) | (11,154 | ) | (38,328 | ) | |||||||
| Depreciation and amortization | (4,256 | ) | (4,293 | ) | (4,851 | ) | (5,971 | ) | (19,371 | ) | |||||||
| Lower of cost or market write-downs on product linefill and tank bottom volumes |
— | — | (633 | ) | — | (633 | ) | ||||||||||
| Corporate relocation and transition | (1,084 | ) | (365 | ) | — | — | (1,449 | ) | |||||||||
| Operating income (loss) | 3,869 | (11,612 | ) | 41,585 | 2,089 | 35,931 | |||||||||||
| Other expense, net | (3,004 | ) | (2,001 | ) | (5,484 | ) | (8,832 | ) | (19,321 | ) | |||||||
| Income tax (expense) benefit | (329 | ) | 5,173 | (13,722 | ) | 368 | (8,510 | ) | |||||||||
| Cumulative effect adjustment, net | — | (1,297 | ) | — | — | (1,297 | ) | ||||||||||
| Net earnings (loss) | $ | 536 | $ | (9,737 | ) | $ | 22,379 | $ | (6,375 | ) | $ | 6,803 | |||||
DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2005, 2004 AND 2003
We reported net earnings of $55.8 million for the year ended June 30, 2005, compared to net earnings of $18.5 million for the year ended June 30, 2004, and net earnings of $6.8 million for the year ended June 30, 2003. After allocating earnings to preferred stock, the net earnings attributable to common stockholders was $44.2 million, $14.5 million and $2.8 million for the years ended June 30, 2005, 2004 and 2003, respectively. Basic earnings per common share for the years ended June 30, 2005,
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2004 and 2003, was $1.10, $0.37 and $0.07, respectively, based on 40.3 million, 39.4 million and 39.1 million weighted average common shares outstanding, respectively. Diluted earnings per share for the years ended June 30, 2005, 2004 and 2003, was $1.07, $0.36 and $0.07, respectively, based upon 52.3 million, 51.0 million and 39.3 million weighted average diluted shares outstanding, respectively.
Terminals, pipelines, and tugs and barges
In our terminals, pipelines, and tugs and barges operations, we provide distribution related services to wholesalers, distributors, marketers, retail gasoline station operators, cruise-ship operators and industrial and commercial end-users of refined petroleum products and other commercial liquids. The net operating margins from our terminals, pipelines, and tugs and barges operations for the year ended June 30, 2005 were $50.0 million, compared to $49.1 million for the year ended June 30, 2004 and $42.9 million for the year ended June 30, 2003. On February 28, 2003, we acquired the Coastal Fuels assets, which include five terminals, a pipeline delivery system, and a tug and barge operation. The results of operations of the Coastal Fuels assets are included from the closing date of the transaction (February 28, 2003). For the years ended June 30, 2005, 2004 and 2003, the Coastal Fuels assets generated revenues of approximately $42.5 million, $37.9 million and $12.6 million, respectively, and net operating margins of approximately $17.2 million, $15.4 million and $5.4 million, respectively, attributable to our terminals, pipelines, and tugs and barges operations.
The increase of $0.9 million in net operating margins for 2005 as compared to 2004 was due principally to increased net operating margins of approximately $0.6 million at the TransMontaigne Partners' facilities, $1.2 at our Brownsville facilities and $2.2 million at our Southeast facilities offset by decreased net operating margins of approximately $0.7 at our River facilities and $2.4 million at our Other facilities. The increase of $6.2 million in total net operating margins for 2004 as compared to 2003 was due principally to the addition of the Coastal Fuels assets offset by a decline in net operating margins due to decreased throughput and storage volumes at our River facilities.
The net operating margins from our terminals, pipelines, and tugs and barges operations are as follows (in thousands):
| |
Years ended June 30, |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
|||||||||
| Throughput and additive injections fees, net | $ | 42,535 | $ | 39,927 | $ | 38,280 | ||||||
| Storage fees | 35,657 | 36,036 | 25,979 | |||||||||
| Pipeline transportation fees | 3,883 | 4,121 | 2,993 | |||||||||
| Tugs and barges | 14,122 | 11,667 | 4,335 | |||||||||
| Management fees and cost reimbursements | 4,815 | 4,975 | 4,461 | |||||||||
| Other | 10,563 | 9,562 | 8,154 | |||||||||
| Revenue | 111,575 | 106,288 | 84,202 | |||||||||
| Less direct operating costs and expenses | (61,592 | ) | (57,181 | ) | (41,338 | ) | ||||||
| Net operating margins | $ | 49,983 | $ | 49,107 | $ | 42,864 | ||||||
Throughput and additive injections fees, net. We own and operate a terminal infrastructure that handles products with transportation connections via pipelines, barges, rail cars and trucks. We earn throughput fees for each barrel of product that is distributed at our terminals through our supply and marketing efforts, through exchange agreements, or for third parties. Terminal throughput fees are based on the volume of products distributed at the facility's truck loading racks, generally at a standard rate per barrel of product. We provide injection services in connection with the delivery of
54
product at our terminals. These fees generally are based on the volume of product injected and delivered over the rack at our terminals.
Exchange agreements provide for the exchange of product at one delivery location for product at a different location. We generally receive a terminal throughput fee based on the volume of the product exchanged, in addition to the cost of transportation from the receipt location to the exchange delivery location. For the years ended June 30, 2005, 2004 and 2003, we averaged approximately 49,000, 50,000 and 51,000 barrels per day, respectively, of delivered volumes under exchange agreements.
Terminal throughput and additive injection fees, net were approximately $42.5 million, $39.9 million and $38.3 million for the years ended June 30, 2005, 2004 and 2003, respectively. For the years ended June 30, 2005, 2004 and 2003, we averaged approximately 332,000 barrels, 397,000 barrels and 342,000 barrels per day of throughput volumes, respectively, at our terminals, including volumes under exchange agreements. The increase of $2.6 million in throughput and additive injection fees, net for 2005 as compared to 2004 was due principally to an increases of approximately $1.3 million at the TransMontaigne Partners' facilities, $1.1 million at the Brownsville facilities and $2.0 million at our Southeast facilities offset by decreases of approximately $0.6 at our River facilities and $1.2 million at our Other facilities. During 2005, we increased the rates charged for each barrel of product that is distributed at our terminals, which more than offset a decrease in throughput volumes. The increase of $1.6 million in throughput and additive injection fees, net for 2004 as compared to 2003 was due principally to increases of approximately $2.0 million as a result of our acquisition of the Coastal Fuels assets, approximately $0.9 million at our Southeast facilities and approximately $0.7 at our historical Florida facilities offset by a decrease of approximately $2.0 million at our River facilities.
Included in the terminal throughput fees for the years ended June 30, 2005, 2004 and 2003 are fees charged to TransMontaigne Inc.'s supply, distribution and marketing segment of approximately $35.9 million, $36.0 million and $29.9 million, respectively.
Storage Fees. We lease storage capacity at our terminals to third parties and to our supply, distribution and marketing segment. Terminal storage fees generally are based on a per barrel of leased capacity per month rate and will vary with the duration of the storage agreement and the type of product stored.
Terminal storage fees were approximately $35.7 million, $36.0 million and $26.0 million for the years ended June 30, 2005, 2004 and 2003, respectively. The decrease of $0.3 million in storage fees for 2005 as compared to 2004 was due principally to a decrease of approximately $1.1 million in storage fees charged at our Southeast facilities resulting from the commencement of terminaling services agreements with MSCG offset by annual increases in storage fees charged to our customers. The increase of $10.0 million in storage fees for 2004 as compared to 2003 was due principally to an increase of approximately $11.5 million from our acquisition of Coastal Fuels assets offset by decreases of approximately $0.7 million at our Brownsville facilities and approximately $0.6 million at our River facilities.
Included in the terminal storage fees for the years ended June 30, 2005, 2004 and 2003 are fees charged to TransMontaigne Inc.'s supply, distribution and marketing segment of approximately $12.6 million, $12.3 million and $5.9 million, respectively.
Pipeline Transportation Fees. We own an interstate products pipeline operating from Mt. Vernon, Missouri to Rogers, Arkansas, or the Razorback Pipeline, together with associated terminal facilities at Mt. Vernon and Rogers. We earn pipeline transportation fees at our Razorback pipeline based on the volume of product transported and the distance from the origin point to the delivery point. Tariff rates
55
on the Razorback Pipeline are regulated by the FERC. We also earn transportation fees at our Port Everglades pipeline delivery system based on the volume of product delivered to cruise ships and freight vessels. The Port Everglades pipeline delivery system allows a more efficient refueling process than barge to ship refueling.
For the years ended June 30, 2005, 2004 and 2003, we earned pipeline transportation fees of approximately $3.9 million, $4.1 million and $3.0 million, respectively. The decrease of $0.2 million in pipeline transportation fees for 2005 as compared to 2004 was due principally to the sale of our CETEX pipeline system on December 30, 2003 (see Note 3 of Notes to consolidated financial statements). The increase of $1.1 million in pipeline transportation fees for 2004 as compared to 2003 was due principally from our acquisition of the Coastal Fuels assets.
Included in the pipeline transportation fees for the years ended June 30, 2005, 2004 and 2003 are fees charged to TransMontaigne Inc.'s supply, distribution and marketing segment of approximately $3.9 million, $3.8 million and $2.5 million, respectively.
Tugs and Barges. In Florida, we currently own and operate 11 tugboats and 13 barges that deliver product to cruise ships and other marine vessels for refueling and to transport third party product from our storage tanks to our customers' facilities. Our tugboats earn fees for providing docking and other ship-assist services to cruise and cargo ships and other marine vessels. Bunkering fees are based on the volume and type of product sold, transportation fees are based on the volume of product that is shipped and the distance to the delivery point, and docking and other ship-assist services are based on a per docking per tugboat basis.
For the years ended June 30, 2005, 2004 and 2003, we earned bunkering fees, transportation fees, and docking and other ship-assist services fees of approximately $14.1 million, $11.7 million and $4.3 million, respectively. We acquired the tugs and barges operations on February 28, 2003 in connection with our acquisition of the Coastal Fuels assets.
Included in the tugs and barges fees for the years ended June 30, 2005, 2004 and 2003, are fees charged to TransMontaigne Inc.'s supply, distribution and marketing segment of approximately $7.3 million, $6.7 million and $2.8 million, respectively.
Management Fees and Cost Reimbursements. We manage and operate for a major oil company 17 terminals that are adjacent to our Southeast facilities and receive a reimbursement of costs. We manage and operate for another major oil company certain tank capacity at TransMontaigne Partners' Port Everglades (South) terminal and receive a reimbursement of costs. We also manage and operate for a foreign oil company a bi-directional products pipeline connected to our Brownsville facilities. For the years ended June 30, 2005, 2004 and 2003, management fees and cost reimbursements from our terminal and pipeline operations were approximately $4.8 million, $5.0 million, and $4.5 million, respectively.
Other Revenue. In addition to providing storage and distribution services at our terminal facilities, we also provide ancillary services including heating and mixing of stored products and product transfer services. We also recognize gains from the sale of product to our supply, distribution and marketing operation resulting from the excess of product deposited into our terminals over the amount of product that the customer is contractually permitted to withdraw from those terminals. For the years ended June 30, 2005, 2004 and 2003, other revenue from our terminals, pipelines, and tugs and barges operations was approximately $10.6 million, $9.6 million and $8.2 million, respectively. The increase of approximately $1.0 million in other revenue for 2005 as compared to 2004 was due principally to an increase of approximately $2.0 million at our Southeast facilities offset by a decrease
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of approximately $0.9 million at our Other facilities. The increase of approximately $1.4 million in other revenue for 2004 as compared to 2003 was due principally to an increase of approximately $2.9 million from our acquisition of the Coastal Fuels assets offset by a decrease of approximately $1.3 million at our Brownsville facilities.
Included in other revenue for the years ended June 30, 2005, 2004 and 2003 are fees charged to TransMontaigne Inc.'s supply, distribution and marketing segment of approximately $6.2 million, $3.7 million and $3.1 million, respectively.
Direct Operating Costs and Expenses. The direct operating costs and expenses of our terminals, pipelines, and tugs and barges operations include the directly related wages and employee benefits, utilities, communications, maintenance and repairs, property and casualty insurance, property taxes, rent, vehicle expenses, environmental compliance costs, materials and supplies. For the years ended June 30, 2005, 2004 and 2003, the direct operating costs and expenses of the terminals, pipelines, and tugs and barges were approximately $61.6 million, $57.2 million and $41.3 million, respectively. The direct operating costs and expenses of our terminals, pipelines, and tugs and barges operations are as follows (in thousands):
| |
Years ended June 30, |
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
||||||||
| Wages and employee benefits | $ | 25,109 | $ | 23,539 | $ | 16,266 | |||||
| Utilities and communication charges | 4,176 | 4,513 | 3,616 | ||||||||
| Repairs and maintenance | 16,420 | 14,416 | 9,697 | ||||||||
| Property and casualty insurance costs | 3,406 | 3,215 | 2,163 | ||||||||
| Office, rentals and property taxes | 5,935 | 5,676 | 4,298 | ||||||||
| Vehicles and fuel costs | 2,811 | 2,126 | 860 | ||||||||
| Environmental compliance costs | 3,907 | 3,718 | 3,244 | ||||||||
| Other | 1,187 | 1,666 | 1,697 | ||||||||
| Less—property and environmental insurance recoveries | (1,359 | ) | (1,688 | ) | (503 | ) | |||||
| Direct operating costs and expenses | $ | 61,592 | $ | 57,181 | $ | 41,338 | |||||
The increase of approximately $4.4 million in direct operating costs and expenses for 2005 as compared to 2004 was due principally to an increase of approximately $1.0 million at TransMontaigne Partners' facilities, $0.4 million at our Southeast facilities, $0.5 million at our River facilities, and $2.5 million at our Other facilities. The increase of approximately $15.8 million in direct operating costs and expenses for 2004 as compared to 2003 was due principally to the addition of the Coastal Fuels assets which resulted in approximately $15.3 million of additional direct operating costs and expenses.
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Supply, distribution and marketing
The net operating margins from our supply, distribution and marketing operations for the year ended June 30, 2005 were $141.9 million, compared to $72.8 million for the year ended June 30, 2004, and $52.8 million for the year ended June 30, 2003.
The net operating margins from our supply, distribution and marketing operations are as follows (in thousands):
| |
Years ended June 30, |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
|||||||||
| Rack spot sales | $ | 956,857 | $ | 1,704,524 | $ | 1,691,324 | ||||||
| Contract sales | 4,369,724 | 3,085,352 | 1,759,196 | |||||||||
| Bulk sales | 2,499,446 | 2,474,685 | 1,892,850 | |||||||||
| Supply chain management services | 611,768 | 362,253 | 177,314 | |||||||||
| Gross sales | 8,437,795 | 7,626,814 | 5,520,684 | |||||||||
| Cost of product sold | (8,304,949 | ) | (7,468,616 | ) | (5,349,795 | ) | ||||||
| Net margin before other direct costs and expenses | 132,846 | 158,198 | 170,889 | |||||||||
| Other direct costs and expenses: | ||||||||||||
| Net gains (losses) on risk management activities | 33,642 | (54,739 | ) | (84,146 | ) | |||||||
| Change in unrealized gains (losses) on derivative contracts | (20,289 | ) | (25,323 | ) | (21,460 | ) | ||||||
| Lower of cost or market write-downs on base operating inventory volumes | (4,268 | ) | (5,334 | ) | (12,435 | ) | ||||||
| Net operating margins | $ | 141,931 | $ | 72,802 | $ | 52,848 | ||||||
We sell our products to customers primarily through three types of arrangements: rack spot sales, contract sales, and bulk sales.
Rack Spot Sales. Rack spot sales are sales to commercial and industrial end-users, independent retailers, cruise-ship operators and jobbers that do not involve continuing contractual obligations to purchase or deliver product. Rack spot sales are priced and delivered on a daily basis through truck loading racks or marine fueling equipment. Our selling price of a particular product on a particular day at a particular terminal is a function of our supply at that terminal, our estimate of the costs to replenish the product at that terminal, our desire to reduce inventory levels at that terminal that day, and other factors. Rack spot sales are recognized as revenue when the product is delivered to the customer through the truck loading rack or marine fueling equipment.
Rack spot sales were approximately $956.9 million, $1,704.5 million and $1,691.3 million for the years ended June 30, 2005, 2004 and 2003, respectively. For the years ended June 30, 2005, 2004 and 2003, we averaged approximately 45,000 barrels, 117,000 barrels and 130,000 barrels per day, respectively, of delivered volumes under rack spot sales.
Contract Sales. Contract sales are sales to commercial and industrial end users, independent retailers, cruise-ship operators and jobbers that are made pursuant to negotiated contracts, generally ranging from one to six months in duration. Contract sales provide these customers with a specified volume of product during the agreement term. 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. Contract sales are recognized as revenue when the product is delivered to the customer through the truck loading rack or marine fueling equipment.
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Contract sales were approximately $4,369.7 million, $3,085.4 million and $1,759.2 million for the years ended June 30, 2005, 2004 and 2003, respectively. For the years ended June 30, 2005, 2004 and 2003, we averaged approximately 219,000 barrels, 210,000 barrels and 136,000 barrels per day, respectively, of delivered volumes under contract sales.
Bulk Sales. Bulk sales are sales of large quantities of product to wholesalers, distributors and marketers in major cash markets. We also may make a bulk sale of products while the product is being transported in the common carrier pipelines or by barge or vessel.
Bulk sales were approximately $2,499.4 million, $2,474.7 million and $1,892.9 million for the years ended June 30, 2005, 2004 and 2003, respectively. For the years ended June 30, 2005, 2004 and 2003, we averaged approximately 246,000 barrels, 400,000 barrels and 363,000 barrels per day, respectively, of delivered volumes under bulk sales.
Supply Chain Management Services Contracts. We provide supply chain management services to companies and governmental entities that desire to outsource their fuel supply function and to reduce the price volatility associated with their fuel supplies. We offer three types of supply chain management services: delivered fuel price management, retail price management, and logistical supply chain management services.
Sales pursuant to supply chain management services contracts were approximately $611.8 million, $362.3 million and $177.3 million for the years ended June 30, 2005, 2004 and 2003, respectively. For the years ended June 30, 2005, 2004 and 2003, we averaged approximately 30,000 barrels, 26,000 barrels and 14,000 barrels per day, respectively, of delivered volumes under supply chain management services contracts.
Cost of Product Sold. The cost of product sold includes the cost of the product inventory sold on a first-in, first-out basis, pipeline transportation and other freight costs, terminal throughput, additive and storage costs, and commissions. Cost of product sold was approximately $8,304.9 million, $7,468.6 million and $5,349.8 million for the years ended June 30, 2005, 2004 and 2003, respectively. Cost of product sold is as follows (in thousands):
| |
Years ended June 30, |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
|||||||
| Inventory product costs | $ | 8,149,165 | $ | 7,272,083 | $ | 5,202,246 | ||||
| Transportation and related charges | 97,006 | 132,816 | 101,381 | |||||||
| Throughput, storage and related charges | 56,284 | 61,153 | 44,269 | |||||||
| Other | 2,494 | 2,564 | 1,899 | |||||||
| Cost of product sold | $ | 8,304,949 | $ | 7,468,616 | $ | 5,349,795 | ||||
Net Losses on Risk Management Activities. Our risk management strategy generally is intended to maintain a balanced position of forward sale commitments against our discretionary inventories held for immediate sale or exchange, inventory volumes due to others under exchange agreements, open positions in derivative contracts, and open positions in risk management contracts, thereby reducing exposure to commodity price fluctuations. We evaluate our exposure to commodity price risk from an overall portfolio basis and offset that position with risk management contracts, principally futures contracts on the NYMEX.
When we nominate refined petroleum products to be supplied by third parties at our terminals, we enter into futures contracts (i.e., short futures contracts) to sell a corresponding amount of product to
59
protect against price fluctuations for the underlying commodity. When we ultimately sell the underlying inventory to a customer, we unwind the related risk management contract. In order to effectively manage commodity price risk, we must predict when we will sell the underlying product.
When we enter into a forward sale commitment to deliver product to a customer in the future at a fixed price, we enter into a futures contract (i.e., a long futures contract) to purchase a corresponding amount of product to protect against price fluctuations for the underlying commodity. When we ultimately deliver the underlying product to a customer, we unwind the related risk management contract.
During a period of rising prices, long (short) futures contracts will increase (decrease) in value resulting in a gain (loss). During a period of declining prices, our long (short) futures contracts will decrease (increase) in value resulting in a loss (gain).
Net gains (losses) on risk management activities were approximately $33.6 million, $(54.7) million and $(84.1) million for the years ended June 30, 2005, 2004 and 2003, respectively, due principally to rising commodity prices during these periods.
Lower of Cost or Market Write-Downs on Base Operating Inventory Volumes. During the years ended June 30, 2005, 2004 and 2003, we recognized impairment losses of approximately $4.3 million, $5.3 million and $12.4 million, respectively, due to lower of cost or market write-downs on certain base operating inventory volumes due principally to declining prices at the end of a quarterly reporting period.
Costs and expenses
Selling, general and administrative expenses for the year ended June 30, 2005 were $42.8 million, compared to $37.5 million for the year ended June 30, 2004, and $38.3 million for the year ended June 30, 2003. Selling, general and administrative expenses are as follows (in thousands):
| |
Years ended June 30, |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
|||||||
| Wages and employee benefits | $ | 34,115 | $ | 27,819 | $ | 28,324 | ||||
| Office costs, utilities and communication charges | 4,180 | 5,314 | 4,878 | |||||||
| Accounting and legal expenses | 1,723 | 1,618 | 2,502 | |||||||
| Property and casualty insurance | 830 | 642 | 668 | |||||||
| Other | 2,001 | 2,139 | 1,956 | |||||||
| Selling, general and administrative expenses | $ | 42,849 | $ | 37,532 | $ | 38,328 | ||||
During the year ended June 30, 2005, we awarded bonuses of approximately $3.5 million to our employees to retain our employees during the evaluation of our strategic alternatives and to compensate our employees for their performance through December 31, 2004.
Depreciation and amortization for the years ended June 30, 2005, 2004 and 2003, was $24.2 million, $23.0 million and $19.4 million, respectively. The increase of $1.2 million in depreciation and amortization for 2005 as compared to 2004 is due principally to depreciation on new additions to property, plant, and equipment and amortization of the product supply agreement. The increase of $3.6 million in depreciation and amortization for 2004 as compared to 2003 is principally related to depreciation and amortization on the Coastal Fuels assets and current year additions to property, plant, and equipment.
60
During the years ended June 30, 2005, 2004 and 2003, we recognized impairment losses of approximately $nil, $60,000 and $0.6 million, respectively, due to write-downs on the product linefill and tank bottom volumes.
We recognized special charges of $1.4 million during the year ended June 30, 2003, related to our corporate relocation and transition. During the year ended June 30, 2003, we completed the relocation of our employees from Atlanta, Georgia to Denver, Colorado. In connection with our corporate relocation and transition, we entered into an operating lease for new office space in Denver, Colorado. Accordingly, we vacated certain office space in Denver, Colorado during June 2003 and we vacated our excess space in Atlanta, Georgia during October 2002.
Gain (loss) on disposition of assets, net for the year ended June 30, 2005 of approximately $0.1 million includes a $2.7 million gain on the sale of land held for investment in Miami, Florida, $0.3 million gain on settlement of NORCO indemnities and $0.7 million gain on the sale of certain product linefill and tank bottom volumes offset by an approximately $(3.5) million loss on the involuntary conversion of our Pensacola terminal facilities due to the damage caused by hurricane Ivan. Gain (loss) on disposition of assets for the year ended June 30, 2004, consists of a $(0.7) million loss on sale of CETEX pipeline system and a $(0.3) loss on the sale of other assets.
Other income and expenses
Dividend income for the year ended June 30, 2005 was $0.4 million, compared to $6,000 for the year ended June 30, 2004, and $0.4 million for the year ended June 30, 2003. The dividend income for 2005 and 2003 is due principally to our investment in Lion Oil Company.
Interest income for the year ended June 30, 2005 was $0.6 million, as compared to $0.2 million for the year ended June 30, 2004, and $0.3 million for the year ended June 30, 2003. Pursuant to our cash management practices, excess cash balances are used to pay down our outstanding borrowings under our credit facility and commodity margin loan and then invested in short-term cash equivalents.
Interest expense for the year ended June 30, 2005 was $24.8 million, compared to $26.5 million during the year ended June 30, 2004, and $14.7 million during the year ended June 30, 2003. Interest expense is as follows (in thousands):
| |
Years ended June 30, |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
|||||||
| Senior subordinated notes | $ | 18,250 | $ | 18,639 | $ | 1,521 | ||||
| Working capital credit facility | 3,662 | 7,216 | 1,724 | |||||||
| Former bank credit facility | 1,331 | — | 4,559 | |||||||
| Letters of credit | 1,284 | 468 | 351 | |||||||
| Commodity margin loan | 107 | 154 | 200 | |||||||
| TransMontaigne Partners' credit facility | 167 | — | — | |||||||
| Interest rate swap | — | — | 3,902 | |||||||
| Term loan | — | — | 2,441 | |||||||
| Other | — | — | 7 | |||||||
| Interest expense | $ | 24,801 | $ | 26,477 | $ | 14,705 | ||||
Other financing costs for the year ended June 30, 2005, were $5.5 million, compared to $3.5 million for the year ended June 30, 2004, and $5.3 million for the year ended June 30, 2003. The increase of $2.0 million in other financing costs for 2005 as compared to 2004 was due principally to the write-off of debt issuance costs of approximately $3.4 million associated with our former credit facility
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offset by a decrease of approximately $1.4 million in amortization of deferred debt issuance costs. On September 13, 2004, we repaid our former bank credit facility. The decrease of $1.8 million in other financing costs for 2004 as compared to 2003 was due principally to the absence of a write-off of debt issuance costs of $5.8 million and an unrealized gain on the settlement of our interest rate swap of $2.2 million, offset by an increase of approximately $1.7 million in amortization of deferred debt issuance costs.
Income taxes
Income tax expense was $39.3 million for the year ended June 30, 2005, compared to $12.1 million for the year ended June 30, 2004, and $8.5 million for the year ended June 30, 2003. The effective combined federal and state income tax rate was 41.0%, 39.4% and 51.2% for the years ended June 30, 2005, 2004 and 2003, respectively. The effective combined rate for 2005, 2004 and 2003 includes a provision of approximately $2.3 million, $0.7 million and $1.7 million, respectively, for a change in cumulative temporary differences.
Cumulative effect adjustment for a change in accounting principle
As a result of the consensus reached on EITF 02-03, we are no longer permitted to carry our inventories—discretionary volumes held for immediate sale or exchange at fair value nor are we permitted to carry our base operating inventory volumes at original cost adjusted for impairment write-downs. Effective October 1, 2002, we adjusted the carrying amount of our inventories—discretionary volumes to the lower of cost (FIFO) or market pursuant to the requirements of EITF 02-03. The change in the carrying amount of our inventories—discretionary volumes has been reflected in the accompanying consolidated statement of operations as a cumulative effect adjustment for a change in accounting principle.
Preferred stock dividends
Preferred stock dividends on our Series A Convertible Preferred stock were $nil, $nil and $1.2 million for the years ended June 30, 2005, 2004 and 2003, respectively. The decrease in the dividend resulted from a reduction in the number of shares of Series A Convertible Preferred stock outstanding. The terms of the Series A Convertible Preferred Stock included an increase in the annual dividend rate from 5% of the liquidation value to 16% of the liquidation value commencing January 1, 2004. Therefore, on June 28, 2002, we entered into an agreement with the holders of the Series A Convertible Preferred stock, or 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, or the Series B Redeemable Convertible Preferred Stock, to reduce the financial impact of the scheduled increase in the dividend rate. 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 approximately $21.3 million. On June 30, 2003, we redeemed the remaining 24,421 shares of Series A Convertible Preferred stock and warrants that were outstanding for a cash payment of approximately $24.4 million.
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Preferred stock dividends on our Series B Redeemable Convertible Preferred Stock were $2.7 million, $2.8 million and $2.8 for the years ended June 30, 2005, 2004 and 2003. 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 with an equal reduction in the amount of preferred stock dividends recognized for financial reporting purposes. For the year ended June 30, 2005, the amount of the dividend recognized for financial reporting purposes is composed of the amount of the dividend payable to the holders of the Series B Redeemable Convertible Preferred Stock of $4.2 million, offset by the amortization of the premium on the carrying amount of the Series B Redeemable Convertible Preferred Stock of $1.5 million. During the year ended June 30, 2005, certain holders of our Series B Redeemable Convertible Preferred Stock exercised their option to convert approximately 26,782 shares of the Series B Redeemable Convertible Preferred Stock into approximately 4.1 million shares of common stock. Subsequent to June 30, 2005, an additional 29,773 shares of Series B Redeemable Convertible Preferred stock were converted into approximately 4.5 million shares of common stock resulting in approximately 17,422 shares of Series B Redeemable Convertible Preferred stock outstanding as of August 23, 2005.
LIQUIDITY, CAPITAL RESOURCES, AND COMMODITY PRICE RISK
At June 30, 2005, our current assets exceeded our current liabilities by $319.6 million, compared to $118.3 million at June 30, 2004. The increase of $201.3 million in working capital is due principally to working capital generated by operations of approximately $92.1 million, net proceeds from TransMontaigne Partners' initial public offering of approximately $73.0 million, net proceeds from TransMontaigne Partners' private placement of approximately $7.9 million, borrowings under TransMontaigne Partners' credit facility of approximately $28.3 million and proceeds from the disposition of assets of approximately $7.3 million offset by additions to property, plant and equipment of approximately $15.9 million.
Our inventories—discretionary volumes are presented in the accompanying consolidated balance sheet as current assets and are carried at the lower of cost or market. Inventories—discretionary volumes are as follows (in thousands):
| |
June 30, 2005 |
June 30, 2004 |
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
Amount |
Bbls |
Amount |
Bbls |
||||||
| Volumes held for immediate sale or exchange | $ | 153,123 | 2,415 | $ | 55,298 | 1,304 | ||||
| Volumes held for base operations | 121,651 | 2,011 | 181,412 | 4,050 | ||||||
| Inventories—discretionary volumes | $ | 274,774 | 4,426 | $ | 236,710 | 5,354 | ||||
Our volumes held for immediate sale or exchange generally are subject to price risk management. Inventories—discretionary volumes held for immediate sale or exchange are as follows (in thousands):
| |
June 30, 2005 |
June 30, 2004 |
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
Amount |
Bbls |
Amount |
Bbls |
||||||
| Gasolines | $ | 77,524 | 1,185 | $ | 13,343 | 226 | ||||
| Distillates | 64,191 | 932 | 35,937 | 843 | ||||||
| No. 6 oil | 11,408 | 298 | 6,018 | 235 | ||||||
| Volumes held for immediate sale or exchange | $ | 153,123 | 2,415 | $ | 55,298 | 1,304 | ||||
63
Our base operating inventory volumes generally are not subject to price risk management. However, at June 30, 2005, we were managing the commodity price risk associated with approximately 0.5 million barrels of base operating inventory volumes in anticipation of the liquidation of certain base operating inventory volumes. Based on the current level of our operations, we have established our base operating inventory volumes, exclusive of product linefill and tank bottom volumes at approximately 2.0 million barrels. Changes in our operation, such as the acquisition of additional terminals, increases in our contract sales volumes or entering into product supply agreements, may result in changes in the volume of our base operating inventory volumes. Inventories—base operating inventory volumes are as follows (in thousands):
| |
June 30, 2005 |
June 30, 2004 |
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
Amount |
Bbls |
Amount |
Bbls |
||||||
| Gasolines | $ | 58,723 | 938 | $ | 117,679 | 2,416 | ||||
| Distillates | 49,479 | 725 | 56,268 | 1,346 | ||||||
| No. 6 oil | 13,449 | 348 | 7,465 | 288 | ||||||
| Volumes held for base operations | $ | 121,651 | 2,011 | $ | 181,412 | 4,050 | ||||
The activity in our base operating inventory volumes is summarized as follows (in thousands):
| |
Amount |
Barrels |
||||
|---|---|---|---|---|---|---|
| As of June 30, 2003 | $ | 96,426 | 2,922 | |||
| Expansion of existing operations | 51,442 | 1,128 | ||||
| Change in FIFO cost basis | 38,878 | — | ||||
| Lower of cost or market write-down | (5,334 | ) | — | |||
| As of June 30, 2004 | 181,412 | 4,050 | ||||
| Net reduction in base operating volumes | (99,471 | ) | (2,039 | ) | ||
| Change in FIFO cost basis | 43,978 | — | ||||
| Lower of cost or market write-down | (4,268 | ) | — | |||
| As of June 30, 2005 | $ | 121,651 | 2,011 | |||
Our product linefill and tank bottom volumes consist of refined products held in our proprietary terminal pipeline connections and tank bottoms. Our product linefill and tank bottom volumes are not held for sale or exchange in the ordinary course of business. Our product linefill and tank bottom volumes are presented in the accompanying consolidated balance sheet as non-current assets and are carried at original cost adjusted for impairment write-downs to current market values. Product linefill and tank bottom volumes consist of the following (in thousands):
| |
June 30, 2005 |
June 30, 2004 |
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
Amount |
Bbls |
Amount |
Bbls |
||||||
| Gasolines | $ | 14,267 | 522 | $ | 14,641 | 533 | ||||
| Distillates | 8,774 | 351 | 8,881 | 356 | ||||||
| No. 6 oil | 1,284 | 52 | 1,514 | 61 | ||||||
| Product linefill and tank bottom volumes | $ | 24,325 | 925 | $ | 25,036 | 950 | ||||
64
The activity in our product linefill and tank bottom volumes is summarized as follows (in thousands):
| |
Amount |
Barrels |
||||
|---|---|---|---|---|---|---|
| As of June 30, 2003 | $ | 22,017 | 877 | |||
| Expansion of existing operations | 3,079 | 73 | ||||
| Lower of cost or market write-down | (60 | ) | — | |||
| As of June 30, 2003 | 25,036 | 950 | ||||
| Sale of product linefill and tank bottom volumes | (711 | ) | (25 | ) | ||
| As of June 30, 2004 | $ | 24,325 | 925 | |||
The following table indicates the maturities of our derivative contracts, including the credit quality of our counterparties to those contracts with unrealized gains at June 30, 2005.
| |
Fair value of contracts (in thousands) |
|||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Maturity less than 1 year |
Maturity 1-3 years |
Maturity in excess of 3 years |
Total |
||||||||||
| Unrealized gain position—asset | ||||||||||||||
| Investment grade | $ | 1,123 | $ | — | $ | — | $ | 1,123 | ||||||
| Non-investment grade | 3,829 | — | — | 3,829 | ||||||||||
| No external rating | 2,668 | — | — | 2,668 | ||||||||||
| 7,620 | — | — | 7,620 | |||||||||||
| Unrealized loss position—liability | (47,215 | ) | (234 | ) | — | (47,449 | ) | |||||||
| Net unrealized loss position—liability | $ | (39,595 | ) | $ | (234 | ) | $ | — | $ | (39,829 | ) | |||
Included in unrealized loss position—liability with a maturity less than one year is an unrealized loss of approximately $3.6 million related to short positions taken in the NYMEX options market.
The following table includes information about the changes in the fair value of our derivative contracts for the years ended June 30, 2004 and 2005 (in thousands):
| |
|
|||
|---|---|---|---|---|
| Fair value at June 30, 2003 | $ | (1,872 | ) | |
| Amounts realized or otherwise settled during the year | 17,329 | |||
| Fair value of contracts originated during the year, which are included in deferred revenue | 3,669 | |||
| Change in fair value attributable to change in commodity prices | (42,653 | ) | ||
| Fair value at June 30, 2004 | (23,527 | ) | ||
| Amounts realized or otherwise settled during the year | 37,589 | |||
| Fair value of contracts originated during the year, which are included in deferred revenue | 7,385 | |||
| Change in fair value attributable to change in commodity prices | (61,276 | ) | ||
| Fair value at June 30, 2005 | $ | (39,829 | ) | |
Capital expenditures for the year ended June 30, 2005, were $15.9 million for terminal and pipeline facilities and assets to support these facilities. Excluding acquisitions, capital expenditures for the year ending June 30, 2006, are estimated to be approximately $10.0 million, which includes approximately $6.0 million of capital expenditures to maintain our existing 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
65
provide; local, state and federal governmental regulations; environmental compliance requirements; and the availability of debt financing and equity capital on acceptable terms.
Our former Working Capital Credit Facility as in effect at June 30, 2004 provided for a maximum borrowing line of credit that was the lesser of (i) $275 million and (ii) the borrowing base (as defined; $364 million at June 30, 2004). The maximum borrowing amount was reduced by the amount of letters of credit that were outstanding. The borrowing base was a function of our cash, accounts receivable, inventory, exchanges, margin deposits, open positions of derivative contracts, outstanding letters of credit, and outstanding indebtedness as defined in the facility. At June 30, 2004, we had borrowings of $110 million outstanding and letters of credit of $38.6 million outstanding under the former Working Capital Credit Facility. On September 13, 2004, we repaid all outstanding borrowings under the former Working Capital Credit Facility with proceeds from our new $400 million Senior Secured Working Capital Credit Facility.
Our Senior Secured Working Capital Credit Facility as in effect at June 30, 2005 provides for a maximum borrowing line of credit that was the lesser of (i) $400 million and (ii) the borrowing base (as defined; $537 million at June 30, 2005). The borrowing base is a function of our cash, accounts receivable, inventory, exchanges, margin deposits, and certain reserve adjustments as defined in the facility. The maximum borrowing amount is reduced by the amount of letters of credit that are outstanding. At June 30, 2005, we had borrowings of $nil outstanding and letters of credit of $91 million outstanding under the Senior Secured Working Capital Credit Facility. We also had the ability to borrow an additional $309 million under the facility based on the borrowing base computation at June 30, 2005. All outstanding borrowings under the Senior Secured Working Capital Credit Facility are due and payable on September 13, 2009.
The Senior Secured Working Capital Credit Facility is our primary means of short-term liquidity to finance working capital requirements. The Senior Secured Working Capital Credit Facility contains affirmative and negative covenants (including limitations on indebtedness, limitations on dividends and other distributions, limitations on certain inter-company transactions, limitations on mergers, consolidation and the disposition of assets, limitations on investments and acquisitions and limitations on liens) that are customary for a facility of this nature. The Senior Secured Working Capital Credit Facility also contains customary representations and warranties (including those relating to corporate organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The only financial covenant contained in the Senior Secured Working Capital Credit Facility is a minimum fixed charge coverage ratio test that is tested on a quarterly basis whenever the average availability falls below $50 million for the last month of any quarter (average availability was approximately $321 million for the month ended June 30, 2005). In that event, we must satisfy a minimum fixed charge coverage ratio requirement of 110%. The fixed charge coverage ratio is based on a defined financial performance measure within the Senior Secured Working Capital Credit Facility known as "fixed charges EBITDA."
66
The computation of the fixed charge coverage ratio for the twelve months ended June 30, 2005, is as follows:
| |
Three Months Ended |
Twelve Months Ended June 30, 2005 |
||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
September 30, 2004 |
December 31, 2004 |
March 31, 2005 |
June 30, 2005 |
||||||||||||
| Financial performance debt covenant test: | ||||||||||||||||
| Consolidated adjusted EBITDA | $ | 6,659 | $ | 42,705 | $ | 62,846 | $ | (306 | ) | $ | 111,904 | |||||
| Capital expenditures | (1,010 | ) | (1,896 | ) | (1,616 | ) | (3,361 | ) | (7,883 | ) | ||||||
| TransMontaigne Partners' capital expenditures | — | — | — | 222 | 222 | |||||||||||
| Cash (paid for) refund of income taxes | 170 | 5 | (2 | ) | (29,704 | ) | (29,531 | ) | ||||||||
| Preferred stock dividends paid in cash | (1,109 | ) | (1,110 | ) | (1,110 | ) | (1,281 | ) | (4,610 | ) | ||||||
| Fixed charges EBITDA | $ | 4,710 | $ | 39,704 | $ | 60,118 | $ | (34,430 | ) | $ | 70,102 | |||||
| Fixed charges for the period | $ | 6,284 | $ | 6,556 | $ | 6,226 | $ | 5,009 | $ | 24,075 | ||||||
| Fixed charge coverage ratio based on rolling four consecutive quarters | 291 | % | ||||||||||||||
| Reconciliation of consolidated adjusted EBITDA to cash flows provided by (used in) operating activities: | ||||||||||||||||
| Consolidated adjusted EBITDA | $ | 6,659 | $ | 42,705 | $ | 62,846 | $ | (306 | ) | $ | 111,904 | |||||
| TransMontaigne Partners' operating income | — | — | — | 1,364 | 1,364 | |||||||||||
| Gain on disposition of assets, net | — | — | (2,993 | ) | (735 | ) | (3,728 | ) | ||||||||
| Gains recognized on beginning inventories—discretionary volumes held for immediate sale or exchange | 2,330 | 4,405 | 6,093 | 10,311 | 2,330 | |||||||||||
| Gains deferred on ending inventories—discretionary volumes held for immediate sale or exchange | (4,405 | ) | (6,093 | ) | (10,311 | ) | (2,125 | ) | (2,125 | ) | ||||||
| Increase in FIFO cost basis of base operating inventory volumes | 21,585 | (18,715 | ) | 32,769 | 8,339 | 43,978 | ||||||||||
| Lower of cost or market write-downs on base operating inventory volumes | — | (2,496 | ) | — | (1,772 | ) | (4,268 | ) | ||||||||
| Interest expense, net | (6,284 | ) | (6,556 | ) | (6,226 | ) | (5,011 | ) | (24,077 | ) | ||||||
| TransMontaigne Partners' interest expense |
— | — | — | (167 | ) | (167 | ) | |||||||||
| Cash (paid for) refund of income taxes | 170 | 5 | (2 | ) | (29,704 | ) | (29,531 | ) | ||||||||
| Amortization of deferred revenue | (1,048 | ) | (1,641 | ) | (2,376 | ) | (1,841 | ) | (6,906 | ) | ||||||
| Amortization of deferred stock-based compensation | 630 | 646 | 697 | 652 | 2,625 | |||||||||||
| Net change in unrealized (gains) losses on long-term derivative contracts | 2,571 | (2,031 | ) | (88 | ) | 296 | 748 | |||||||||
| Change in operating assets and liabilities |
(25,632 | ) | (123,311 | ) | 174,692 | (67,173 | ) | (41,424 | ) | |||||||
| Cash flows provided by (used in) operating activities | $ | (3,424 | ) | $ | (113,082 | ) | $ | 255,101 | $ | (87,872 | ) | $ | 50,723 | |||
If we were to fail the fixed charge ratio covenant, or any other covenant contained in the Senior Secured Working Capital Credit Facility, we would seek a waiver from our lenders under such facility. If we were unable to obtain a waiver from our lenders, we would be in breach of the Senior Secured
67
Working Capital Credit Facility and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. In addition, a default under the Senior Secured Working Capital Credit Facility would trigger a cross-default provision in the indenture covering our Senior Subordinated Notes.
On May 30, 2003, we consummated the sale and issuance of $200 million aggregate principal amount of 91/8% Senior Subordinated Notes due 2010 ("Notes") and received proceeds of $194.5 million (net of underwriters' discounts of $5.5 million). We used the net proceeds from the offering of the Notes to repay certain outstanding indebtedness. The Notes mature on June 1, 2010 and interest is payable semi-annually in arrears on each June 1 and December 1 commencing on December 1, 2003. The Notes are unsecured and subordinated to all of our existing and future senior debt. Upon certain change of control events, each holder of the Notes may require us to repurchase all or a portion of its notes at a purchase price equal to 101% of the principal amount thereof, plus accrued interest.
We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations at June 30, 2005 are as follows (in thousands):
| |
Years ending June 30, |
|||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2006 |
2007 |
2008 |
2009 |
2010 |
Thereafter |
||||||||||||||
| Debt | $ | — | $ | — | $ | — | $ | — | $ | 228,307 | $ | — | ||||||||
| Interest expense on debt(1) | 19,665 | 19,665 | 19,665 | 19,665 | 17,910 | — | ||||||||||||||
| Series B Redeemable Convertible Preferred stock(2) | — | — | 47,195 | — | — | — | ||||||||||||||
| Transportation and deficiency agreements | 640 | — | — | — | — | — | ||||||||||||||
| Additions to property, plant and equipment under contract | 1,785 | — | — | — | — | — | ||||||||||||||
| Operating leases, net of contracted sublease rentals: | ||||||||||||||||||||
| Existing office space | 1,382 | 1,377 | 1,537 | 1,520 | 1,586 | 2,478 | ||||||||||||||
| Vacated office space | 1,046 | 995 | 306 | 313 | 318 | — | ||||||||||||||
| Vessel charters | 5,125 | — | — | — | — | — | ||||||||||||||
| Terminal and pipeline capacity | 2,100 | 1,495 | 1,082 | 117 | 97 | — | ||||||||||||||
| Property and equipment | 435 | 362 | 290 | 171 | 75 | 194 | ||||||||||||||
| Total contractual obligations to be settled in cash | $ | 32,178 | $ | 23,894 | $ | 70,075 | $ | 21,786 | $ | 248,293 | $ | 2,672 | ||||||||
- (1)
- Assumes
that our outstanding borrowings at June 30, 2005 remain outstanding until their respective maturity dates and we incur interest expense at 9.125% on our Senior
Subordinated Notes and 5.0% on TransMontaigne Partners' credit facility.
- (2)
- Subsequent to June 30, 2005, an additional 29,773 shares of Series B Redeemable Convertible Preferred stock were converted into approximately 4.5 million shares of common stock resulting in approximately 17,422 shares of Series B Redeemable Convertible Preferred stock outstanding as of August 23, 2005.
68
Off-balance sheet arrangements
We have outstanding letters of credit with third parties in the amount of $91 million, which expire within one year.
See Notes 10, 12, 13 and 19 of Notes to consolidated financial statements for additional information regarding our contractual obligations and off-balance sheet arrangements that may affect our results of operations and financial condition.
We believe that our current working capital position; future cash expected to be provided by operating activities; available borrowing capacity under our Senior Secured Working Capital Credit 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 through at least the maturity date of our Senior Secured Working Capital Credit Facility (September 2009).
In December 2004, the Financial Accounting Standards Board ("FASB") enacted Statement of Financial Accounting Standards 123—revised 2004 ("SFAS 123R"), "Share-Based Payment" which replaces Statement of Financial Accounting Standards No. 123 ("SFAS 123"), "Accounting for Stock-Based Compensation" and supersedes APB Opinion No. 25 ("APB 25"), "Accounting for Stock Issued to Employees." SFAS 123R requires the measurement of all employee share-based payments to employees, including grants of employee stock options, using a fair-value-based method and the recording of such expense in our consolidated statements of operations. For TransMontaigne Inc., the accounting provisions of SFAS 123R are effective for reporting periods beginning after June 15, 2005. The pro forma disclosures previously permitted under SFAS 123 no longer will be an alternative to financial statement recognition. Although we have not yet determined whether the adoption of SFAS 123R will result in amounts that are similar to the current pro forma disclosures under SFAS 123, we are evaluating the requirements under SFAS 123R and do not anticipate the adoption will have a significant impact on our consolidated financial statements.
In March 2005, the FASB issued FASB Interpretation No. 47 ("FIN 47"), "Accounting for Conditional Asset Retirement Obligations—an interpretation of SFAS 143," which requires companies to recognize a liability for the fair value of a legal obligation to perform asset-retirement activities that are conditional on a future event, if the amount can be reasonably estimated. For TransMontaigne Inc., FIN 47 is effective for annual reporting periods beginning after December 15, 2005. We are evaluating the requirements under FIN 47 and do not anticipate the adoption will have a significant impact on our consolidated financial statements.
69
Our business, operations and financial condition are subject to various risks. You should consider carefully the following risk factors, in addition to the other information set forth in this annual report in connection with any investment in our securities. If any of the following risks actually occurs, our business, financial condition or results of operations could be materially adversely affected. In that case, the market value of our outstanding debt and equity securities could decline, and investors could lose all or a part of their investment.
RISKS RELATING TO OUR BUSINESS
The profitability of our operations depends on the availability to us of supplies of petroleum products. A significant decrease in available supplies for any reason could adversely affect our sales and results of operations.
The success of our marketing and distribution business depends on our ability to generate positive margins on sales of refined petroleum products. In addition, our terminal, tug and barge business depends on an active market for refined petroleum products to create demand for terminal services. As a result, the availability of supplies of refined petroleum product is essential to our operations. Pursuant to our product supply agreement with Morgan Stanley Capital Group, Morgan Stanley Capital Group is obligated to supply our refined petroleum product needs for the grades of refined products covered by the supply agreement in the absence of a "force majeure" event. A material decline in refined petroleum product supplies as the result of such an event, or the failure of Morgan Stanley Capital Group for any other reason to perform its obligations under the product supply agreement, could adversely affect our revenues from rack spot and contract sales, as well as throughput and storage fees. A material decline in product supplies due to a "force majeure" may be caused by natural disasters, adverse weather conditions, terrorist attacks and other events beyond our control. Furthermore, we do not have long-term supply contracts with refiners. Therefore, the availability of product, and the prices at which it is available, could be adversely affected by any one of several events, including a lack of crude oil supplies, lack of refining capacity, price or volume competition and external economic or political events. For example, a crude oil supply disruption in the Middle East or South America or a lack of refining capacity could result in the inability of major refiners to produce volumes of refined petroleum products sufficient to meet market demands. Such shortages could lead the major oil companies, as well as the independent refining and marketing companies to retain all of their refined petroleum product supplies for their own distribution operations, thus creating a shortage of supply available to us. Such a shortage could have a material adverse effect on our financial condition and results of operations.
We are subject to the credit risk and performance risk of Morgan Stanley Capital Group and Morgan Stanley Capital Group's creditworthiness or failure to perform under our product supply agreement could adversely affect our ability to operate and adversely affect our results of operations.
In November 2004, we entered into a product supply agreement with Morgan Stanley Capital Group Inc. Morgan Stanley Capital Group began supplying gasoline and distillate to our operations during January and February 2005, and the product supply agreement expires on December 31, 2011, subject to provisions for early termination. Under the terms of the product supply agreement, Morgan Stanley Capital Group has become our principal supplier of gasoline and distillate to our existing
70
marketing and distribution business at terminals connected to the Colonial and Plantation pipelines and the Florida waterborne terminals owned by TransMontaigne Partners. If Morgan Stanley Capital Group should be unable to meet its obligations under the product supply agreement, we would have to secure supplies of gasoline and distillate products from other sources, which may not be available at comparable prices. In addition, we might be unable to secure adequate supplies of refined petroleum products in order to make timely deliveries to our customers and, as a result, would be in breach of our obligations to those customers. Consequently, the failure by Morgan Stanley Capital Group to meet its obligations under the product supply agreement could adversely affect our relations with our customers and have an adverse impact on our results of operations.
Contract non-performance by our customers could cause us to incur unplanned expenses and suffer losses as a result.
We have contract sales agreements, fuel supply management agreements, storage agreements and other contractual relationships with our customers. We therefore could be exposed to unplanned expenses and losses if any of those parties fails to honor its contractual commitments or files for bankruptcy. Accordingly, we are exposed to an increased level of direct and indirect counter-party credit and performance risk. For example, when we enter into a long-term sale contract with a customer, the contract sets a fixed price for our sale of product to that customer. In accordance with our risk management policies and practices, we may enter into futures contracts to protect against price fluctuations. However, if the customer with whom we have entered into the long-term sale contract then fails to honor its contractual commitments or files for bankruptcy, we would remain liable for the obligations under the applicable futures contract. If the price of product has changed adversely since we entered into the futures contract, we could be forced to make a substantial payment to settle the futures contract that would not be offset by corresponding revenues from the customer, which could adversely impact our results of operations.
We face intense competition in our supply, distribution and marketing activities, as well as in our terminaling activities and our results of operations may be adversely impacted if we are not able to compete effectively.
We compete with other petroleum companies, including national, regional and local pipeline and terminal companies, the major integrated oil companies, their marketing affiliates, and independent brokers and marketers of widely varying sizes, financial resources and experience. In particular, our ability to compete could be harmed by factors we cannot control, including:
- –>
- price
competition from major oil companies or other independent refined product companies, some of which are substantially larger than we are, have greater financial
resources and control substantially greater supplies of petroleum products than we do;
- –>
- an
abundance of supply of petroleum products causing petroleum sales margins to decline;
- –>
- the
perception that another company can provide better service; and
- –>
- the availability of alternative supply points, or supply points located closer to our customers' operations.
In addition, the major integrated oil companies derive profits from various operations, such as exploration and production and refining, and can use those other operations to effectively subsidize their marketing operations, which may allow them to compete with us through the reduction of wholesale prices and marketing margins. The ability to subsidize their marketing operations may
71
enable the major integrated oil companies to compete more effectively than TransMontaigne Inc., because our operations are focused on marketing, distribution and terminal services. As a result, the major integrated oil companies may be better positioned to compete effectively if margins in the areas in which we operate are lowered by competitive activities or other factors. If we are unable to compete with services offered by other petroleum enterprises, our results of operations may be adversely affected.
Potential customers of our supply management services may be unwilling to outsource their fuel supply management function, which would limit our ability to increase our sales of these services.
We may be unable to increase our sales of supply management services, which in turn, could limit our ability to increase our revenues, if potential customers are unwilling to contract with us instead of managing their fuel supply needs internally. Because the provision of supply management services is a relatively new industry, potential customers may not realize that they can outsource their fuel supply management function in a cost effective manner. Furthermore, our supply management services require the companies we service to outsource a vital part of their operational activities to us which requires their trust in our ability to fulfill their product needs. These potential customers may consider this function too important to their operations to outsource. Because we may have less name recognition than some of our competitors in the petroleum products industry, it may be difficult for us to obtain additional contracts for supply management services.
A portion of our revenues is generated under contracts that must be renegotiated periodically. The failure to successfully renew significant contracts, or if renewals are obtained on less favorable terms, could adversely affect our revenues and results of operations.
Much of our contract-based revenues are generated under contracts generally having a duration of one year or less. As these contracts expire, they must be renegotiated and extended or replaced. We may not be able to renegotiate, extend or replace these contracts when they expire, or the terms of any renegotiated contracts may not be as favorable as the existing contracts.
In particular, our ability to extend or replace sales contracts could be impacted by competitive factors we cannot control, such as those described above under "We face intense competition in our supply, distribution and marketing activities, as well as in our terminaling activities" and such as the following:
- –>
- the
abundance of storage capacity in the markets we serve;
- –>
- the
failure of our technologies that support our performance under our contracts; and
- –>
- the election by a customer to provide the services for itself, eliminating the need to contract with us.
If we cannot successfully renew significant contracts, or have to renew them on less favorable terms, our revenues from these arrangements could decline and our results of operations could be adversely affected.
72
Our business involves many hazards and operational risks, some of which may not be covered by insurance.
Our operations are subject to the many hazards inherent in the transportation and storage of volatile and toxic petroleum products, including explosions, pollution, release of toxic substances, fires, accidents on rivers or at sea and other hazards that could result in environmental damages, personal injuries, loss of life and suspension of operations. Our operations also are subject to risks associated with natural disasters, adverse weather conditions, terrorist attacks and other events beyond our control. If any of these events were to occur and such event is not fully covered by insureance, we could suffer substantial losses, which could adversely affect our financial condition and results of operations.
Our management has discretion in conducting our risk management activities and may not accurately predict future price fluctuations and therefore expose us to financial risks and reduce our opportunity to benefit from price increases.
We evaluate our exposure to commodity price risk from an overall portfolio basis. Our management has discretion in determining whether and how to manage the commodity price risk associated with our physical and derivative positions. During the three months ended June 30, 2005, we revised our risk management policy to permit management the discretion to manage the commodity price risk relating to all discretionary volumes, including those volumes designated as base operating inventory volumes and the undelivered in-transit volumes supplied to our terminals under the product supply agreement with MSCG. At June 30, 2005, we were managing the commodity price risk associated with approximately 1.0 million barrels of undelivered in-transit volumes supplied to our terminals under the product supply agreement with MSCG and approximately 0.5 million barrels of base operating inventory volumes. At June 30, 2005, we did not manage the commodity price risk on approximately 4.5 million barrels composed of approximately 0.1 million barrels of discretionary inventories held for immediate sale or exchange, approximately 1.5 million barrels of discretionary inventories held for base operations, approximately 2.0 million barrels of fixed-price forward purchase commitments and approximately 0.9 million barrels of product linefill and tank bottoms. We generally do not manage the commodity price risk associated with our fixed-price forward purchase commitments prior to receipt of the product at our terminals, discretionary volumes held for base operations and product linefill and tank bottoms because these positions are expected to be held for the foreseeable future and, thus, these positions are not expected to be sold or exchanged in the ordinary course of business.
To the extent that we do not manage the commodity price risk relating to a position that is subject to commodity price risk and commodity prices move adversely, we could suffer losses. For example, if we decide to not to manage physical product held in discretionary inventories, we could suffer losses at the time we sell the underlying inventory if the price of those products declines. Such losses could be substantial and could adversely affect our financial condition and results of operations.
Our risk management activities may not precisely match our contractual delivery obligations and sales of physical inventory and therefore expose us to financial risks if we must roll futures contracts from period to period or if the price of the commodity in our inventory moves differently than the price of the futures contract we enter into.
When we take title and accept risk of loss upon delivery of refined petroleum products at our terminals by third parties, we enter into futures contracts to sell a corresponding amount of product to
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protect against price fluctuations for the underlying commodity. When we ultimately sell the underlying inventory to a customer, we terminate the related risk management arrangement. In order to accurately manage commodity price risk, we must attempt to predict when we will sell the underlying product. If we fail to accurately predict the timing of those future sales, and the product remains in our inventory longer than the expiration date of the futures contract, we must settle the old futures contract and enter into a new futures contract to sell the product to manage the commodity price risk against the same inventory. If market conditions are adverse for an extended period, we can suffer financial losses. Furthermore, we may be unable to precisely match the underlying product in our futures contracts with the exact type of product in our physical inventory. To the extent that price fluctuations of the product covered by the NYMEX futures contract do not match the price fluctuations of the product in our physical inventory, we could suffer losses which could adversely affect our financial condition and results of operations.
A decrease in correlation between commodity price changes in the cash market for physical delivery and the futures market could increase the cost of our risk management activities and cause us to accept greater commodity price risk.
The use of the NYMEX futures contract as a risk management tool assumes that there is correlation in the movement of prices between commodity prices in the cash market for a physical commodity and the prices of corresponding futures contracts for that commodity on the NYMEX. From time to time, however, there has been decreased correlation between the cash market and the futures market for refined petroleum products and there is a reasonable likelihood that the refined petroleum products market will experience future decreases in correlation between the cash market and the futures markets. A decrease in the correlation between the cash market and the futures market results in an increase in the cost of managing the commodity price risk associated with our discretionary inventories held for immediate sale or exchange. The overall high level of commodity prices combined with the possibility of an increase in the cost of managing the commodity price risk associated with our discretionary inventories held for immediate sale or exchange has in the past resulted in our distributing and transporting fewer barrels of discretionary inventories held for immediate sale or exchange. In addition, increased costs of managing commodity price risk could cause management to decide not to manage the commodity price risk on greater volumes of inventory than might otherwise be the case and we could suffer losses on the sale of the inventory if market conditions were unfavorable. Consequently, periods of decreased correlation between the cash market and the futures market for refined petroleum products can adversely affect our cash flows and results of operations.
Unauthorized speculation on commodity prices or trading of commodity futures contracts could cause us to incur losses.
We maintain a system of policies and controls designed to prevent unauthorized trading or speculation on commodity prices. However, unauthorized speculative trades could occur that may expose us to substantial losses to cover a position in the futures contract, which may, in turn, have a material adverse effect on our cash flows and results of operations.
Changes in commodity prices subject us to margin calls, which may adversely affect our liquidity.
All of our futures contracts are traded on the NYMEX and therefore, require daily settlements for changes in commodity prices. Unfavorable commodity price changes subject us to margin calls that
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require us to provide cash collateral to the NYMEX in amounts that may be material. For example, we may enter into a futures contract to hedge against a fixed-price firm sales commitment to sell and deliver product on a future date. If commodity prices fall before the expiration date of the futures contract, the futures contract will be "out of the money," which means that we will be obligated to deposit funds to cover a margin call based on the decrease in the commodity price. If our obligation to sell and deliver product under a fixed-price firm sales commitment extends over a period of several months, we would be required to fund significant margin deposits, which would decrease our available cash balances until we receive payment from our customer for delivery of the underlying physical product. Such funding requirements could exceed our ability to access our credit line or other sources of capital. If we are unable to meet these margin calls with borrowings or cash on hand, we would be forced to sell product to meet the margin calls, or to terminate the corresponding futures contracts. If we are forced to sell product to meet margin calls, we may have to sell the product at prices or in locations that are not advantageous, and could incur financial losses as a result.
A sustained failure of the complex, proprietary technology, including computer software, that we use to link our facilities and to purchase and sell refined petroleum products could reduce our revenues, cause us to suffer increased expenses and adversely affect our business.
We use complex, proprietary computer software and techniques to purchase refined petroleum product and to market, transport and distribute product to our facilities and customers. A sustained outage could significantly adversely affect our business by preventing us from:
- –>
- acquiring
adequate supplies and delivering them to our terminals and customers;
- –>
- directing
product for delivery on a timely basis to locations and facilities where we have delivery obligations;
- –>
- directing
product for delivery to markets in which we can generate a sales margin;
- –>
- marketing
and selling product on a timely basis or at the best available prices; and
- –>
- being able to properly manage the needs of customers for whom we provide supply management services.
In such event, our customers could suffer financial damage, or determine that we have become an unreliable supplier and could elect to cease purchasing from us, or reduce the volume of product they purchase from us. Therefore, we could lose revenue and suffer increased expenses that would adversely affect our cash flows and results of operations.
Our operations and sales volumes are dependent upon demand for petroleum products by distributors, marketers, wholesalers and commercial end users in the Gulf Coast, Florida, East Coast and Midwest regions of the United States. Any decrease in this demand could adversely affect our business.
Our business depends in large part on the demand for refined petroleum products in the markets served by our transportation and storage network. Our earnings and cash flow are dependent on high sales volumes and our ability to achieve positive sales margins on the product we sell. The volumes of our sales and our margin on sales can be adversely affected by the prices of refined products, which are subject to significant fluctuation depending upon numerous factors beyond our control, including the supply of and demand for gasoline and other refined products. The supply of and demand for
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refined products can be affected by, among other things, changes in domestic and foreign economies, political affairs, terrorism and the threat of terrorism, production levels, industry-wide inventory levels, the availability of imports, the marketing of gasoline and other refined products by competitors, the marketing of competitive fuels, the impact of energy conservation efforts and government regulation. Sales volumes also are affected by regional factors, such as local market conditions, the availability of transportation systems with adequate capacity, transportation costs, fluctuating and seasonal demands for products, changes in transportation and travel patterns, variations in weather patterns from year to year and the operations of companies providing competing services.
We may not be successful in growing through acquisitions or integrating effectively and efficiently any businesses and operations we may acquire. Any future acquisitions may substantially increase the levels of our indebtedness.
Part of our business strategy includes acquiring additional terminal and storage facilities that complement our existing asset base and distribution capabilities. In order to expand our business through selective acquisitions, we must identify those opportunities. We may not be able to identify appropriate opportunities for acquisition which will satisfy our target rates of return, obtain financing on acceptable terms, or negotiate satisfactory terms of such acquisitions. There is no guarantee that any such acquisitions will improve our operating results.
Acquisitions may require substantial capital or the incurrence of substantial indebtedness. As a result, our capital structure and results of operations may change significantly as a result of future acquisitions. Any additional debt financing could significantly increase our interest expense and subject us to various restrictive covenants. Furthermore, you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in connection with any future acquisitions.
Unexpected costs or challenges may arise whenever businesses with different operations and management are combined. Inefficiencies and difficulties may arise because of unfamiliarity with new assets and new geographic areas of any acquired businesses. We believe that successful business combinations will require our management and other personnel to devote significant amounts of time to integrating the acquired businesses with our existing operations. These efforts may temporarily distract their attention from day-to-day business and other business opportunities. In addition, the management of the acquired business may not join our management team. Any change in management may make it more difficult to integrate an acquired business with our existing operations. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we may have no recourse.
The loss of any of our key executive officers could harm our business.
Our future success depends largely on the efforts of our executive management team. The loss of any members of our executive management team could have a material adverse effect on our business. If we experience vacancies in any of these key roles, it could have a material adverse impact on our ability to properly conduct our business operations and pursue our growth initiatives and, as a result, could have a material adverse impact on our overall business, financial condition and results of operations. We do not carry key-man insurance on the life of any of our executive officers. We also do not have employment agreements with our executive officers.
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If TransMontaigne Partners exercises its options to purchase our terminal assets, our business will be primarily focused on marketing and distribution, which may cause our reported revenues, cash flow and results of operations to be less predictable.
In connection with the formation of TransMontaigne Partners and its initial public offering of common units, we granted TransMontaigne Partners options to purchase the substantial majority of our terminal assets over time. Although the exercise of the options is subject to several contingencies, if the options are exercised in full, TransMontaigne Partners will own substantially all of our terminal assets and the business of TransMontaigne Inc. will be primarily focused on the marketing and distribution of refined petroleum products. The terminal services business tends to have predictable revenues and cash flow, while the marketing and distribution business tends to have less predictable revenues and cash flow. As a result, our reported revenues, cash flow and results of operations likely would be less predictable in the event TransMontaigne Partners were to fully exercise its options.
RISKS RELATING TO TRANSMONTAIGNE PARTNERS
TransMontaigne Partners may not have sufficient cash from operations to enable it to pay the minimum quarterly distribution, which could cause the market price for the common units and the value of our subordinated units to decline materially.
TransMontaigne Partners may not have sufficient available cash from operating surplus each quarter to pay the minimum quarterly cash distribution on its units. The amount of cash TransMontaigne Partners can distribute on its units principally depends upon the amount of cash it generates from operations, which will fluctuate from quarter to quarter based on, among other things, terminaling service fees and tariffs, the volume of refined products throughput at its terminals and transported in its pipeline, and the level of its operating costs. In addition, the actual amount of cash TransMontaigne Partners will have available for distribution will depend on other factors such as capital expenditures, the restrictions contained in TransMontaigne Partners' credit facility, debt service requirements, acquisition costs, if any, working capital needs and other operating factors. If TransMontaigne Partners does not generate sufficient cash from operations, or if capital and operating expenses are higher than anticipated, or if other operating expectations are not met, TransMontaigne Partners may not be able to pay the minimum quarterly cash distribution or any amount on the subordinated and common units, in which event the market price of the common units and the value of the subordinated units may decline materially.
Our limited partnership interests in TransMontaigne Partners are subordinated with respect to the receipt of quarterly distributions, so we will not receive a minimum quarterly distribution unless the corresponding quarterly distribution on the common units are paid in full, and we may not receive the entire amount of a minimum quarterly distribution on our subordinated units even if the minimum distribution on the common units is paid in full.
As of May 27, 2005, the date that TransMontaigne Partners completed its initial public offering of common units representing limited partnership interests, the amount of available cash TransMontaigne Partners needed to pay the minimum quarterly distribution for four quarters on its outstanding common units, subordinated units and general partner interest was approximately $11.9 million. If TransMontaigne Partners does not have sufficient cash available for distribution in the future to pay the minimum quarterly distribution on the subordinated units, the income to us from the subordinated units would be reduced and our results of operations would be adversely affected. In addition, if
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TransMontaigne Partners does not have sufficient cash available for distribution in the future to pay the minimum quarterly distribution on the common units, the market value of the common units could be substantially reduced, which would adversely affect the value of the subordinated units held by us.
TransMontaigne Partners may not be able to successfully execute its business plan and may not be able to grow its business, which could adversely affect the value of our investment in the subordinated units and the general partnership interests in TransMontaigne Partners.
TransMontaigne Partners' ability to successfully operate its business and generate sufficient cash to pay the minimum quarterly cash distributions to its unitholders and to allow for growth is subject to a number of risks and uncertainty. Similarly, TransMontaigne Partners may not be able to successfully expand its business through acquiring or constructing additional terminal assets because of various factors, including economic and competitive factors beyond its control. If TransMontaigne Partners is not able to execute its business plan or to grow its business, the market price of the common units is likely to decline, causing the subordinated units and the general partner interest we hold in TransMontaigne Partners also to decline in value.
TransMontaigne Partners controls the timing of its exercise of its options to purchase our fixed assets, which could impose tax burdens on us and could occur at a time when we would not otherwise elect to sell those assets in the open market.
We have granted TransMontaigne Partners options to purchase the substantial majority of our fixed assets over time. The exercise of these options will be subject to the negotiation of a purchase price and a terminaling services agreement relating to the terminals proposed to be purchased, and may be conditioned on obtaining various consents. Nevertheless, TransMontaigne Partners may elect to purchase some or all of the assets subject to the options at a time or times that would not be favorable to us. For example, if the value of our terminal assets were depressed because of adverse market conditions, TransMontaigne Partners would have an incentive to exercise its options in order to pay a lower price for the assets than it might have to pay during better market conditions. In addition, many of the assets subject to the options are carried on our books at depreciated values or historical costs that may not reflect the current market value for those assets. As a result, the exercise of the options by TransMontaigne Partners could cause us to incur substantial tax liabilities on the resultant gains.
The tax treatment of TransMontaigne Partners depends upon its status as a partnership for federal income tax purposes, as well as it not being subject to entity-level taxation by states. If the IRS were to treat TransMontaigne Partners as a corporation, or if it were to become subject to entity-level taxation for state tax purposes, then its cash available for distribution would be substantially reduced.
We own subordinated units representing approximately 39.4% of the limited partnership interests in TransMontaigne Partners, in addition to a 2% general partnership interest. The anticipated after-tax benefit of an investment in the subordinated units of TransMontaigne Partners depends largely on TransMontaigne Partners being treated as a partnership for federal income tax purposes. TransMontaigne Partners has not requested, and does not plan to request, a ruling from the IRS on this or any other matter affecting its tax status.
If TransMontaigne Partners were treated as a corporation for federal income tax purposes, it would pay federal income tax on its income at the corporate tax rate, which is currently a maximum of 35%.
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Cash distributions to the holders of limited partnership interests, including the subordinated units we hold and the common units held by the public, would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to the holders of the limited partnership interests to shelter a substantial portion of such distributions from state and federal income taxes. Because a tax would be imposed upon TransMontaigne Partners as a corporation, its cash available for distribution to limited partners would be substantially reduced. Thus, treatment of TransMontaigne Partners as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to us, as the holder of the subordinated units, as well as to the holders of the common units, likely causing a substantial reduction in the value of the subordinated units and the market price of the common units.
Current tax law may change, causing TransMontaigne Partners to be treated as a corporation for federal income tax purposes or otherwise subjecting it to entity-level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon TransMontaigne Partners as an entity, the cash available for distribution to holders of limited partnership interests would be reduced. TransMontaigne Partners' partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that would subject it to taxation as a corporation, or otherwise would subject it to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly cash distribution amount and the target distribution amounts would be reduced to reflect the impact of that law on TransMontaigne Partners.
If the IRS successfully contests the federal income tax positions taken by TransMontaigne Partners, it may adversely impact the market for its common units, which would adversely affect the value of the subordinated units and the general partner interests held by us, and a substantial portion of the costs of opposing any such contest would be borne by us indirectly through our ownership of subordinated units and the general partnership interest in TransMontaigne Partners.
TransMontaigne Partners has not requested any ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes or any other matter affecting its tax status. The IRS may adopt positions that differ from TransMontaigne Partners' conclusions with respect to its treatment as a partnership for federal income tax purposes. In that case, it may be necessary for TransMontaigne Partners to resort to administrative or court proceedings to sustain some or all of the positions it has taken with respect to its status for tax purposes. A court may not agree with such positions. Any contest with the IRS may materially and adversely impact the market for TransMontaigne Partners common units and the price at which they trade, which would adversely affect the value of the subordinated units held by us. In addition, the costs of any contest with the IRS would result in a reduction in cash available for distribution to the holders of TransMontaigne Partners' common and subordinated units and its general partner, which we own and control and, thus, would be indirectly borne in part by us.
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We control the general partner of TransMontaigne Partners, which has sole responsibility for conducting TransMontaigne Partners' business and managing its operations. We and TransMontaigne Partners have conflicts of interest, which may require the general partner of TransMontaigne Partners to further the interests of TransMontaigne Partners to the detriment of our own interests.
TransMontaigne Services Inc., a wholly owned subsidiary of TransMontaigne Inc., owns and controls the general partner of TransMontaigne Partners. The general partner of TransMontaigne Partners has a fiduciary duty to manage TransMontaigne Partners in a manner beneficial to its unitholders, while the directors and officers of TransMontaigne Services Inc. have a fiduciary duty to manage the general partner in a manner beneficial to us as its owner. Neither the partnership agreement of TransMontaigne Partners, nor any other agreement requires TransMontaigne Partners or us to pursue a business strategy that favors the other. Moreover, some of our officers also will provide services to TransMontaigne Partners. As a result, conflicts of interest may arise between TransMontaigne Partners and its unitholders, on the one hand, and us and our stockholders, on the other hand. When a conflict of interest arises in managing the business of TransMontaigne Partners, the general partner may take an action more favorable to the interests of TransMontaigne Partners and its affiliates than to our interests. Potential conflicts of interest that may arise include the fact that:
- –>
- TransMontaigne
Partners has an economic incentive to seek higher tariff rates and terminaling service fees when possible, while we have an economic incentive to pay
lower tariff rates and terminaling service fees.
- –>
- We
and TransMontaigne Partners may engage in competition with each other under certain circumstances.
- –>
- The
general partner of TransMontaigne Partners will have to allocate costs incurred by it and our other subsidiaries because a portion of the costs are reimbursable
by TransMontaigne Partners. Allocating costs for goods and services that benefit both us and TransMontaigne Partners may be difficult and require subjective judgment in some cases.
- –>
- The
general partner will control the timing of exercise of the options that TransMontaigne Partners has to purchase additional terminals from us. The timing of the
exercise of the options might be more or less favorable to us, depending on prevailing market conditions. For example, if the market for terminal assets were depressed, the general partner may elect
to exercise the options at time when market prices are low, even though it would be in our best interest to wait until market prices are better.
- –>
- Because
we have agreed to give an option to TransMontaigne Partners to purchase any additional terminal assets that we build or acquire in the future that have a
value in excess of $10 million, we may elect not to purchase such additional assets, or may elect to purchase different assets than we otherwise would in the absence of TransMontaigne Partners'
option.
- –>
- The timing or effects of certain transactions, such as acquisitions or capital market transactions, may be more favorable to TransMontaigne Partners than to us.
TransMontaigne Partners and we may engage in competition with each other under certain circumstances.
We have agreed to offer to sell to TransMontaigne Partners certain tangible assets that we acquire or construct (including assets subject to lease or joint venture arrangements controlled by us and extending for more than five years) related to the storage, transportation or terminaling of refined petroleum products in the United States, provided such assets generate qualifying income as defined in
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Section 7704 of the Internal Revenue Code. At the request of TransMontaigne Partners, we must make such an offer within two years of the date of purchase or completion of construction of the particular asset. If TransMontaigne Partners declines such offer, we will be free to use the asset to compete with TransMontaigne Partners, or to sell the asset without restriction. In addition, we could purchase or build tangible assets that compete with TransMontaigne Partners having a value of less than $10 million without being required to offer to sell such assets to TransMontaigne Partners. As discussed above, such competition could result in conflicts of interest that may be resolved in favor TransMontaigne Partners.
We have agreed to indemnify TransMontaigne Partners against environmental liabilities and title defects relating to the operation of the terminals contributed to TransMontaigne Partners in connection with its initial public offering.
In connection with the formation of TransMontaigne Partners and its initial public offering of common units representing limited partnership interests, we agreed to indemnify TransMontaigne Partners for a period of five years against liabilities for environmental violations relating to the operation of the nine terminals and the Razorback Pipeline that were contributed to TransMontaigne Partners, up to an aggregate indemnification obligation of $15 million, subject to a deductive of $250,000. In addition, we agreed to indemnify TransMontaigne Partners against title defects and against the absence of necessary rights of way, easements and other real property interests or related licenses, consents and permits necessary for the operation of such terminals and the pipeline. If we are called upon to indemnify TransMontaigne Partners for any such matters, the cost of such indemnification, including related liabilities, compliance expenses and other expenses could be substantial and the payment of such amounts could adversely affect our financial condition and results of operations.
We depend on TransMontaigne Partners to provide terminal services at its terminals in Florida and transportation sevices on the Razorback Pipeline in order to support our marketing activities to our customers at those locations. The failure of TransMontaigne Partners to provide those services could adversely affect our customer relations and our results of operations.
We have significant customers in the cruise ship and shipping industries and satisfy related delivery obligations through the terminals owned by TransMontaigne Partners in Florida. In addition, we ship substantial amounts of refined petroleum products on the Razorback Pipeline and use TransMontaigne Partners related terminals at Rogers and Mt. Vernon. TransMontaigne Partners has agreed in the terminaling services and transportation agreement to provide us with terminaling services at its terminals and to transport product for us on the Razorback Pipeline. TransMontaigne Partners' terminaling operations are subject to the same risks as many of our terminals. In addition, TransMontaigne Partners' terminals in Florida are subject to risks of damage from tropical storms, which are common in Florida. TransMontaigne Partners also could fail to meet its contractual obligations to provide terminaling and transportation services to us for other reasons, such as a foreclosure by its lenders in the event TransMontaigne Partners defaulted on its outstanding debt obligations. If TransMontaigne Partners fails to meet its obligations under the terminaling services and transportation agreement for any reason, our ability to meet our delivery obligations and to market product to our customers could be disrupted and adversely affect our results of operations.
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RISKS RELATING TO REGULATION AND COMPLIANCE
Our operations are subject to governmental laws and regulations relating to the protection of the environment that may expose us to significant costs and liabilities.
The risk of substantial environmental costs and liabilities is inherent in pipeline, transport and terminal operations and we may incur substantial environmental costs and liabilities. Our operations and activities are subject to significant federal, state and local laws and regulations relating to the protection of the environment. These include, for example, the Federal Clean Air Act and analogous state laws, which impose obligations related to air emissions and the federal Water Pollution Control Act, commonly referred to as the Clean Water Act, and analogous state laws, which regulate discharge of wastewaters from our facilities into state and federal waters. In addition, our operations are also subject to the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, the Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws in connection with the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal. Various governmental authorities including the U.S. Environmental Protection Agency, or the EPA, have the power to enforce compliance with these regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Liability may be incurred without regard to fault under CERCLA, RCRA, and analogous state laws for the remediation of contaminated areas. Private parties, including the owners of properties located near our terminal facilities, or through which our pipeline systems pass, also may have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. Please see "Business—Environmental Matters," for a more detailed discussion of the environmental regulations to which we are subject.
In addition, the possibility exists that new, stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, some of which may be material. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us. Our business may be adversely affected by increased costs because of stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations could adversely affect our products and activities, including processing, storage and transportation, as well as waste management and air emissions. Federal and state agencies also could impose additional safety requirements, any of which could affect our profitability.
We currently own or lease, and have owned or leased, many properties that have been used for many years to terminal or store refined petroleum products or other chemicals. Owners, tenants or users of these properties have disposed of or released hydrocarbons or solid wastes on or under them. Additionally, some sites we operate are located near current or former refining and terminal operations. There is a risk that contamination has migrated from those sites to ours. Increasingly strict environmental laws, regulations and enforcement policies and claims for damages and other similar developments could result in substantial costs and liabilities.
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Federal Energy Regulatory Commission and Department of Transportation regulations may change important aspects of our industry and could reduce our ability to compete and impose significant costs on us or affect our ability to ship product in the quantities we need, which could adversely affect our revenues.
The Federal Energy Regulatory Commission, or FERC, regulates the tariff rates for interstate common carrier operations. Tariff rates are subject to periodic changes and the FERC may approve higher tariff rates for transport of product on the principal pipelines we utilize. The FERC also may change the manner in which tariffs apply, such as changing from tariffs based on shipping history to tariffs based on competitive bidding or some other methodology. Substantial increases or changes in the tariff rates on the principal pipelines we utilize could adversely affect our ability to ship the quantities of product we need or to ship product at economical rates. As a result, we could lose sales or suffer higher transportation expenses, which could adversely affect our results of operations.
In addition, refined petroleum product pipeline operations are subject to regulation by the Department of Transportation. These regulations require, among other things, that pipeline operators engage in a regular program of pipeline integrity testing to assess, evaluate, repair and validate the integrity of their pipelines, which could result in service interruptions or significant and unexpected expenditures on pipelines that we use. We may have to bear those interruptions and expenses through the difference between the tariffs we pay to transport product, and the prices we charge when selling product that we purchase and market. The resulting tariff increases might not be entirely recoverable from our customers, or the resultant price increases to recover such costs could lower demand for product. We direct the delivery of a large amount of product on common carrier pipelines that we do not own, and spurs of those pipelines supply our terminals. If the Department of Transportation determines that a spur of a common carrier pipeline that supplies our terminals requires repair to maintain its integrity, the owner of the pipeline may decide to abandon the spur to our terminal instead of completing the repair work, or could require us to pay for the repair work, either of which would adversely affect our operations at that terminal, or force us to close the terminal.
We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could adversely affect us.
The workplaces associated with the processing and storage facilities and the pipelines we operate are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to our employees, state and local government authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances, could adversely affect our results of operations if we are subjected to fines or significant additional compliance costs.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 composed primarily of our senior executives. Our RMC has responsibility for oversight with respect to our risk management policies and our audit committee of the board of directors approves the financial exposure limits.
Commodity risk
The value of petroleum products in any local delivery market is the sum of the commodity price as reflected on the NYMEX and the basis differential for that local delivery market. The basis differential for any local delivery market is the spread between the cash price in the physical market and the quoted price in the futures markets for the prompt month. For those physical and derivative positions as to which we choose to manage the associated commodity price risk, the primary objective of our risk management strategy is to minimize the financial impact on us from changes in petroleum commodity prices affected by world-wide crude oil and petroleum products supply and demand disruptions (e.g., the Iraq war, OPEC production quotas, disruptions due to hurricanes and other weather-related occurrences, foreign country work stoppages, and major refinery outages). We utilize NYMEX futures contracts to manage the financial impact on us from changes in commodity prices due to "world-wide" events. NYMEX futures contracts are obligations to purchase or sell a specific volume of inventory at a fixed price at a future date. We believe that the utilization of NYMEX futures contracts to manage commodity price risk minimizes the financial impact on us from changes in "world-wide" commodity prices. We generally do not manage the financial impact on us from changes in basis differentials affected by local market supply and demand disruptions (e.g., local pipeline delivery disruptions, local refinery outages, periodic change in local government specifications for gasolines and distillates, local seasonality in product demand, and disruptions due to local weather related occurrences). The impacts on us from changes in basis differentials are as follows:
| Basis Differential |
Change in Basis Differential |
Net Physical Position |
Financial Impact |
|||
|---|---|---|---|---|---|---|
| Futures price in excess of physical market price ("negative basis differential") | Increasing | Long | Loss | |||
| Futures price in excess of physical market price | Increasing | Short | Gain | |||
| Futures price in excess of physical market price | Decreasing | Long | Gain | |||
| Futures price in excess of physical market price | Decreasing | Short | Loss | |||
| Physical market price in excess of futures price ("positive basis differential") | Increasing | Long | Gain | |||
| Physical market price in excess of futures price | Increasing | Short | Loss | |||
| Physical market price in excess of futures price | Decreasing | Long | Loss | |||
| Physical market price in excess of futures price | Decreasing | Short | Gain | |||
84
The physical and derivative positions that expose us to commodity price risk and an indication of whether those positions are actively managed under the our risk management strategies are as follows:
| Position |
Derivative Contract |
Subject to Commodity Price Risk |
Commodity Price Risk Actively Managed |
Long (Short) Position at June 30, 2005 (in 000's barrels) |
|||||
|---|---|---|---|---|---|---|---|---|---|
| Fixed-price forward purchase commitments prior to receipt of the product at our terminal | Yes | Yes | No | 3,000 | |||||
| Discretionary inventory held for immediate sale or exchange | No | Yes | Yes | 2,415 | |||||
| Discretionary volumes held for base operations | No | Yes | No | 2,011 | |||||
| Product linefill and tank bottom volumes | No | Yes | No | 925 | |||||
| Fixed-price forward sale commitments | Yes | Yes | Yes | (1,021 | ) | ||||
| Inventory due to others under exchange agreements | Yes | Yes | Yes | (296 | ) | ||||
| Risk management contracts—NYMEX futures contracts |
Yes | Yes | — | (2,001 | ) | ||||
| Risk management contracts—NYMEX options | Yes | Yes | — | (470 | ) | ||||
Our risk management strategies and practices currently do not qualify for "hedge accounting" for financial reporting purposes because we do not designate and associate the risk management contracts as hedges of specific physical and derivative positions and we do not document and test the effectiveness of the relationship between the risk management contracts and the physical and derivative positions.
We evaluate our exposure to commodity price risk from an overall portfolio basis. Our risk management strategies are intended to maintain a balanced position of discretionary inventories held for immediate sale or exchange, fixed-price forward purchase commitments, inventory due to others under exchange agreements, fixed-price forward sale commitments and risk management contracts, thereby reducing exposure to commodity price fluctuations. To the extent that we do not manage the commodity price risk relating to a position that is subject to commodity price risk and commodity prices move adversely, we could suffer losses on that position. If, however, prices move favorably, we would realize a gain that we would not realize if substantially all of our positions were managed.
During the three months ended June 30, 2005, we revised our risk management policy to permit management the discretion to manage the commodity price risk relating to all discretionary volumes, including those volumes designated as base operating inventory volumes and the undelivered in-transit volumes supplied to our terminals under the product supply agreement with MSCG. At June 30, 2005, we were managing the commodity price risk associated with approximately 1.0 million barrels of undelivered in-transit volumes supplied to our terminals under the product supply agreement with MSCG and approximately 0.5 million barrels of base operating inventory volumes. At June 30, 2005, we did not manage the commodity price risk on approximately 4.5 million barrels composed of approximately 0.1 million barrels of discretionary inventories held for immediate sale or exchange, approximately 1.5 million barrels of discretionary inventories held for base operations, approximately 2.0 million barrels of undelivered in-transit volumes supplied to our terminals under the product supply agreement with MSCG and approximately 0.9 million barrels of product linefill and tank bottoms. We generally do not manage the commodity price risk associated with our discretionary volumes held for base operations and fixed-price forward purchase commitments prior to receipt of the
85
product at our terminals because these positions are expected to be held for the foreseeable future and, thus, these positions are not expected to be sold or exchanged in the ordinary course of business.
Except for our discretionary volumes held for base operations, when we take title and accept risk of loss on refined petroleum products supplied by third parties at our terminals, we enter into futures contracts (i.e., short futures contracts) to sell a corresponding amount of product to protect against price fluctuations for the underlying commodity. In order to effectively manage commodity price risk, we must predict when we will sell the underlying product. When we ultimately sell the underlying inventory to a customer, we terminate the related futures contract. If there is correlation in price changes between the forward price curve in the futures market and the value of physical products in the cash market, the net changes in our variation margin position should be offset by the net operating margins we receive when we sell the underlying discretionary inventory. Therefore, in order to effectively manage commodity price risk, we must predict when we will sell the underlying product. If we fail to accurately predict the timing of those future sales, and the product remains in our inventory longer than the expiration date of the futures contract, we must settle the old futures contract and enter into a new futures contract to sell the product to manage the commodity price risk against the same inventory. Furthermore, we may be unable to precisely match the underlying product in our futures contracts with the exact type of product in our physical inventory. To the extent that price fluctuations of the product covered by the NYMEX futures contract do not match the price fluctuations of the product in our physical inventory, our exposure may not be mitigated.
When we enter into a forward sale commitment to deliver product to a customer in the future at a fixed price, we enter into a futures contract (i.e., a long futures contract) to purchase a corresponding amount of product to protect against price fluctuations for the underlying commodity. When we ultimately deliver the underlying product to a customer, we unwind the related risk management contract. We may be unable to precisely match the underlying product in our futures contracts with the exact type of product in our fixed-price forward sale commitment. To the extent that price fluctuations of the product covered by the NYMEX futures contract do not match the price fluctuations of the product in our fixed-price forward sale commitment, our exposure may not be mitigated.
When our discretionary inventory volumes held for immediate sale or exchange exceeds our fixed-price forward sale commitments, we will maintain a net short futures position. When our fixed-price forward sale commitments exceed our discretionary inventory volumes held for immediate sale or exchange, we will maintain a net long futures position. During a period of rising prices, long (short) futures contracts will increase (decrease) in value resulting in a gain (loss). During a period of declining prices, our long (short) futures contracts will decrease (increase) in value resulting in a loss (gain). Therefore, if we are in a net short futures position during periods of rising commodity prices, we expect to recognize significant net margin before other direct costs and expenses from the sale of the physical product offset by significant net losses on risk management activities resulting in overall net operating margins that are in line with expectations. Conversely, if we are in a net short futures position during periods of declining commodity prices, we expect to recognize minimal, if any, net margin before other direct costs and expenses from the sale of the physical product offset by significant net gains on risk management activities resulting in overall net operating margins that are, again, in line with expectations.
For the years ended June 30, 2005, 2004 and 2003, we recognized net gains (losses) on risk management activities of approximately $33.6 million, $(54.7) million and $(84.1) million, respectively, due principally to rising commodity prices and a net short (long) futures position.
86
The NYMEX requires an initial margin deposit to open a futures contract. At June 30, 2005 and 2004, we had approximately $10.4 million and $3.5 million, respectively, on deposit to cover our initial margin requirements on open NYMEX futures contracts. NYMEX futures contracts also require daily settlements for changes in commodity prices. Unfavorable commodity price changes subject us to variation margin calls that require us to make cash payments to the NYMEX in amounts that may be material. At June 30, 2005, a $0.05 per gallon unfavorable change in commodity prices would have required us to make a cash payment of approximately $5.2 million to cover the variation margin. Conversely, a $0.05 per gallon favorable change in commodity prices would have permitted us to receive approximately $5.2 million. We use our available cash and credit lines to fund these margin calls, but such funding requirements could exceed our ability to access capital.
At June 30, 2005, a $0.05 per gallon unfavorable change in commodity prices relative to our open positions in derivative contracts and risk management contracts would have resulted in the recognition of a loss (realized and unrealized) of approximately $1.7 million. However, the fair value of our discretionary inventory held for immediate sale or exchange would have increased by approximately $5.1 million. The gain from the increase in the fair value of our discretionary inventory volumes held for immediate sale or exchange will not be recognized for financial reporting purposes until those volumes have been sold to customers, which may be in an accounting period subsequent to the accounting period in which the losses on derivative contracts and risk management contracts are recognized.
Interest rate risk
At June 30, 2005, we had no outstanding borrowings under our Senior Secured Working Capital Credit Facility. We are exposed to interest rate risk because the Senior Secured Working Capital Credit Facility is a variable-rate-based credit 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.
87
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following consolidated financial statements should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this annual report.
TransMontaigne Inc. and Subsidiaries:
88
Report of Independent Registered Public Accounting Firm
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, 2005 and 2004, 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, 2005. These consolidated financial statements are the responsibility of TransMontaigne Inc.'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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TransMontaigne Inc. and subsidiaries as of June 30, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended June 30, 2005, in conformity with U.S. generally accepted accounting principles.
As discussed in note 1(i) to the consolidated financial statements, the Company changed its method of accounting for inventories—discretionary volumes in 2003.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of TransMontaigne Inc.'s internal control over financial reporting as of June 30, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated September 12, 2005 expressed an unqualified opinion on management's assessment of, and the effective operation of, internal control over financial reporting.
| KPMG LLP | ||
Denver, Colorado September 12, 2005 |
89
TransMontaigne Inc. and subsidiaries
Consolidated balance sheets
(In thousands)
| |
June 30, 2005 |
June 30, 2004 |
|||||||
|---|---|---|---|---|---|---|---|---|---|
| ASSETS | |||||||||
| Current assets: | |||||||||
| Cash and cash equivalents | $ | 29,721 | $ | 6,158 | |||||
| Restricted cash held by commodity broker | 10,436 | 3,468 | |||||||
| Trade accounts receivable, net | 381,771 | 282,298 | |||||||
| Inventories—discretionary volumes | 274,774 | 236,710 | |||||||
| Unrealized gains on derivative contracts | 7,620 | 11,071 | |||||||
| Deferred tax assets | 18,401 | 11,862 | |||||||
| Prepaid expenses and other | 6,767 | 3,768 | |||||||
| 729,490 | 555,335 | ||||||||
Property, plant and equipment, net |
344,532 |
362,265 |
|||||||
| Product linefill and tank bottom volumes | 24,325 | 25,036 | |||||||
| Investment in Lion Oil Company | 10,131 | 10,131 | |||||||
| Deferred debt issuance costs, net | 9,778 | 10,383 | |||||||
| Other assets, net | 23,725 | 11,206 | |||||||
| $ | 1,141,981 | $ | 974,356 | ||||||
LIABILITIES AND EQUITY |
|||||||||
| Current liabilities: | |||||||||
| Commodity margin loan | $ | — | $ | 1,923 | |||||
| Working capital credit facility | — | 110,000 | |||||||
| Trade accounts payable | 212,040 | 142,395 | |||||||
| Income taxes payable | 29,801 | — | |||||||
| Unrealized losses on derivative contracts | 47,215 | 33,689 | |||||||
| Inventory due to others under exchange agreements | 16,429 | 32,390 | |||||||
| Excise taxes payable | 79,597 | 93,702 | |||||||
| Other accrued liabilities | 20,791 | 19,414 | |||||||
| Deferred revenue—supply chain management services | 3,981 | 3,502 | |||||||
| 409,854 | 437,015 | ||||||||
Other liabilities: |
|||||||||
| Long-term debt | 228,307 | 200,000 | |||||||
| Deferred tax liabilities | 46,413 | 30,424 | |||||||
| Unrealized losses on derivative contracts | 234 | 909 | |||||||
| Total liabilities | 684,808 | 668,348 | |||||||
| Non-controlling interests in TransMontaigne Partners | 81,440 | — | |||||||
| Series B Redeemable Convertible Preferred stock | 49,249 | 77,719 | |||||||
Common stockholders' equity: |
|||||||||
| Common stock | 456 | 411 | |||||||
| Capital in excess of par value | 299,681 | 251,775 | |||||||
| Deferred stock-based compensation | (7,042 | ) | (4,129 | ) | |||||
| Retained earnings (accumulated deficit) | 33,389 | (19,768 | ) | ||||||
| 326,484 | 228,289 | ||||||||
| $ | 1,141,981 | $ | 974,356 | ||||||
See accompanying notes to consolidated financial statements.
90
TransMontaigne Inc. and subsidiaries
Consolidated statements of operations
(In thousands, except per share amounts)
| |
Year ended June 30, 2005 |
Year ended June 30, 2004 |
Year ended June 30, 2003 |
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Supply, distribution and marketing: | |||||||||||||
| Revenues | $ | 8,437,795 | $ | 7,626,814 | $ | 5,520,684 | |||||||
| Cost of product sold and other direct costs and expenses | (8,295,864 | ) | (7,554,012 | ) | (5,467,836 | ) | |||||||
| Net operating margins | 141,931 | 72,802 | 52,848 | ||||||||||
| Terminals, pipelines, and tugs and barges: | |||||||||||||
| Revenues | 111,575 | 106,288 | 84,202 | ||||||||||
| Direct operating costs and expenses | (61,592 | ) | (57,181 | ) | (41,338 | ) | |||||||
| Net operating margins | 49,983 | 49,107 | 42,864 | ||||||||||
| Total net operating margins | 191,914 | 121,909 | 95,712 | ||||||||||
| Costs and expenses: | |||||||||||||
| Selling, general and administrative | (42,849 | ) | (37,532 | ) | (38,328 | ) | |||||||
| Depreciation and amortization | (24,215 | ) | (23,015 | ) | (19,371 | ) | |||||||
| Lower of cost or market write-downs on product linefill and tank bottom volumes | — | (60 | ) | (633 | ) | ||||||||
| Corporate relocation and transition costs | — | — | (1,449 | ) | |||||||||
| Gain (loss) on disposition of assets, net | 129 | (978 | ) | — | |||||||||
| Total costs and expenses | (66,935 | ) | (61,585 | ) | (59,781 | ) | |||||||
| Operating income | 124,979 | 60,324 | 35,931 | ||||||||||
| Other income (expenses): | |||||||||||||
| Dividend income | 389 | 6 | 374 | ||||||||||
| Interest income | 557 | 205 | 286 | ||||||||||
| Interest expense | (24,801 | ) | (26,477 | ) | (14,705 | ) | |||||||
| Other financing costs: | |||||||||||||
| Amortization of deferred debt issuance costs | (2,099 | ) | (3,469 | ) | (1,725 | ) | |||||||
| Write-off of debt issuance costs | (3,392 | ) | — | (5,775 | ) | ||||||||
| Gain on interest rate swap | — | — | 2,224 | ||||||||||
| Total other expenses | (29,346 | ) | (29,735 | ) | (19,321 | ) | |||||||
| Earnings before income taxes, non-controlling interests and cumulative effect of a change in accounting principle | 95,633 | 30,589 | 16,610 | ||||||||||
| Income tax expense | (39,253 | ) | (12,060 | ) | (8,510 | ) | |||||||
| Non-controlling interests share in earnings of TransMontaigne Partners | (562 | ) | — | — | |||||||||
| Earnings before cumulative effect of a change in accounting principle | 55,818 | 18,529 | 8,100 | ||||||||||
| Cumulative effect of a change in accounting principle of $2,092, net of income tax benefit of $795 | — | — | (1,297 | ) | |||||||||
| Net earnings | $ | 55,818 | $ | 18,529 | $ | 6,803 | |||||||
91
TransMontaigne Inc. and subsidiaries
Consolidated statements of operations—(Continued)
(In thousands, except per share amounts)
| |
Year ended June 30, 2005 |
Year ended June 30, 2004 |
Year ended June 30, 2003 |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Computation of earnings (loss) per share: | ||||||||||||
| Net earnings before cumulative effect of a change in accounting principle | $ | 55,818 | $ | 18,529 | $ | 8,100 | ||||||
| Earnings allocable to preferred stock | (11,643 | ) | (4,060 | ) | (3,984 | ) | ||||||
| Cumulative effect of a change in accounting principle | — | — | (1,297 | ) | ||||||||
| Net earnings (loss) attributable to common stockholders | $ | 44,175 | $ | 14,469 | $ | 2,819 | ||||||
| Basic net earnings (loss) per common share: | ||||||||||||
| Net earnings (loss) after amounts allocable to preferred stock and before cumulative effect of a change in accounting principle | $ | 1.10 | $ | 0.37 | $ | 0.10 | ||||||
| Cumulative effect of a change in accounting principle | — | — | (0.03 | ) | ||||||||
| $ | 1.10 | $ | 0.37 | $ | 0.07 | |||||||
| Diluted net earnings (loss) per common share: | ||||||||||||
| Net earnings (loss) after amounts allocable to preferred stock and before cumulative effect of a change in accounting principle | $ | 1.07 | $ | 0.36 | $ | 0.10 | ||||||
| Cumulative effect of a change in accounting principle | — | — | (0.03 | ) | ||||||||
| $ | 1.07 | $ | 0.36 | $ | 0.07 | |||||||
| Weighted average common shares outstanding: | ||||||||||||
| Basic | 40,292 | 39,355 | 39,116 | |||||||||
| Diluted | 52,345 | 51,008 | 39,263 | |||||||||
See accompanying notes to consolidated financial statements.
92
TransMontaigne Inc. and subsidiaries
Consolidated statements of preferred stock and common stockholders' equity
Years ended June 30, 2005, 2004 and 2003
(in thousands)
| |
Preferred stock |
|
Capital in excess of par value |
Deferred stock-based compensation |
|
Total common stockholders' equity |
||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Common stock |
Accumulated deficit |
||||||||||||||||||||
| |
Series A |
Series B |
||||||||||||||||||||
| Balance at June 30, 2002 | $ | 24,421 | $ | 80,939 | $ | 399 | $ | 245,844 | $ | (2,540 | ) | $ | (38,353 | ) | $ | 205,350 | ||||||
| Common stock issued for options exercised | — | — | — | 12 | — | — | 12 | |||||||||||||||
| Common stock repurchased from employees for withholding taxes | — | — | — | (214 | ) | — | — | (214 | ) | |||||||||||||
| Net tax effect arising from stock-based compensation |
— | — | — | 70 | — | — | 70 | |||||||||||||||
| Forfeiture of restricted stock awards prior to vesting |
— | — | — | (238 | ) | 238 | — | — | ||||||||||||||
| Deferred compensation related to restricted stock awards | — | — | 8 | 3,605 | (3,613 | ) | — | — | ||||||||||||||
| Deferred compensation related to non-employee stock options | — | — | — | 260 | (260 | ) | — | — | ||||||||||||||
| Amortization of deferred stock-based compensation |
— | — | — | — | 2,232 | — | 2,232 | |||||||||||||||
| Preferred stock dividends | — | — | — | — | — | (5,594 | ) | (5,594 | ) | |||||||||||||
| Amortization of premium on Series B Redeemable Convertible Preferred stock | — | (1,610 | ) | — | — | — | 1,610 | 1,610 | ||||||||||||||
| Repurchase of Series A Convertible Preferred stock |
(24,421 | ) | — | — | — | — | — | — | ||||||||||||||
| Net earnings | — | — | — | — | — | 6,803 | 6,803 | |||||||||||||||
| Balance at June 30, 2003 | $ | — | $ | 79,329 | $ | 407 | $ | 249,339 | $ | (3,943 | ) | $ | (35,534 | ) | $ | 210,269 | ||||||
| Common stock issued for options exercised | — | — | 1 | 317 | — | — | 318 | |||||||||||||||
| Common stock repurchased from employees for withholding taxes | — | — | (1 | ) | (620 | ) | — | — | (621 | ) | ||||||||||||
| Net tax effect arising from stock-based compensation |
— | — | — | (103 | ) | — | — | (103 | ) | |||||||||||||
| Forfeiture of restricted stock awards prior to vesting |
— | — | (1 | ) | (336 | ) | 337 | — | — | |||||||||||||
| Deferred compensation related to restricted stock awards | — | — | 5 | 3,178 | (3,183 | ) | — | — | ||||||||||||||
| Amortization of deferred stock-based compensation |
— | — | — | — | 2,660 | — | 2,660 | |||||||||||||||
| Preferred stock dividends | — | — | — | — | — | (4,373 | ) | (4,373 | ) | |||||||||||||
| Amortization of premium on Series B Redeemable Convertible Preferred stock | — | (1,610 | ) | — | — | — | 1,610 | 1,610 | ||||||||||||||
| Net earnings | — | — | — | — | — | 18,529 | 18,529 | |||||||||||||||
| Balance at June 30, 2004 | $ | — | $ | 77,719 | $ | 411 | $ | 251,775 | $ | (4,129 | ) | $ | (19,768 | ) | $ | 228,289 | ||||||
| Common stock issued for options exercised | — | — | — | 347 | — | — | 347 | |||||||||||||||
| Common stock repurchased from employees for withholding taxes | — | — | (1 | ) | (816 | ) | — | — | (817 | ) | ||||||||||||
| Net tax effect arising from stock-based compensation |
— | — | — | 272 | — | — | 272 | |||||||||||||||
| Forfeiture of restricted stock awards prior to vesting | — | — | (2 | ) | (1,222 | ) | 1,224 | — | — | |||||||||||||
| Deferred compensation related to restricted stock awards | — | — | 7 | 4,163 | (4,170 | ) | — | — | ||||||||||||||
| Amortization of deferred stock-based compensation |
— | — | — | — | 2,625 | — | 2,625 | |||||||||||||||
| Warrant granted to MSCG in exchange for product supply agreements | — | — | — | 14,600 | — | — | 14,600 | |||||||||||||||
| Preferred stock dividends paid-in-kind | — | 1,087 | — | — | — | — | — | |||||||||||||||
| Preferred stock dividends | — | — | — | — | — | (4,207 | ) | (4,207 | ) | |||||||||||||
| Amortization of premium on Series B Redeemable Convertible Preferred stock | — | (1,546 | ) | — | — | — | 1,546 | 1,546 | ||||||||||||||
| Conversion of Series B Redeemable Convertible Preferred stock into common stock | — | (28,011 | ) | 41 | 27,970 | — | — | 28,011 | ||||||||||||||
| Deferred compensation related to restricted TransMontaigne Partners' common unit awards | — | — | — | 2,592 | (2,592 | ) | — | — | ||||||||||||||
| Net earnings | — | — | — | — | — | 55,818 | 55,818 | |||||||||||||||
| Balance at June 30, 2005 | $ | — | $ | 49,249 | $ | 456 | $ | 299,681 | $ | (7,042 | ) | $ | 33,389 | $ | 326,484 | |||||||
See accompanying notes to consolidated financial statements.
93
TransMontaigne Inc. and subsidiaries
Consolidated statements of cash flows—(Continued)
(In thousands)
| |
Year ended June 30, 2005 |
Year ended June 30, 2004 |
Year ended June 30, 2003 |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Cash flows from operating activities: | ||||||||||||||
| Net earnings | $ | 55,818 | $ | 18,529 | $ | 6,803 | ||||||||
| Adjustments to reconcile net earnings to net cash provided (used) by operating activities: | ||||||||||||||
| Amortization of deferred revenue | (6,906 | ) | (4,983 | ) | (2,485 | ) | ||||||||
| Depreciation and amortization | 24,215 | 23,015 | 19,371 | |||||||||||
| Deferred tax expense | 9,450 | 12,191 | 7,400 | |||||||||||
| Net tax effect arising from stock-based compensation | 272 | (103 | ) | 70 | ||||||||||
| Loss (gain) on disposition of assets, net | (129 | ) | 978 | — | ||||||||||
| Non-controlling interests share in earnings of TransMontaigne Partners | 562 | — | — | |||||||||||
| Amortization of deferred stock-based compensation | 2,625 | 2,660 | 2,232 | |||||||||||
| Amortization of debt issuance costs | 2,099 | 3,469 | 1,725 | |||||||||||
| Repayment of interest rate swap | — | — | (3,205 | ) | ||||||||||
| Write-off of debt issuance costs | 3,392 | — | 5,775 | |||||||||||
| Unrealized loss (gain) on interest rate swap | — | — | (2,224 | ) | ||||||||||
| Net change in unrealized (gains)/losses on long-term derivative contracts | 748 | 3,365 | 6,678 | |||||||||||
| Lower of cost or market write-downs on product linefill and tank bottom volumes | — | 60 | 633 | |||||||||||
| Amortization of prepaid transportation costs | — | 2,159 | — | |||||||||||
| Changes in operating assets and liabilities, net of effects from acquisitions: | ||||||||||||||
| Trade accounts receivable, net | (99,473 | ) | 7,709 | (116,271 | ) | |||||||||
| Inventories—discretionary volumes | (38,065 | ) | (8,236 | ) | 7,836 | |||||||||
| Prepaid expenses and other | 1,201 | (252 | ) | (918 | ) | |||||||||
| Trade accounts payable | 69,646 | 1,801 | 40,313 | |||||||||||
| Income taxes payable | 29,801 | — | — | |||||||||||
| Unrealized (gains)/losses on derivative contracts | 22,940 | 21,959 | 14,782 | |||||||||||
| Inventory due to others under exchange agreements, net | (15,961 | ) | (2,731 | ) | 18,213 | |||||||||
| Excise taxes payable and other accrued liabilities | (11,512 | ) | (11,886 | ) | 26,595 | |||||||||
| Net cash provided by operating activities | 50,723 | 69,704 | 33,323 | |||||||||||
| Cash flows from investing activities: | ||||||||||||||
| Acquisition of Coastal Fuels assets | — | — | (155,968 | ) | ||||||||||
| Acquisition of terminals, pipelines, tugs and barges | (7,970 | ) | (6,761 | ) | (6,983 | ) | ||||||||
| Additions to property, plant and equipment—expansion of facilities | (4,163 | ) | (6,358 | ) | (7,170 | ) | ||||||||
| Additions to property, plant and equipment—maintain existing facilities | (3,720 | ) | (5,118 | ) | (3,649 | ) | ||||||||
| Proceeds from sale of assets | 7,252 | 501 | — | |||||||||||
| Additions to product linefill and tank bottom volumes | — | (3,079 | ) | — | ||||||||||
| Decrease (increase) in restricted cash held by commodity broker | (6,968 | ) | 1,687 | 3,466 | ||||||||||
| Decrease (increase) in other assets | 4 | 845 | (321 | ) | ||||||||||
| Net cash (used) by investing activities | (15,565 | ) | (18,283 | ) | (170,625 | ) | ||||||||
| Cash flows from financing activities: | ||||||||||||||
| Net borrowings (repayments) of debt | (81,693 | ) | (65,000 | ) | 188,000 | |||||||||
| Repayments of commodity margin loan | (1,923 | ) | (2,612 | ) | (6,778 | ) | ||||||||
| Deferred debt issuance costs | (4,886 | ) | (944 | ) | (17,679 | ) | ||||||||
| Common stock issued for options and warrants exercised | 347 | 318 | 12 | |||||||||||
| Common stock repurchased from employees for withholding taxes | (817 | ) | (621 | ) | (214 | ) | ||||||||
| Net proceeds from issuance of TransMontaigne Partners' common and subordinated units | 80,878 | — | — | |||||||||||
| Cash paid to redeem Series A Convertible Preferred stock | — | — | (24,421 | ) | ||||||||||
| Preferred stock dividends paid in cash | (3,501 | ) | (4,373 | ) | (4,501 | ) | ||||||||
| Net cash provided (used) by financing activities | (11,595 | ) | (73,232 | ) | 134,419 | |||||||||
| Increase (decrease) in cash and cash equivalents | 23,563 | (21,811 | ) | (2,883 | ) | |||||||||
| Cash and cash equivalents at beginning of year | 6,158 | 27,969 | 30,852 | |||||||||||
| Cash and cash equivalents at end of year | $ | 29,721 | $ | 6,158 | $ | 27,969 | ||||||||
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TransMontaigne Inc. and subsidiaries
Consolidated statements of cash flows
(In thousands)
| |
Year ended June 30, 2005 |
Year ended June 30, 2004 |
Year ended June 30, 2003 |
||||||
|---|---|---|---|---|---|---|---|---|---|
| Supplemental disclosures of cash flow information: | |||||||||
| Cash paid for (refund of) income taxes | $ | (270 | ) | $ | (28 | ) | $ | 310 | |
| Cash paid for interest expense | $ | 25,183 | $ | 26,028 | $ | 13,050 | |||
See accompanying notes to consolidated financial statements.
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Notes to consolidated financial statements
Years ended June 30, 2005, 2004 and 2003
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) 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 (including TransMontaigne Partners L.P.). All significant inter-company accounts and transactions have been eliminated in consolidation, except for throughput fees, storage fees, pipeline transportation fees, tug and barge fees and other fees charged to our supply, distribution and marketing operations by our or TransMontaigne Partners L.P.'s terminals, pipelines, and tugs and barges. The related inter-company revenues and costs offset within total net operating margins in the accompanying consolidated statement of operations.
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. The following estimates, in our opinion, are subjective in nature, require the exercise of judgment, and involve complex analysis: allowance for doubtful accounts; fair value of inventories—discretionary volumes held for immediate sale or exchange (used to evaluate the financial performance of our business segments); fair value of derivative contracts; and accrued environmental obligations. 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.
(b) Nature of Business and Basis of Presentation
TransMontaigne Inc., a Delaware corporation based in Denver, Colorado, was formed in 1995 to create an independent refined petroleum products distribution and supply company. We are a holding company that conducts operations in the United States primarily in the Gulf Coast, Florida, East Coast, and Midwest regions. We provide integrated terminal, transportation, storage, supply, distribution, and marketing services to refiners, wholesalers, distributors, marketers, and industrial and commercial end-users of refined petroleum products. Our business segments consist of (i) terminal, pipeline, and tug and barge operations, (ii) supply, distribution, and marketing, and (iii) managing the activities of TransMontaigne Partners L.P.
On May 27, 2005, TransMontaigne Partners L.P. ("TransMontaigne Partners"), a consolidated subsidiary of ours, completed its initial public offering of common units. TransMontaigne Partners received net proceeds of approximately $73.0 million for the issuance and sale of 3,852,500 common units, after giving effect to the exercise of the underwriters' over-allotment option, at the initial public offering price of $21.40 per common unit, and the payment of the underwriting discount, structuring fee and other offering costs of approximately $9.5 million. TransMontaigne Partners also received approximately $7.9 million for the issuance and sale of 450,000 subordinated units to an affiliate of Morgan Stanley Capital Group, Inc. in a separate private placement at a price of $17.65 per subordinated unit. We contributed seven refined products terminals located in Florida, the Razorback Pipeline, and two refined products terminals located in Mt. Vernon, Missouri and Rogers, Arkansas to
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TransMontaigne Partners in exchange for a 2% general partner interest, 2,872,266 subordinated units, and a distribution of $111.5 million. We also entered into an omnibus agreement and terminaling and transporation services agreement with TransMontaigne Partners. The omnibus agreement sets forth the terms on which we will provide TransMontaigne Partners with certain general and administrative services, insurance coverage and environmental and other indemnification, among other terms. We also have agreed to provide TransMontaigne Partners with certain options and rights of first refusal to purchase additional refined petroleum product terminal assets, and TransMontaigne Partners has agreed to provide us certain rights of first refusal with respect to its assets and additional terminal capacity added by TransMontaigne Partners in the future. Pursuant to the terminaling and transportation services agreement, we agreed to transport on TransMontaigne Partners' Razorback Pipeline and to throughput in TransMontaigne Partners' terminals a volume of refined product that will result in minimum revenues to TransMontaigne Partners of $5.0 million per calendar quarter.
On February 28, 2003, we acquired all of the outstanding shares of capital stock of Coastal Fuels Marketing, Inc. and its subsidiary, Coastal Tug and Barge, Inc., from a wholly-owned subsidiary of El Paso Merchant Energy Petroleum Company ("EPME-PC"), along with the rights to and operations of the southeast marketing division of EPME-PC (see Note 2 of Notes to consolidated financial statements).
(c) Accounting for Terminal, Pipeline, and Tug and Barge Activities
In connection with our terminal, pipeline, and tug and barge operations, we utilize the accrual method of accounting for revenue and expenses. We generate revenues in our terminal, pipeline, and tug and barge operations from throughput fees, storage fees, transportation fees, ship-assist fees, management fees and cost reimbursements, and fees from other ancillary services. 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; ship-assist revenue is recognized when docking and other services are provided to marine vessels; management fees and cost reimbursements are recognized as the services are performed; and other service revenue is recognized as the services are performed.
Shipping and handling costs attributable to our terminal, pipeline, and tug and barge operations are included in direct operating costs and expenses in the accompanying consolidated statement of operations.
(d) Accounting for Supply, Distribution, and Marketing Activities
In our supply, distribution and marketing operations, we enter into contracts to purchase refined petroleum products, schedule them for delivery to our terminals, as well as terminals owned by third parties, and then sell those products to our customers through rack spot sales, contract sales, and bulk sales. Revenue from our sales of physical inventory is recognized pursuant to the accrual method of accounting (i.e., when cash becomes due and payable to us pursuant to the terms of the sales contracts). Revenue from rack spot sales and contract sales is recognized when the product is delivered to the customer through a truck loading rack or marine fueling equipment. Revenue from bulk sales is recognized when the title to the product is transferred to the customer, which generally occurs upon confirmation of the terms of the sale.
Shipping and handling costs attributable to our supply, distribution, and marketing operations are included in cost of product sold in the accompanying consolidated statement of operations.
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(e) Accounting for Supply Chain Management Services Activities
We provide supply chain management services to companies and governmental entities that desire to outsource their fuel supply function and to reduce the price volatility associated with their fuel supplies. We offer three types of supply chain management services: delivered fuel price management, retail price management, and logistical supply chain management services.
Delivered fuel price management contracts involve the sales of committed quantities of specific motor fuels delivered to our customer's proprietary fleet refueling locations, at fixed prices for terms up to three years. Under retail price management contracts, customers commit for terms up to 18 months to a specific monthly quantity of product within one or more metropolitan areas and agree to a net settlement with us for the difference between a stipulated retail price index and our fixed contract price. Our logistical supply chain management arrangements permit our customers to use our proprietary web-based inventory management system for a fee, which typically is charged on a per gallon basis.
Revenue from sales made pursuant to delivered fuel price management contracts is recognized when title to the product is transferred to the customer, which generally occurs upon delivery of the product at the customer's proprietary fleet refueling location. Revenue from sales made pursuant to retail price management contracts is recognized when title to the product is transferred to the customer, which generally occurs upon lifting of the product by the customer at the retail gasoline station. Revenue from logistical supply chain management services is recognized on a straight-line basis over the term of the contract.
(f) Accounting for Risk Management Activities
We enter into risk management contracts, principally NYMEX futures contracts, to manage 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 held for immediate sale or exchange, inventory volumes due to others under exchange agreements, open positions in derivative contracts, and open positions in risk management contracts. We enter into risk management contracts that are intended to offset the changes in the values of our inventories—discretionary volumes held for immediate sale or exchange and derivative contracts. At June 30, 2005 and 2004, our open positions in risk management contracts were NYMEX futures contracts (purchases and sales).
(g) Accounting for Derivative Contracts
Our contract sales, bulk sales, delivered fuel price management, retail price management, risk management contracts and product supply contracts qualify as derivative instruments pursuant to the requirements of Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), Accounting for Derivative Instruments and Hedging Activities. All derivative contracts are required to be reported as assets and liabilities at fair value in the accompanying consolidated balance sheet in accordance with SFAS No. 133. The fair value of our derivative contracts is included in "Unrealized gains or losses on derivative contracts" in the accompanying consolidated balance sheet. At June 30, 2005 and 2004, there were no unrealized gains or losses on risk management contracts because NYMEX futures contracts require daily settlement for changes in commodity prices on open futures contracts. The net changes in the fair value of our derivative contracts are included in net operating margins attributable to our supply, distribution and marketing operations.
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The estimated fair value of our delivered fuel price management and retail price management contracts at origination is deferred because our estimate of the fair value is not evidenced by quoted market prices or current market transactions for the contracts in their entirety. The deferred revenue is amortized into income over the respective terms of the contracts as the products are delivered to the ground fleet customers. Subsequent changes in the fair value of our delivered fuel price management and retail price management contracts are included in net operating margins attributable to our supply, distribution, and marketing operations.
(h) Presentation of Revenues from Energy-Related and Risk Management Activities
We present revenue from our rack spot sales, contract sales, certain bulk sales, and delivered fuel price management on a gross basis in the accompanying consolidated statement of operations because our obligations under these arrangements are settled via transfer of title and risk of loss of the product to the customer. Revenue from bulk transactions that are "booked out" is presented on a net basis (i.e., product costs are netted directly against gross revenues to arrive at net revenues) in the consolidated statement of operations. Revenue from our retail price management contracts and risk management contracts are presented on a net basis in the accompanying consolidated statement of operations because our obligations under these arrangements are settled on a net cash basis. The logistical supply chain management services fees do not involve the sale of inventory and, therefore, only the service fee is presented in the accompanying consolidated statement of operations.
(i) Accounting for Inventories—Discretionary Volumes
Our inventories—discretionary volumes consist of refined petroleum products, primarily gasolines, distillates, and No. 6 oil. At June 30, 2005 and 2004, our inventories—discretionary volumes are composed of volumes held for immediate sale or exchange and volumes held for base operations. Volumes held for immediate sale or exchange generally are subject to price risk management activities, whereas, volumes held for base operations generally are not subject to price risk management activities. Inventories—discretionary volumes are presented in the accompanying consolidated balance sheet as current assets and are carried at the lower of cost (first-in, first-out) or market (replacement cost) for periods subsequent to September 30, 2002. Prior to October 1, 2002, our inventories—discretionary volumes held for immediate sale or exchange were carried at fair value and our volumes held for base operations, representing minimum volumes in-transit principally in common carrier pipelines, were carried at original cost adjusted for impairment write-downs (see Note 1(k) of Notes to consolidated financial statements). Inventories—discretionary volumes are as follows (in thousands):
| |
June 30, 2005 |
June 30, 2004 |
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
Amount |
Bbls |
Amount |
Bbls |
||||||
| Volumes held for immediate sale or exchange | $ | 153,123 | 2,415 | $ | 55,298 | 1,304 | ||||
| Volumes held for base operations | 121,651 | 2,011 | 181,412 | 4,050 | ||||||
| Inventories—discretionary volumes | $ | 274,774 | 4,426 | $ | 236,710 | 5,354 | ||||
At June 30, 2005 and 2004, the market value of our volumes held for immediate sale or exchange exceeded their cost basis by approximately $2.1 million and $2.3 million, respectively. During the year ended June 30, 2005, we decreased our volumes held for base operations by approximately 2.0 million barrels as a result of our product supply agreement with Morgan Stanley Capital Group, Inc. At June 30, 2005 and 2004, the market value of our volumes held for base operations exceeded their cost basis by approximately $0.2 million and $1.4 million, respectively. During the years ended
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June 30, 2005, 2004 and 2003, we recognized an impairment loss of approximately $4.3 million, $5.3 million and $12.4 million, respectively, due to lower of cost or market write-downs on certain of our base operating inventory volumes.
Through September 30, 2002, we marked to market our energy trading and risk management activities, including physical inventories held for immediate sale or exchange, pursuant to the guidance in 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 operating margins attributable to supply, distribution, and marketing in the period of the change in value. On October 25, 2002, the Emerging Issues Task Force reached a consensus on Issue No. 02-03 ("EITF 02-03"), Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, that eliminated mark-to-market accounting for energy trading and risk management activities that are not derivative contracts. EITF 02-03 also concluded that all physical inventories, including inventory volumes associated with energy trading activities, be carried at the lower of cost or market pursuant to Accounting Research Bulletin ("ARB") No. 43, Chapter 4—Inventory Pricing. As a result, we are no longer permitted to carry our inventories—discretionary volumes held for immediate sale or exchange at fair value effective October 1, 2002. Therefore, we adjusted the carrying amount of our inventories—discretionary volumes to the lower of cost (first-in, first-out) or market pursuant to the requirements of EITF 02-03 through a cumulative effect adjustment for a change in accounting principle. The cumulative effect adjustment is presented in the accompanying consolidated statement of operations for the year ended June 30, 2003, and is calculated as follows (in thousands):
| Inventories—discretionary volumes: |
|
|||||
|---|---|---|---|---|---|---|
| Volumes held for immediate sale or exchange: | ||||||
| Fair value at October 1, 2002 | $ | (180,241 | ) | |||
| Cost basis at October 1, 2002 | 167,597 | |||||
| Excess of fair value over cost basis | (12,644 | ) | ||||
| Base operating volumes: | ||||||
| Original cost basis—original cost as adjusted at October 1, 2002 | (28,959 | ) | ||||
| New cost basis—first-in, first-out at October 1, 2002 | 39,511 | |||||
| Excess of new cost basis over original cost basis | 10,552 | |||||
| Change in carrying amount of inventories—discretionary volumes | (2,092 | ) | ||||
| Income tax effects at 38% | 795 | |||||
| Cumulative effect of a change in accounting principle | $ | (1,297 | ) | |||
(j) Inventory Due to Others Under Exchange Agreements
We enter into exchange agreements generally with major oil companies. Exchange agreements generally are fixed term agreements that involve our receipt of a specified volume of product at one location in exchange for delivery by us of product at a different location. At June 30, 2005 and 2004, current liabilities include inventory due to others under exchange agreements of approximately 296,000 barrels and 661,000 barrels, respectively, with a fair value of approximately $16.4 million and $32.4 million, respectively. The amount recorded represents the fair value of inventory due to others under exchange agreements at the respective balance sheet date.
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(k) Accounting for Product Linefill and Tank Bottom Volumes
Our product linefill and tank bottom 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 volumes in the ordinary course of business and, therefore, we do not manage the commodity price risks associated with these volumes.
Prior to October 1, 2002, our product linefill and tank bottom volumes aggregated approximately 2.0 million barrels of product reflecting tank bottoms, line fill in our proprietary pipelines, and in-transit volumes principally on common carrier pipelines. On October 1, 2002, in connection with the adoption of EITF 02-03, we transferred to inventories—discretionary volumes approximately 1.3 million barrels of product linefill and tank bottom volumes representing the volumes associated with our in-transit volumes. As of June 30, 2005 and 2004, we have approximately 925,000 barrels and 950,000 barrels, respectively, of product reflecting tank bottoms and line fill in our proprietary terminal connections with an adjusted cost basis of $24.3 million and $25.0 million, respectively.
At June 30, 2005 and 2004, our product linefill and tank bottom volumes are presented in the accompanying consolidated balance sheet as non-current assets and are carried at the lower of cost (weighted average) or market (replacement cost). The replacement cost of our product linefill and tank bottom volumes is based on the nearest quoted wholesale market price. At June 30, 2005 and 2004, the market value of our product linefill and tank bottom volumes exceeded their costs basis by approximately $34.8 million and $17.9 million, respectively. During the years ended June 30, 2005, 2004 and 2003, we recognized impairment losses of approximately $nil, $60,000, and $0.6 million, respectively, due to lower of cost or market write-downs on certain of our product linefill and tank bottom volumes.
(l) 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 margin requirements related to open NYMEX futures contracts.
(m) Property, Plant and Equipment
All items of property, plant and equipment are carried at cost. Expenditures that increase capacity, or extend useful lives are capitalized. Routine repairs and maintenance are expensed as incurred and included in direct operating costs and expenses in the accompanying consolidated statement of operations.
We expense as incurred the costs related to the planning and preliminary project stage of our internal-use software and website development efforts. Direct costs incurred in the development stage are capitalized as property, plant and equipment. Costs associated with minor upgrades, enhancements and maintenance are expensed as incurred and included in selling, general and administrative expenses in the accompanying consolidated statement of operations.
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Depreciation is computed using the straight-line and double-declining balance methods. Estimated useful lives are as follows:
| |
Range of Estimated Useful Lives |
Weighted Average Useful Lives |
||
|---|---|---|---|---|
| Terminals, pipelines and equipment | 3 - 25 years | 20 years | ||
| Technology and equipment | 5 - 10 years | 7 years | ||
| Tugs and barges | 15 years | 15 years | ||
| Furniture, fixtures and equipment | 6 - 20 years | 11 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.
(n) Deferred Debt Issuance Costs
Deferred debt issuance costs are amortized using the interest method over the term of the underlying debt instrument. Deferred debt issuance costs are as follows (in thousands):
| |
June 30, 2004 |
Additions |
Amortization |
Write-off |
June 30, 2005 |
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Former working capital credit facility | $ | 3,769 | $ | — | $ | (377 | ) | $ | (3,392 | ) | $ | — | |||
| Senior secured working capital credit facility | 50 | 3,969 | (597 | ) | — | 3,422 | |||||||||
| Senior subordinated notes | 6,564 | — | (1,109 | ) | — | 5,455 | |||||||||
| TransMontaigne Partners' credit facility | — | 917 | (16 | ) | — | 901 | |||||||||
| $ | 10,383 | $ | 4,886 | $ | (2,099 | ) | $ | (3,392 | ) | $ | 9,778 | ||||
(o) Goodwill
Goodwill represents the excess of the aggregate purchase price over the fair value of the identifiable assets acquired. Pursuant to Statement of Financial Accounting Standards ("SFAS") No. 142, goodwill and intangible assets acquired in a purchase business combination that have an indefinite useful life are not amortized, but instead tested for impairment in accordance with the provisions of SFAS No. 142. At June 30, 2005 and 2004, the carrying amount of goodwill was $6.9 million and $6.9 million, respectively, related to our November 1997 acquisition of the ITAPCO terminals. During the years ended June 30, 2005, 2004 and 2003, we performed an impairment review for goodwill during the three months ended June 30, and concluded that goodwill was not impaired.
(p) 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, on an undiscounted basis, 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
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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. We periodically file claims for insurance recoveries of certain environmental remediation costs with our insurance carriers under our comprehensive liability policies. Due to the uncertainty of obtaining recoveries from our insurance carriers, we recognize our insurance recoveries as a credit to income in the period the insurance recoveries are received.
At June 30, 2005 and 2004, we have accrued environmental obligations of approximately $6.1 million and $5.3 million, respectively, representing our best estimate of our remediation obligations (see Note 10 of Notes to consolidated financial statements). During the years ended June 30, 2005 and 2004, we made payments of approximately $0.5 million and $1.0 million, respectively, towards our environmental remediation obligations. During the years ended June 30, 2005 and 2004, we charged to income approximately $1.4 million and $0.7 million, respectively, to increase our estimate of our future environmental remediation obligations. During the years ended June 30, 2005, 2004 and 2003, we received insurance recoveries of approximately $1.2 million, $1.1 million and $0.2 million, respectively.
(q) 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.
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(r) 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, 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 compensation cost for our 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, |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
|||||||||
| Net earnings (loss) attributable to common stockholders: | ||||||||||||
| As reported | $ | 44,175 | $ | 14,469 | $ | 2,819 | ||||||
| Amortization of the fair value of stock options granted to employees | (100 | ) | (223 | ) | (379 | ) | ||||||
| Pro forma | $ | 44,075 | $ | 14,246 | $ | 2,440 | ||||||
| Earnings (loss) per common share | ||||||||||||
| As reported | ||||||||||||
| Basic | $ | 1.10 | $ | 0.37 | $ | 0.07 | ||||||
| Diluted | $ | 1.07 | $ | 0.36 | $ | 0.07 | ||||||
| Pro forma | ||||||||||||
| Basic | $ | 1.09 | $ | 0.36 | $ | 0.06 | ||||||
| Diluted | $ | 1.06 | $ | 0.36 | $ | 0.06 | ||||||
There were no options granted during the years ended June 30, 2005, 2004 and 2003. The weighted average fair value at grant dates for options granted during the years ended June 30, 2002 and 2001, was $3.08 and $2.12, 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 and 2001, were as follows: no dividend yield, expected volatility of 79% and 61%, risk-free rates of 4.49% and 4.95%, and expected lives of 4 years and 5 years, respectively.
Deferred compensation related to restricted stock awards is amortized to income over the related vesting period on an accelerated basis pursuant to FASB Interpretation No. 28.
(s) 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.
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In the event dividends on a per share equivalent basis are declared on our common stock in excess of the dividends declared on the Series B Redeemable Convertible Preferred stock, the Series B Redeemable Convertible Preferred stock will participate as if the Series B Redeemable Convertible Preferred stock was converted into common stock. Accordingly, the Series B Redeemable Convertible Preferred stock has been determined to be a "participating" security for purposes of computing earnings per share.
(t) Adoption of New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("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 adopted the provisions of SFAS No. 143 effective July 1, 2002. In connection with the adoption of SFAS No. 143, we reviewed current laws and regulations governing obligations for asset retirements. Based on that review we did not identify any significant legal obligations associated with the retirement of our tangible long-lived assets. Therefore, the adoption of SFAS No. 143 did not have an impact on our consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which addresses the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires, among other things, a financial instrument issued in the form of shares that is mandatorily redeemable due to an unconditional obligation of the issuer to redeem the shares by transferring its assets at a specified date be classified as a liability on the balance sheet. We were required to adopt the provisions of SFAS No. 150 in our interim financial statements for the quarter ended September 30, 2003. The adoption of SFAS No. 150 did not have an impact on our consolidated financial statements. Pursuant to SFAS No. 150, our Series B Redeemable Convertible Preferred stock is not required to be presented as a liability in the accompanying consolidated balance sheet because holders of our Series B Redeemable Convertible Preferred stock have the right, at the holder's option, to convert the preferred shares into common shares.
(u) Reclassifications
Certain amounts in the prior years have been reclassified to conform to the current year's presentation. Net earnings and stockholders' equity have not been affected by these reclassifications.
We have presented bulk transactions that were "booked out" on a net basis in the consolidated statement of operations (i.e., product costs are netted directly against gross revenues to arrive at net revenues). A "book out" occurs when one party appears more than once for the sale and purchase of a specific grade of refined product for a specific scheduling date to transport product on a particular common carrier pipeline. In that instance, we and other pipeline shippers agree not to schedule or
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deliver the refined product that originates and ends with the same counterparty, but rather settle in cash the amounts due to or from each intervening counterparty, thus booking out the transaction. For the years ended June 30, 2005, 2004 and 2003, we booked out bulk transactions of approximately $2.386.1 million, $3,588.5 million and $2,720.3 million, respectively. The booking out of a bulk transaction has no effect on our net operating margins or net earnings.
(2) ACQUISITIONS
On October 1, 2003, we acquired for cash consideration of approximately $3.1 million a products terminal in Norfolk, Virginia. The terminal increases our presence in the Mid-Atlantic market and includes a docking facility that permits us to receive shipments off and deliver shipments to the water.
On February 28, 2003, we acquired all of the outstanding shares of capital stock of Coastal Fuels Marketing, Inc. and its subsidiary, Coastal Tug and Barge, Inc., from El Paso CGP Company ("CGP") along with the rights to and operations of the southeast marketing division of El Paso Merchant Energy Petroleum Company ("EPME-PC"). The acquisition included five Florida terminals, with aggregate capacity of approximately 4.9 million barrels, and a related tug and barge operation (collectively, the "Coastal Fuels assets"). The Coastal Fuels assets primarily provide sales and storage of bunker fuel, No. 6 oil, diesel fuel and gasoline at Cape Canaveral, Port Manatee/Tampa, Port Everglades/Ft. Lauderdale and Fisher Island/Miami, and storage of asphalt at Jacksonville, Florida. The adjusted purchase price for the acquisition was approximately $156.0 million, including approximately $37.0 million of product inventory. The consolidated financial statements include the results of operations of the Coastal Fuels assets from the closing date of the transaction (February 28, 2003).
On January 31, 2003, we acquired for cash consideration of approximately $6.4 million a products terminal in Fairfax, Virginia. The terminal supplies product to the Washington, D.C. market and increases our presence in the Mid-Atlantic market.
On July 31, 2002, we acquired for cash consideration of approximately $0.6 million a products terminal in Brownsville, Texas. The terminal provides us with additional storage and rail car handling facilities in Brownsville, Texas.
The purchase price of each transaction was allocated to the assets and liabilities acquired based upon the estimated fair value of the assets and liabilities as of the acquisition date. The purchase price was allocated as follows (in thousands):
| |
Norfolk |
Coastal Fuels |
Fairfax |
Brownsville |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Discretionary inventory volumes | $ | 698 | $ | 30,625 | $ | — | $ | — | |||||
| Prepaid expenses and other current assets | — | 2,259 | — | — | |||||||||
| Property, plant and equipment | 1,906 | 118,787 | 6,773 | 630 | |||||||||
| Other assets—acquired intangible | — | 2,500 | — | — | |||||||||
| Product linefill and tank bottom volumes | 859 | 6,311 | — | — | |||||||||
| Trade accounts payable—due diligence costs | — | (1,350 | ) | — | — | ||||||||
| Acquisition related liabilities | (393 | ) | (3,164 | ) | (420 | ) | — | ||||||
| Cash paid, net of cash acquired of $0, $0, $0 and $85, respectively | $ | 3,070 | $ | 155,968 | $ | 6,353 | $ | 630 | |||||
Norfolk acquisition related liabilities include approximately $0.4 million of estimated environmental remediation costs. Coastal Fuels acquisition related liabilities of approximately $3.2 million represent an estimate of the fair value of certain assumed obligations that existed at the date of the Coastal
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Fuels assets acquisition, including estimated environmental remediation costs of approximately $2.5 million, estimated litigation costs of approximately $0.4 million, lease abandonment costs of approximately $130,000 and property taxes of approximately $140,000. Fairfax acquisition related liabilities include approximately $0.4 million of estimated environmental remediation costs.
(3) DISPOSITIONS
During the three months ended June 30, 2005, we liquidated approximately 25,000 barrels of product linefill and tank bottoms for approximately $1.4 million, resulting in a gain on disposition of assets of approximately $0.7 million.
On March 16, 2005, we sold land held for investment purposes in Miami, Florida for approximately $5.8 million, resulting in a gain on disposition of assets of approximately $2.7 million.
During the three months ended December 31, 2004, we settled our obligations with respect to certain NORCO indemnities and recognized a gain of approximately $0.3 million.
During September 2004, we incurred a loss of approximately $3.5 million on the involuntary conversion of our Pensacola terminal facilities due to the damage caused by hurricane Ivan.
On December 30, 2003, we sold our CETEX pipeline system for approximately $0.4 million, resulting in a loss on disposition of assets of approximately $0.7 million. For the six months ended December 31, 2003, we recognized net revenues of approximately $0.4 million, direct operating costs and expenses of approximately $0.3 million, and depreciation and amortization expense of approximately $34,000 related to the operations of the CETEX pipeline system. For the year ended June 30, 2003, we recognized net revenues of approximately $0.5 million, direct operating costs and expenses of approximately $0.7 million, and depreciation and amortization of approximately $0.1 million, related to the operations of the CETEX pipeline system.
(4) CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE
Our primary market areas are located in the Northeast, Midwest, Florida and Southeast regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies, other wholesalers, waste management companies, cruise-ship operators 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 request letters of credit, prepayments or guarantees. We maintain allowances for potentially uncollectible accounts receivable. During the years ended June 30, 2005, 2004 and 2003, we increased the allowance for doubtful accounts through a charge to income of approximately $nil, $0.1 million and $0.7 million, respectively.
Trade accounts receivable, net consists of the following (in thousands):
| |
June 30, 2005 |
June 30, 2004 |
|||||
|---|---|---|---|---|---|---|---|
| Trade accounts receivable | $ | 382,324 | $ | 282,889 | |||
| Less allowance for doubtful accounts | (553 | ) | (591 | ) | |||
| $ | 381,771 | $ | 282,298 | ||||
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No single customer accounted for 10% or more of total revenues for the years ended June 30, 2005, 2004 or 2003.
(5) UNREALIZED GAINS AND LOSSES ON DERIVATIVE CONTRACTS
Unrealized gains and losses on derivative contracts are as follows (in thousands):
| |
June 30, 2005 |
June 30, 2004 |
|||||||
|---|---|---|---|---|---|---|---|---|---|
| Unrealized gains—current asset | $ | 7,620 | $ | 11,071 | |||||
| Unrealized losses—current liability | (47,215 | ) | (33,689 | ) | |||||
| Unrealized losses—long-term liability | (234 | ) | (909 | ) | |||||
| Unrealized losses—liability | (47,449 | ) | (34,598 | ) | |||||
| Net liability position | $ | (39,829 | ) | $ | (23,527 | ) | |||
At June 30, 2005 and 2004, there were no unrealized gains or losses on risk management contracts because NYMEX futures contracts require daily settlement for changes in commodity prices on open futures contracts.
Included in unrealized losses—current liability is an unrealized loss of approximately $3.6 million related to short positions taken in the NYMEX options market.
(6) PREPAID EXPENSES AND OTHER CURRENT ASSETS
Prepaid expenses and other current assets are as follows (in thousands):
| |
June 30, 2005 |
June 30, 2004 |
||||
|---|---|---|---|---|---|---|
| Prepaid insurance | $ | 2,246 | $ | 1,413 | ||
| Amounts due from insurance carrier | 954 | — | ||||
| Asset held for sale | 1,200 | — | ||||
| Prepaid business taxes | 552 | 391 | ||||
| Additive detergent | 985 | 899 | ||||
| Prepaid software maintenance fees | 105 | 134 | ||||
| Other | 725 | 931 | ||||
| $ | 6,767 | $ | 3,768 | |||
Amounts due from insurance carrier represents our remaining estimated proceeds to be received on insurance claims related to the involuntary conversion of our Pensacola terminal facilities due to the damage caused by hurricane Ivan.
Asset held for sale is carried at the lower of cost or fair value less costs of disposition and consists of the land held for sale at our Pensacola terminal facilities.
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(7) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, net is as follows (in thousands):
| |
June 30, 2005 |
June 30, 2004 |
|||||
|---|---|---|---|---|---|---|---|
| Land | $ | 38,710 | $ | 42,886 | |||
| Terminals, pipelines and equipment | 374,213 | 378,258 | |||||
| Technology and equipment | 14,751 | 14,586 | |||||
| Tugs and barges | 27,277 | 18,790 | |||||
| Furniture, fixtures and equipment | 6,784 | 6,747 | |||||
| Construction in progress | 1,747 | 2,561 | |||||
| 463,482 | 463,828 | ||||||
| Less accumulated depreciation | (118,950 | ) | (101,563 | ) | |||
| $ | 344,532 | $ | 362,265 | ||||
(8) INVESTMENT IN LION OIL COMPANY
We own 18.04% of the common stock (representing a 14.4% economic interest) 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. At June 30, 2005 and 2004, the carrying amount of our investment in Lion is approximately $10.1 million. For the years ended June 30, 2005, 2004, and 2003, we recognized dividend income from Lion of approximately $0.4 million, $nil, and $0.4 million, respectively.
(9) OTHER ASSETS
Other assets are as follows (in thousands):
| |
June 30, 2005 |
June 30, 2004 |
||||
|---|---|---|---|---|---|---|
| Prepaid transportation | $ | 326 | $ | 862 | ||
| Goodwill | 6,853 | 6,853 | ||||
| Acquired intangible, net of accumulated amortization of $1,167 and $667, respectively | 1,333 | 1,833 | ||||
| Product supply agreement, net of accumulated amortization of $1,043 and $nil, respectively |
13,557 | — | ||||
| Commodity trading membership | 1,500 | 1,500 | ||||
| Deposits and other assets | 156 | 158 | ||||
| $ | 23,725 | $ | 11,206 | |||
Prepaid transportation relates to our contractual transportation and deficiency agreements with three interstate product pipelines (see Note 19 of Notes to consolidated financial statements).
Goodwill represents the excess of the aggregate purchase price over the fair value of the identifiable assets acquired related to our November 1997 acquisition of the ITAPCO terminals. Goodwill is not amortized, but instead tested for impairment on an annual basis during the three months ended June 30.
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On November 23, 2004, we granted to Morgan Stanley Capital Group warrants to acquire 5.5 million shares of our common stock at an exercise price of $6.60 per share as partial consideration for agreeing to enter into a 7-year product supply agreement (see Note 16 of Notes to consolidated financial statements). The value ascribed to the product supply agreement is being amortized to income over the 7-year term of the agreement, commencing January 2005.
Acquired intangible represents the right to use the Coastal Fuels trade name for a period of five years. The cost of the acquired intangible is being amortized on a straight-line basis over five years.
Commodity trading membership represents the purchase price we paid to acquire two seats on the NYMEX.
(10) OTHER ACCRUED LIABILITIES
Other accrued liabilities are as follows (in thousands):
| |
June 30, 2005 |
June 30, 2004 |
||||
|---|---|---|---|---|---|---|
| Accrued environmental obligations | $ | 6,148 | $ | 5,278 | ||
| Accrued lease abandonment | 1,798 | 2,468 | ||||
| Accrued indemnities—NORCO | 1,000 | 1,300 | ||||
| Accrued transportation and deficiency obligations | 640 | 921 | ||||
| Accrued property taxes | 2,245 | 2,013 | ||||
| Assumed litigation costs—Coastal Fuels assets | 325 | 400 | ||||
| Dividend payable—preferred stock | 708 | 1,093 | ||||
| Interest payable | 1,521 | 1,903 | ||||
| Customer advances and deposits | 1,773 | 437 | ||||
| Accrued expenses and other | 4,633 | 3,601 | ||||
| $ | 20,791 | $ | 19,414 | |||
Accrued Lease Abandonment. We vacated certain office space in Denver, Colorado during June 2003 and we vacated our excess space in Atlanta, Georgia during October 2002. In connection with our acquisition of the Coastal Fuels assets, we vacated a sales office in Coral Gables, Florida (see Note 2 of Notes to consolidated financial statements). 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. At June 30, 2005 and 2004, the accrued liability for lease abandonment costs was approximately $1.8 million and $2.5 million, respectively.
| (in thousands) |
Accrued liability at June 30, 2004 |
Change in estimate charged to expense |
Amounts paid during the period |
Accrued liability at June 30, 2005 |
||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Accrued lease abandonment | $ | 2,468 | $ | 167 | $ | (837 | ) | $ | 1,798 | |||
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We expect to pay the accrued liability of approximately $1.8 million, net of estimated sublease rentals, as follows (in thousands):
| Years ending June 30: |
Lease payments |
Estimated sublease rentals |
Accrued liability |
||||||
|---|---|---|---|---|---|---|---|---|---|
| 2006 | $ | 1,046 | $ | (340 | ) | $ | 706 | ||
| 2007 | 995 | (346 | ) | 649 | |||||
| 2008 | 306 | (159 | ) | 147 | |||||
| 2009 | 313 | (165 | ) | 148 | |||||
| 2010 | 318 | (170 | ) | 148 | |||||
| $ | 2,978 | $ | (1,180 | ) | $ | 1,798 | |||
Accrued indemnities—NORCO. In connection with our sale of the NORCO system 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. During the year ended June 30, 2005, we settled our obligations with respect to certain indemnities at no cost to us and we reduced our estimated liability by approximately $0.3 million.
Assumed litigation costs—Coastal Fuels assets. At June 30, 2004, our estimate of the fair value of the expected litigation costs we assumed in connection with our acquisition of the Coastal Fuels assets was approximately $0.4 million (see Note 2 of Notes to consolidated financial statements). During the year ended June 30, 2005, we paid approximately $75,000 in legal costs associated with preacquisition Coastal Fuels litigation matters, reducing the accrued liability to approximately $0.3 million at June 30, 2005.
(11) DEFERRED REVENUE—SUPPLY CHAIN MANAGEMENT SERVICES
We enter into price management contracts with ground fleet customers that permit these customers to fix the price of their fuel purchases. During the years ended June 30, 2005, 2004 and 2003, we originated retail price management contracts with estimated fair values of approximately $2.3 million, $1.5 million and $2.9 million, respectively, and delivered fuel price management contracts with estimated fair values of approximately $5.1 million, $2.1 million and $2.8 million, respectively, representing the excess of the amounts we expect to receive from the ground fleet customers over our estimate of the forward price curve of the underlying commodity adjusted for basis differentials. We have deferred the estimated fair value of these contracts at origination because our estimate of the fair value is not evidenced by quoted market prices or current market transactions for the contracts in their entirety. We amortize the deferred revenue from these contracts into revenues attributable to our supply, distribution, and marketing operations over the respective terms of the contracts as the products are delivered to the ground fleet customers. During the years ended June 30, 2005, 2004 and 2003, we recognized approximately $6.9 million, $5.0 million and $2.5 million, respectively, in
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revenues attributable to our supply, distribution and marketing operations from the amortization of the deferred revenue from these contracts.
| (in thousands) |
Deferred revenue at June 30, 2004 |
Additions during the period |
Amounts amortized during the period |
Deferred revenue at June 30, 2005 |
||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Retail price management contracts | 1,332 | 2,332 | (2,696 | ) | 968 | |||||||
| Delivered fuel price management contracts | 2,170 | 5,053 | (4,210 | ) | 3,013 | |||||||
| $ | 3,502 | $ | 7,385 | $ | (6,906 | ) | $ | 3,981 | ||||
(12) DEBT
Debt is as follows (in thousands):
| |
June 30, 2005 |
June 30, 2004 |
|||||
|---|---|---|---|---|---|---|---|
| Commodity margin loan | $ | — | $ | 1,923 | |||
| Senior secured working capital credit facility | — | — | |||||
| Former credit facility | — | 110,000 | |||||
| Senior subordinated notes | 200,000 | 200,000 | |||||
| 200,000 | 311,923 | ||||||
| TransMontaigne Partners' credit facility | 28,307 | — | |||||
| 228,307 | 311,923 | ||||||
| Less debt classified as current | — | (111,923 | ) | ||||
| Long-term debt | $ | 228,307 | $ | 200,000 | |||
Scheduled maturities of debt at June 30, 2005 are as follows (in thousands):
| Years ending June 30: |
|
||
|---|---|---|---|
| 2006 | $ | — | |
| 2007 | — | ||
| 2008 | — | ||
| 2009 | — | ||
| 2010 | 228,307 | ||
| Thereafter | — | ||
| $ | 228,307 | ||
Commodity Margin Loan. We currently have a commodity margin loan agreement with a commodity broker that allows us to borrow up to $10.0 million to fund certain initial and variation margin requirements in commodities accounts maintained by us with the commodity broker. 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% (4.88% at June 30, 2005).
Former Credit Facility. On February 28, 2003, we executed a Credit Agreement with UBS AG that initially provided for a $250 million revolving line of credit ("Former Credit Facility") and a $200 million senior secured term loan ("Term Loan"). The Former Credit Facility provided for a
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maximum borrowing line of credit that was the lesser of (i) $275 million and (ii) the borrowing base. The maximum borrowing amount was reduced by the amount of letters of credit that were outstanding. On September 13, 2004, we repaid all outstanding borrowings under the former Working Capital Credit Facility with proceeds from the initial borrowings under our new Senior Secured Working Capital Credit Facility and the Former Credit Facility was cancelled.
Senior Secured Working Capital Credit Agreement. The Senior Secured Working Capital Credit Facility provides for a maximum borrowing line of credit equal to the lesser of (i) $400 million and (ii) the borrowing base ($537 million at June 30, 2005), which is a function, among other things, of our cash, accounts receivable, refined petroleum product inventory, exchanges, margin deposits and certain reserve adjustements as defined in the facility. In addition, outstanding letters of credit ($91 million at June 30, 2005) are counted against the maximum borrowing capacity available at any time. Borrowings under the Senior Secured Working Capital Credit Facility bear interest (at our option) based on a base rate plus an applicable margin, or LIBOR plus an applicable margin; the applicable margins are a function of the average excess borrowing base availability (as defined therein). Interest on loans under the Senior Secured Working Capital Credit Facility will be due and payable periodically, based on the applicable interest rate and related interest period, generally each one, two or three months. The weighted average interest rate on borrowings under the Senior Secured Working Capital Credit Facility was 4.61% during the year ended June 30, 2005. In addition, we will pay a commitment fee ranging from 0.25% to 0.50% per annum on the total amount of the unused commitments. Borrowings under the Senior Secured Working Capital Credit Facility are secured by our cash, accounts receivable, inventories, certain terminal facilities with an orderly liquidation value of not less than $100 million, and certain other current assets. The only financial covenant contained in the new Senior Secured Working Capital Credit Facility is a minimum fixed charge coverage ratio test that is computed on a quarterly basis and becomes applicable whenever the average minimum unused credit line falls below $50 million for the last month of any quarter (average availability was $321 million for the month ended June 30, 2005). In that event, we must satisfy a minimum fixed charge coverage ratio requirement of 110%. The principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, September 13, 2009.
TransMontaigne Partners' Credit Facility. On May 9, 2005, TransMontaigne Partners entered into a $75 million senior secured credit facility. The credit facility provides for a maximum borrowing line of credit equal to the lesser of (i) $75 million and (ii) four times Consolidated EBITDA of TransMontaigne Partners (as defined; $61.3 million at June 30, 2005). Borrowings under the credit facility bear interest (at TransMontaigne Partners' option) based on a base rate plus an applicable margin, or LIBOR plus an applicable margin; the applicable margins are a function of the total leverage ratio (as defined). Interest on loans under the credit facility will be due and payable periodically, based on the applicable interest rate and related interest period, generally either one, two or three months. The weighted average interest rate on borrowings under the TransMontaigne Partners' credit facility was 4.97% during the year ended June 30, 2005. In addition, TransMontaigne Partners will pay a commitment fee ranging from 0.375% to 0.50% per annum on the total amount of the unused commitments. Borrowings under the TransMontaigne Partners' credit facility are secured by a lien on TransMontaigne Partners' assets, including cash, accounts receivable, inventory, general intangibles, investment property, contract rights and real property, except for TransMontaigne Partners' real property located in Florida. The terms of the credit facility include covenants that restrict TransMontaigne Partners' ability to make capital expenditures and cash distributions. The principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, May 9, 2010.
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The TransMontaigne Partners' credit facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the TransMontaigne Partners' credit facility are a total leverage ratio test (not to exceed four times) and an interest coverage ratio test (not to be less than three times).
Senior Subordinated Notes. On May 30, 2003, we consummated the sale and issuance of $200 million aggregate principal amount of 91/8% Senior Subordinated Notes due 2010 and received proceeds of $194.5 million (net of underwriters' discounts of $5.5 million). The Senior Subordinated Notes mature on June 1, 2010 and interest is payable semi-annually in arrears on each June 1 and December 1 commencing on December 1, 2003. The Senior Subordinated Notes are unsecured and subordinated to all of our existing and future senior debt. Upon certain change of control events, each holder of the Senior Subordinated Notes may require us to repurchase all or a portion of its notes at a purchase price equal to 101% of the principal amount thereof, plus accrued interest. The indenture governing the Senior Subordinated Notes contains covenants that, among other things, limit our ability to incur additional indebtedness, pay dividends on, redeem or repurchase our common stock, make investments, make certain dispositions of assets, engage in transactions with affiliates, create certain liens, and consolidate, merge, or transfer all or substantially all of our assets. The Senior Subordinated Notes are fully and unconditionally guaranteed on a joint and several basis by our subsidiaries other than (1) minor subsidiaries that are inactive and have no assets or operations and (2) since May 27, 2005, TransMontaigne Partners L.P. and its general partner and the wholly-owned subsidiaries of TransMontaigne Partners L.P.
We are a holding company for our subsidiaries, with no independent assets or operations. Accordingly, we are dependent upon the distribution of the earnings of our subsidiaries, whether in the form of dividends, advances or payments on account of inter-company obligations, to service our debt obligations. There are no restrictions on our ability to obtain funds from our subsidiaries other than TransMontaigne Partners L.P. TransMontaigne Partners L.P. is not a party to the indenture governing the Senior Subordinated Notes and, therefore, TransMontaigne Partners L.P. and its subsidiaries are not guarantors of the Senior Subordinated Notes.
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Summarized consolidating financial information for TransMontaigne Inc. and the guarantor subsidiaries and TransMontaigne Partners and the non-guarantor subsidiaries as of and for the year ended June 30, 2005 is as follows:
| |
TransMontaigne Inc. and guarantor subsidiaries |
TransMontaigne Partners and non- guarantor subsidiaries |
Eliminations |
Consolidated |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Assets | |||||||||||||
| Current assets | $ | 731,979 | $ | 4,573 | $ | (7,062 | ) | $ | 729,490 | ||||
| Property, plant and equipment, net | 228,488 | 116,044 | — | 344,532 | |||||||||
| Other assets | 71,701 | 2,243 | (5,985 | ) | 67,959 | ||||||||
| $ | 1,032,168 | $ | 122,860 | $ | (13,047 | ) | $ | 1,141,981 | |||||
| Liabilities and Equity | |||||||||||||
| Current liabilities | $ | 409,788 | $ | 7,128 | $ | (7,062 | ) | $ | 409,854 | ||||
| Long-term debt | 200,000 | 28,307 | — | 228,307 | |||||||||
| Other liabilities | 46,647 | — | — | 46,647 | |||||||||
| Non-controlling interests | — | — | 81,440 | 81,440 | |||||||||
| Preferred stock | 49,249 | — | — | 49,249 | |||||||||
| Partners' equity | — | 87,425 | (87,425 | ) | — | ||||||||
| Common stockholders' equity | 326,484 | — | — | 326,484 | |||||||||
| $ | 1,032,168 | $ | 122,860 | $ | (13,047 | ) | $ | 1,141,981 | |||||
| Statement of Operations | |||||||||||||
| Revenues | $ | 8,546,060 | $ | 3,310 | $ | — | $ | 8,549,370 | |||||
| Cost of product sold and direct operating costs and expenses | (8,356,289 | ) | (1,167 | ) | — | (8,357,456 | ) | ||||||
| Costs and expenses | (65,947 | ) | (988 | ) | — | (66,935 | ) | ||||||
| Other income (expenses) | (28,753 | ) | (182 | ) | (411 | ) | (29,346 | ) | |||||
| Income tax expense | (39,253 | ) | — | — | (39,253 | ) | |||||||
| Non-controlling interest share of earnings | — | — | (562 | ) | (562 | ) | |||||||
| Net earnings | $ | 55,818 | $ | 973 | $ | (973 | ) | $ | 55,818 | ||||
| Statement of Cash Flows | |||||||||||||
| Net cash provided by operating activities | $ | 46,298 | $ | 4,425 | $ | — | $ | 50,723 | |||||
| Net cash (used) by investing activities | (15,343 | ) | (222 | ) | — | (15,565 | ) | ||||||
| Net cash (used) by financing activities | (7,633 | ) | (3,962 | ) | — | (11,595 | ) | ||||||
| Increase in cash and cash equivalents | 23,322 | 241 | — | 23,563 | |||||||||
| Cash at beginning of year | 6,158 | — | — | 6,158 | |||||||||
| Cash at end of year | $ | 29,480 | $ | 241 | $ | — | $ | 29,721 | |||||
For all periods ended after the issuance of the Senior Subordinated Notes (May 30, 2003) and before the closing of TransMontaigne Partners' initial public offering (May 27, 2005), we had no subsidiaries that had not guaranteed the Senior Subordinated Notes on a full and unconditional, joint and several basis, other than subsidiaries that were minor. Accordingly, we have not presented consolidating financial information as of and for the years ended June 30, 2004 and 2003, because such information would be substantially duplicative with the accompanying consolidated financial statements. TransMontaigne Partners completed its initial public offering and commenced operations on May 27, 2005.
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(13) PREFERRED STOCK
At June 30, 2005 and 2004, we have authorized the issuance of up to 2,000,000 shares of preferred stock. Preferred stock outstanding is as follows (in thousands, except share data):
| |
June 30, 2005 |
June 30, 2004 |
||||
|---|---|---|---|---|---|---|
| Series B Redeemable Convertible Preferred stock, par value $0.01 per share, 100,000 shares authorized, 47,195 and 72,890 shares issued and outstanding, liquidation preference of $47,195 and $72,890 | $ | 49,249 | $ | 77,719 | ||
At June 30, 2005 and 2004, there are 47,195 and 72,890 shares, respectively, of Series B Redeemable Convertible Preferred Stock outstanding. During the year ended June 30, 2005, 1,087 shares of Series B Redeemable Convertible Preferred stock were issued in lieu of a cash divided related the three months ended June 30, 2004. During the year ended June 30, 2005, 26,782 shares of Series B Redeemable Convertible Preferred stock were converted into approximately 4.1 million shares of common stock at the request of the holder. Subsequent to June 30, 2005, an additional 29,773 shares of Series B Redeemable Convertible Preferred stock were converted into approximately 4.5 million shares of common stock resulting in approximately 17,422 shares of Series B Redeemable Convertible Preferred stock outstanding as of August 23, 2005.
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 by restrictions under the Senior Secured Working Capital Credit 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 (including those relating to sale of substantially all of the assets, delisting of our common stock from a national exchange, change in control, bankruptcy filing, and an event of default that accelerates the repayment of our debt). We have the right to call a portion or all of the outstanding shares of Series B Redeemable Convertible Preferred Stock after June 30, 2005, provided that the average quoted price of our common stock for the preceding thirty days is at least $10.00 per share. The Series B Redeemable Convertible Preferred Stock is convertible, at the 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 (voting collectively as a single class).
On June 28, 2002, we consummated 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 the 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 approximately $21.3 million. The initial
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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 with an equal reduction in the amount of preferred stock dividends recorded for financial reporting purposes.
On June 30, 2003, we redeemed the remaining outstanding shares of Series A Convertible Preferred stock and warrants for approximately $24.4 million in cash.
Preferred stock dividends on the Series A Convertible Preferred stock were $nil, $nil, and $1.2 million for the years ended June 30, 2005, 2004 and 2003, respectively. Preferred Stock dividends on the Series B Redeemable Convertible Preferred Stock were $2.7 million for the year ended June 30, 2005 and $2.8 million for each of the years ended June 30, 2004 and 2003. The amount of the Series B Redeemable Convertible Preferred Stock dividend recognized for financial reporting purposes is composed of the amount of the dividend payable and paid to the holders of the Series B Redeemable Convertible Preferred Stock offset by the amortization of the premium on the carrying amount of the Series B Redeemable Convertible Preferred Stock.
(14) COMMON STOCK
At June 30, 2005, we were authorized to issue up to 150,000,000 shares of common stock with a par value of $0.01 per share. At June 30, 2005 and 2004, there were 45,586,475 shares and 41,114,494 shares issued and outstanding, respectively. Our Senior Secured Working Capital Credit Facility, Senior Subordinated Notes and the certificate of designation of our Series B Redeemable Convertible 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 employees, subject to forfeiture if employment terminates prior to the vesting dates. Upon a change in control, all unvested shares become immediately vested shares. At the date of grant, the market value of shares awarded under the plan is recorded in common stockholders' equity as deferred stock-based compensation. Information about restricted common stock activity for the years ended June 30, 2005, 2004 and 2003 is as follows:
| |
Total shares |
Vested shares |
Unvested shares |
||||
|---|---|---|---|---|---|---|---|
| Outstanding at June 30, 2002 | 1,074,716 | 160,748 | 913,968 | ||||
| Granted | 840,500 | — | 840,500 | ||||
| Cancelled | (51,080 | ) | — | (51,080 | ) | ||
| Repurchased | (49,437 | ) | (49,437 | ) | — | ||
| Vested | — | 187,209 | (187,209 | ) | |||
| Outstanding at June 30, 2003 | 1,814,699 | 298,520 | 1,516,179 | ||||
| Granted | 536,000 | — | 536,000 | ||||
| Cancelled | (71,095 | ) | — | (71,095 | ) | ||
| Repurchased | (101,601 | ) | (101,601 | ) | — | ||
| Vested | — | 356,876 | (356,876 | ) | |||
| Outstanding at June 30, 2004 | 2,178,003 | 553,795 | 1,624,208 | ||||
| Granted | 689,200 | — | 689,200 | ||||
| Cancelled | (229,350 | ) | — | (229,350 | ) | ||
| Repurchased | (131,625 | ) | (131,625 | ) | — | ||
| Vested | — | 446,758 | (446,758 | ) | |||
| Outstanding at June 30, 2005 | 2,506,228 | 868,928 | 1,637,300 | ||||
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During the years ended June 30, 2005, 2004 and 2003, we recognized deferred-stock based compensation associated with restricted common stock granted to employees of approximately $4.2 million, $3.2 million, and $3.6 million, respectively, which is being amortized to income over their respective four-year vesting period.
Amortization of deferred stock-based compensation of approximately $2.6 million, $2.7 million and $2.2 million is included in selling, general and administrative expense for the years ended June 30, 2005, 2004 and 2003, respectively.
On May 27, 2005, the general partner of TransMontaigne Partners awarded 120,000 restricted common units to key employees and directors of the general partner. TransMontaigne Partners recognized deferred-equity based compensation of approximately $2.6 million, which is being amortized to income over the four-year vesting period.
(15) STOCK OPTIONS
We had three stock option plans (the "1991 Plan", the "1995 Plan" and the "1997 Plan") under which stock options had been granted to employees. The 1991 Plan and the 1995 Plan have been terminated as all previously granted stock options have been exercised or cancelled. There were no options granted during the years ended June 30, 2005, 2004 and 2003. Options previously granted under the 1997 Plan expire no later than ten years from the date of grant. Options granted under the 1997 Plan vest 100% upon a change in control or, alternatively, 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, 2005, 2004 and 2003, is as follows:
| |
Terminated Plans |
1997 Plan |
|||||||
|---|---|---|---|---|---|---|---|---|---|
| |
Shares |
Weighted average exercise price |
Shares |
Weighted average exercise price |
|||||
| Outstanding at June 30, 2002 | 230,450 | 5.50 | 1,062,780 | $ | 4.52 | ||||
| Granted | — | — | — | — | |||||
| Cancelled | (230,450 | ) | 5.50 | (55,080 | ) | 4.69 | |||
| Exercised | — | — | (3,200 | ) | 3.75 | ||||
| Outstanding at June 30, 2003 | — | — | 1,004,500 | 4.51 | |||||
| Granted | — | — | — | — | |||||
| Cancelled | — | — | (53,500 | ) | 4.73 | ||||
| Exercised | — | — | (65,500 | ) | 4.85 | ||||
| Outstanding at June 30, 2004 | — | — | 885,500 | 4.48 | |||||
| Granted | — | — | — | — | |||||
| Cancelled | — | — | (31,600 | ) | 3.75 | ||||
| Exercised | — | — | (85,998 | ) | 4.05 | ||||
| Outstanding at June 30, 2005 | — | — | 767,902 | $ | 4.55 | ||||
| Exercisable at June 30, 2005 | — | — | 737,902 | $ | 4.53 | ||||
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Information about stock options outstanding at June 30, 2005, is as follows:
| |
|
|
|
|
Options exercisable |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Range of exercise prices |
Number outstanding |
Weighted average remaining life in years |
Weighted average exercise price |
Number exercisable |
Weighted average exercise price |
||||||||
| 1997 Plan | 3.75 - 7.25 | 755,402 | 5.5 | $ | 4.43 | 725,402 | $ | 4.40 | ||||||
| 11.00 - 13.50 | 11,500 | 3.6 | $ | 11.65 | 11,500 | $ | 11.65 | |||||||
| 17.25 | 1,000 | 2.2 | $ | 17.25 | 1,000 | $ | 17.25 | |||||||
| 767,902 | 737,902 | |||||||||||||
(16) WARRANTS
On November 23, 2004, we granted to Morgan Stanley Capital Group warrants to acquire 5.5 million shares of our common stock at an exercise price of $6.60 per share as partial consideration for agreeing to enter into a 7-year product supply agreement. The fair value of the warrants at the grant date of approximately $14.6 million was recorded as an increase to other assets (product supply agreement—see Note 9 of Notes to consolidated financial statements) and additional paid-in capital. The primary assumptions used to estimate the fair value of the warrants using the Black-Scholes option-pricing model were as follows: no dividend yield, expected volatility of 41%, risk-free interest rate of 3.62%, and a contractual life of 5.3 years.
(17) EMPLOYEE BENEFIT PLAN
We have 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. Employees vest 25% per year in our discretionary contributions, as determined by management based upon our financial performance. Our discretionary contributions for the years ended June 30, 2005, 2004 and 2003, were approximately $0.9 million, $0.8 million and $0.6 million, respectively.
(18) INCOME TAXES
Total income tax expense (benefit) consists of the following (in thousands):
| |
Years ended June 30, |
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
||||||||
| Continuing operations | $ | 39,253 | $ | 12,060 | $ | 8,510 | |||||
| Stockholders' equity | (272 | ) | 103 | (70 | ) | ||||||
| Cumulative effect of a change in accounting principle | — | — | (795 | ) | |||||||
| Total income tax expense | $ | 38,981 | $ | 12,163 | $ | 7,645 | |||||
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Income tax expense (benefit) from continuing operations consists of the following (in thousands):
| |
Years ended June 30, |
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
||||||||
| Current: | |||||||||||
| Federal income taxes | $ | 25,531 | $ | — | $ | — | |||||
| State income taxes | 4,000 | (28 | ) | 315 | |||||||
| Current income taxes | 29,531 | (28 | ) | 315 | |||||||
| Deferred: | |||||||||||
| Federal income taxes | 8,316 | 11,241 | 7,735 | ||||||||
| State income taxes | 1,134 | 950 | 390 | ||||||||
| Deferred income taxes | 9,450 | 12,191 | 8,125 | ||||||||
| Charge (benefit) in lieu of taxes—tax effects of stock-based compensation | 272 | (103 | ) | 70 | |||||||
| Income tax expense | $ | 39,253 | $ | 12,060 | $ | 8,510 | |||||
Income tax expense 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, |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
|||||||
| Computed "expected" tax expense | $ | 33,472 | $ | 10,706 | $ | 5,814 | ||||
| Increase (reduction) in income taxes resulting from: | ||||||||||
| Change in prior years' estimates | 2,341 | 660 | 1,700 | |||||||
| State income taxes, net of federal income tax benefit | 3,337 | 572 | 452 | |||||||
| Other, net | 103 | 122 | 544 | |||||||
| Income tax expense | $ | 39,253 | $ | 12,060 | $ | 8,510 | ||||
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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, 2005 |
June 30, 2004 |
|||||||
|---|---|---|---|---|---|---|---|---|---|
| Deferred tax assets: | |||||||||
| Net operating loss and tax credit carry forwards | $ | — | $ | 33,239 | |||||
| Allowance for doubtful accounts | 210 | 225 | |||||||
| Discretionary inventories and linefill and tank bottom volumes, principally due to differences in accounting methods | 14,134 | 8,224 | |||||||
| Other current assets, principally due to differences in amortization methods | 47 | 117 | |||||||
| Investment in TransMontaigne Partners | 2,230 | — | |||||||
| Intangible assets, principally due to differences in amortization methods and impairment allowances | 4,185 | 4,628 | |||||||
| Accrued environmental obligations | 2,336 | 2,006 | |||||||
| Accrual for lease abandonment | 683 | 938 | |||||||
| Other accrued liabilities, principally due to differences in accounting methods | 991 | 646 | |||||||
| Deferred compensation, principally due to differences in amortization methods | 1,758 | 1,576 | |||||||
| Deferred tax assets | 26,574 | 51,599 | |||||||
| Deferred tax liabilities: | |||||||||
| Plant and equipment, principally due to differences in depreciation methods and impairment allowances | (51,241 | ) | (68,862 | ) | |||||
| Deferred revenue—supply chain management services | — | (295 | ) | ||||||
| Investment in Lion Oil Company, principally due to undistributed earnings | (3,345 | ) | (1,004 | ) | |||||
| Deferred tax liabilities | (54,586 | ) | (70,161 | ) | |||||
| Net deferred tax liabilities | $ | (28,012 | ) | $ | (18,562 | ) | |||
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 of future taxable income including the expected timing of the reversal of taxable temporary differences over the periods in which the deferred tax assets are deductible, management believes the "more likely than not" criterion has been satisfied as of June 30, 2005 and 2004, and that the benefits of future deductible differences will be realized.
On May 27, 2005, we contributed seven refined products terminals located in Florida, the Razorback Pipeline, and two refined products terminals located in Mt. Vernon, Missouri and Rogers, Arkansas to TransMontaigne Partners in exchange for a 2% general partner interest, 120,000 common units, 2,872,266 subordinated units, and a cash distribution of $111.5 million. For income tax reporting purposes, the contribution to TransMontaigne Partners was treated as a taxable transaction, which resulted in the recognition of a taxable gain of approximately $56.4 million. At June 30, 2005, the tax basis of our investment in TransMontaigne Partners exceeds our financial reporting basis by approximately $5.9 million.
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(19) COMMITMENTS AND CONTINGENCIES
Transportation and Deficiency Agreements. In connection with our sale of 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. At June 30, 2004, we had an accrued liability of approximately $0.3 million representing our estimate of the future amounts we expected to pay for the shortfall in our actual volumes and our estimated shortfall in volumes for the remainder of the term of the agreement. Based on actual throughput volumes for the year ended June 30, 2005, we increased our estimate of the liability by $0.3 million resulting in a remaining accrued liability of $0.6 million at June 30, 2005.
We also are subject to three transportation and deficiency agreements ("T&D's") with three separate 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 interstate pipeline company 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 in the future. 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. At June 30, 2004, we had an accrued liability of approximately $0.6 million representing our estimate of the future amounts we expected to pay for our estimated shortfall in volumes for the remainder of the term of the agreements. During the year ended June 30, 2005, we settled our remaining obligations under the T&D agreements for approximately $0.6 million.
At June 30, 2005 and 2004, we included approximately $0.3 million and $0.9 million, respectively, of prepaid transportation in other assets since we have a contractual right, after the end of the term of the T&D agreements, to apply the amounts to charges for using the interstate pipelines in the future (see Note 9 of Notes to consolidated financial statements). During the years ended June 30, 2005 and 2004, we applied approximately $0.5 million and $2.2 million, respectively, of our prepaid transportation to charges for using the interstate pipelines during those respective years.
| (in thousands) |
June 30, 2004 |
Payments during the period |
Amounts applied during the period |
Change in estimate during the period |
June 30, 2005 |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Other assets—prepaid transportation | $ | 862 | $ | — | $ | (536 | ) | $ | — | $ | 326 | |||||
| Accrued liability—T&D obligations | $ | (921 | ) | $ | 581 | $ | — | $ | (300 | ) | $ | (640 | ) | |||
Operating Leases. On April 19, 2002, we executed a 10-year non-cancelable operating lease for new office space to accommodate our corporate headquarters. The lease commenced on October 1, 2002 and July 1, 2003 with respect to approximately one-half of the total leased square footage, respectively. We also lease office space in Atlanta, Georgia, vessel charters, pipeline and terminal capacity, and property and equipment under non-cancelable operating leases that expire through
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January 2013. At June 30, 2005, future minimum lease payments under these non-cancelable operating leases are as follows (in thousands):
| Years ending June 30: |
Office space |
Vessel charters |
Terminal and pipeline capacity |
Property and equipment |
Total |
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2006 | $ | 1,382 | $ | 5,125 | $ | 2,100 | $ | 435 | $ | 9,042 | |||||
| 2007 | 1,377 | — | 1,495 | 362 | 3,234 | ||||||||||
| 2008 | 1,537 | — | 1,082 | 290 | 2,909 | ||||||||||
| 2009 | 1,520 | — | 117 | 171 | 1,808 | ||||||||||
| 2010 | 1,586 | — | 97 | 75 | 1,758 | ||||||||||
| Thereafter | 2,478 | — | — | 194 | 2,672 | ||||||||||
| $ | 9,880 | $ | 5,125 | $ | 4,891 | $ | 1,527 | $ | 21,423 | ||||||
Rental expense under operating leases is as follows (in thousands):
| |
Years ended June 30, |
||||||||
|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
||||||
| Office space | $ | 1,551 | $ | 2,100 | $ | 1,724 | |||
| Vessel charters | 12,148 | 30,356 | 5,867 | ||||||
| Terminal and pipeline capacity | 8,353 | 13,214 | 7,331 | ||||||
| Property and equipment | 587 | 559 | 764 | ||||||
| $ | 22,639 | $ | 46,229 | $ | 15,686 | ||||
(20) LITIGATION
We have been named as a defendant in various lawsuits and we are 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. For the years ended June 30, 2005, 2004 and 2003, we incurred outside third-party legal and settlement expenses of approximately $1.1 million, $0.8 million and $1.6 million, respectively, that are included in selling, general and administrative expenses in the accompanying consolidated statement of operations.
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(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, |
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2005 |
2004 |
2003 |
||||||||
| Net earnings before cumulative effect of a change in accounting principle | $ | 55,818 | $ | 18,529 | $ | 8,100 | |||||
| Earnings allocable to preferred stock | (11,643 | ) | (4,060 | ) | (3,984 | ) | |||||
| Cumulative effect of a change in accounting principle | — | — | (1,297 | ) | |||||||
| Net earnings (loss) attributable to common stockholders | $ | 44,175 | $ | 14,469 | $ | 2,819 | |||||
| Basic weighted average shares | 40,292 | 39,355 | 39,116 | ||||||||
| Effect of dilutive securities: | |||||||||||
| Restricted common stock subject to continuing vesting requirements | 976 | 333 | 22 | ||||||||
| Stock options | 311 | 276 | 125 | ||||||||
| Series B Redeemable Convertible Preferred stock | 10,619 | 11,044 | — | ||||||||
| MSCG warrants | 147 | — | — | ||||||||
| Diluted weighted average shares | 52,345 | 51,008 | 39,263 | ||||||||
| Earnings (loss) per share: | |||||||||||
| Basic | $ | 1.10 | $ | 0.37 | $ | 0.07 | |||||
| Diluted | $ | 1.07 | $ | 0.36 | $ | 0.07 | |||||
We exclude potentially dilutive securities from our computation of diluted earnings per share when their effect would be anti-dilutive. Based on an averaged quoted market price of $6.98 per common share for the year ended June 30, 2005, the following securities were excluded from the earnings per share computation, as their inclusion would have been anti-dilutive:
| |
June 30, 2005 |
June 30, 2004 |
June 30, 2003 |
|||
|---|---|---|---|---|---|---|
| Restricted common stock subject to continuing vesting requirements | — | — | 693,179 | |||
| Common stock issuable upon exercise of stock options | 62,500 | 62,500 | 397,500 | |||
| Common stock issuable upon conversion of Series B Redeemable Convertible Preferred Stock | — | — | 11,043,939 | |||
| 62,500 | 62,500 | 12,134,618 | ||||
For the years ended June 30, 2005 and 2004, certain stock options were excluded because their exercise prices exceeded the average quoted market price of our common stock during the period. For the years ended June 30, 2005 and 2004, the excluded stock options had a weighted average exercise price of $8.22 and $8.22 per share, respectively.
(22) 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, 2005 and 2004.
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.
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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. At June 30, 2005 and 2004, the fair value of the Senior Subordinated Notes was approximately $209 million and $206 million, respectively, based on quoted market prices.
(23) BUSINESS SEGMENTS
We provide integrated terminal, transportation, storage, supply, distribution and marketing services to refiners, wholesalers, distributors, marketers, and industrial and commercial end-users of refined petroleum products. We conduct business in the following business segments:
- –>
- Terminals, pipelines, and tugs and barges—consists of an extensive terminal and pipeline infrastructure
that handles refined petroleum products with transportation connections via pipelines, barges, vessels, rail cars and trucks to our facilities or to TransMontaigne Partners' facilities with an
emphasis on transportation connections primarily through the Colonial, Plantation, TEPPCO, Explorer and Magellan pipeline systems.
- –>
- Supply, distribution and marketing—consists of services for the supply and distribution of refined petroleum products through rack spot sales, contract sales, and bulk sales in the physical and derivative markets, with retail, wholesale, industrial and commercial customers using our terminal racks and marine refueling equipment, and providing related value-added fuel procurement and supply chain management services.
Our chief operating decision maker is our chief executive officer ("CEO"). Our CEO reviews the financial performance of our business segments using a financial performance measure that is referred to by us as "adjusted net operating margins" for purposes of making operating decisions and assessing financial performance. Accordingly, we present "adjusted net operating margins" for each of our two business segments: (i) terminals, pipelines, and tugs and barges and (ii) supply, distribution and marketing.
For the terminals, pipelines, and tugs and barges segment, "adjusted net operating margins" is composed of revenues less direct operating costs and expenses. There are no differences between "adjusted net operating margins" for our terminals, pipelines, and tugs and barges segment and the net operating margins reported for that segment in our accompanying historical financial statements.
Our CEO assesses the "adjusted net operating margins" of our supply, distribution, and marketing segment using financial information that is prepared pursuant to the mark-to-market method of accounting. Our presentation of "adjusted net operating margins" for the supply, distribution and marketing segment differs from net operating margins for that segment as presented in our accompanying historical consolidated statement of operations due to the treatment of our inventories—discretionary volumes (which includes both volumes held for immediate sale or exchange and volumes held for base operating requirements) and purchase commitments under the MSCG supply agreement. Inventories—discretionary volumes held for immediate sale or exchange are reflected at fair value, which matches the treatment of our derivative contracts (e.g., volumes due to others under exchange agreements, forward purchase and sale agreements) and risk management contracts (principally NYMEX futures contracts). Because our inventories—discretionary volumes are composed of refined petroleum products, which are commodities with established trading markets and readily ascertainable market prices, we believe that the financial performance of our supply, distribution and marketing segment can be appropriately evaluated using the mark-to-market method. Our inventories—discretionary volumes are carried at the lower of cost or market in the accompanying historical consolidated balance sheets, while our derivative and risk management contracts are carried at fair
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value. As a result, if refined petroleum product prices are increasing during the end of a quarter, we may report in the accompanying historical statement of operations significant losses on derivative and risk management contracts and significant deferred gains on discretionary inventory volumes held for immediate sale or exchange at the end of that quarter and report significant gains on our beginning inventories—discretionary volumes held for immediate sale or exchange when they are sold in the following quarter. Therefore, the effects of changes in the fair value of our inventories—discretionary volumes held for immediate sale or exchange are included in "adjusted net operating margins" attributable to our supply, distribution and marketing segment in the period in which the fair value actually changes.
Additionally, for purposes of computing our "adjusted net operating margins," our discretionary inventories—base operating volumes and the undelivered in-transit volumes supplied to our terminals by MSCG are maintained at original cost.
The differences between "adjusted net operating margins" for the supply, distribution and marketing segment and the net operating margins reported for that segment in our accompanying historical financial statements are presented as "Inventory Adjustments" in the accompanying "Reconciliation to Earnings Before Income Taxes."
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The financial performance of our business segments is as follows (in thousands):
| |
Year ended June 30, 2005 |
Year ended June 30, 2004 |
Year ended June 30, 2003 |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Terminals, pipelines, and tugs and barges: | |||||||||||||||
| TransMontaigne Partners L.P. facilities | $ | 20,251 | $ | 19,624 | $ | 10,908 | |||||||||
| Brownsville facilities | 4,533 | 3,343 | 3,414 | ||||||||||||
| Southeast facilities | 20,505 | 18,346 | 19,600 | ||||||||||||
| River facilities | 2,845 | 3,551 | 6,547 | ||||||||||||
| Other | 1,849 | 4,243 | 2,395 | ||||||||||||
| Adjusted net operating margins | 49,983 | 49,107 | 42,864 | ||||||||||||
| Supply, distribution and marketing: | |||||||||||||||
| Light oils—marketing margins: | |||||||||||||||
| TransMontaigne Partners L.P. facilities | 9,934 | 10,446 | 12,309 | ||||||||||||
| Brownsville facilities | — | — | — | ||||||||||||
| Southeast facilities | 14,189 | 9,037 | 14,334 | ||||||||||||
| River facilities | 2,834 | 5,168 | 3,268 | ||||||||||||
| Other | 311 | 5,829 | 7,183 | ||||||||||||
| 27,268 | 30,480 | 37,094 | |||||||||||||
| Heavy oils—marketing margins | 13,120 | 13,656 | 6,299 | ||||||||||||
| Supply chain management services margins | 13,498 | 8,624 | 13,017 | ||||||||||||
| Bulk activities and other | 6,376 | (16,204 | ) | 2,808 | |||||||||||
| Trading and risk management activities, net | 14,619 | (823 | ) | (1,139 | ) | ||||||||||
| Adjusted net operating margins | 74,881 | 35,733 | 58,079 | ||||||||||||
| Total adjusted net operating margins | $ | 124,864 | $ | 84,840 | $ | 100,943 | |||||||||
Reconciliation to Earnings Before Income Taxes: |
|||||||||||||||
| Adjusted net operating margins | $ | 124,864 | $ | 84,840 | $ | 100,943 | |||||||||
| Inventory Adjustments: | |||||||||||||||
| Gains recognized on beginning inventories—discretionary volumes | 2,330 | 5,855 | 12,644 | ||||||||||||
| Gains deferred on ending inventories—discretionary volumes held for immediate sale or exchange | (2,125 | ) | (2,330 | ) | (5,855 | ) | |||||||||
| Increase (decrease) in value of light oil volumes nominated under the MSCG product supply agreement prior to delivery at our terminals | 27,135 | — | — | ||||||||||||
| Increase in FIFO cost basis of base operating inventory volumes | 43,978 | 38,878 | 415 | ||||||||||||
| Lower of cost or market write-downs on base operating inventory volumes | (4,268 | ) | (5,334 | ) | (12,435 | ) | |||||||||
| Net operating margins | 191,914 | 121,909 | 95,712 | ||||||||||||
| Other Items: | |||||||||||||||
| Selling, general and administrative expenses | (42,849 | ) | (37,532 | ) | (38,328 | ) | |||||||||
| Depreciation and amortization | (24,215 | ) | (23,015 | ) | (19,371 | ) | |||||||||
| Lower of cost or market write-downs on product linefill and tank bottom volumes | — | (60 | ) | (633 | ) | ||||||||||
| Corporate relocation and transition costs | — | — | (1,449 | ) | |||||||||||
| Gain (loss) on disposition of assets, net | 129 | (978 | ) | — | |||||||||||
| Operating income | 124,979 | 60,324 | 35,931 | ||||||||||||
| Other expense, net | (29,346 | ) | (29,735 | ) | (19,321 | ) | |||||||||
| Earnings before income taxes | $ | 95,633 | $ | 30,589 | $ | 16,610 | |||||||||
127
Supplemental information about our business segments is summarized below (in thousands):
| |
Year ended June 30, 2005 |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Supply, distribution and marketing |
Terminals and pipelines |
Corporate |
Total consolidated |
|||||||||
| Revenues from external customers | $ | 8,437,795 | $ | 45,664 | $ | — | $ | 8,483,459 | |||||
| Inter-segment revenues | — | 65,911 | — | 65,911 | |||||||||
| Revenues | $ | 8,437,795 | $ | 111,575 | $ | — | $ | 8,549,370 | |||||
Identifiable assets |
$ |
724,487 |
$ |
356,743 |
$ |
60,751 |
$ |
1,141,981 |
|||||
Capital expenditures |
$ |
— |
$ |
15,647 |
$ |
206 |
$ |
15,853 |
|||||
| |
Year ended June 30, 2004 |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Supply, distribution and marketing |
Terminals, pipelines, tugs and barges |
Corporate |
Total consolidated |
|||||||||
| Revenues from external customers | $ | 7,626,814 | $ | 43,827 | $ | — | $ | 7,670,641 | |||||
| Inter-segment revenues | — | 62,461 | — | 62,461 | |||||||||
| Revenues | $ | 7,626,814 | $ | 106,288 | $ | — | $ | 7,733,102 | |||||
Identifiable assets |
$ |
561,047 |
$ |
368,434 |
$ |
44,875 |
$ |
974,356 |
|||||
Capital expenditures |
$ |
711 |
$ |
16,040 |
$ |
322 |
$ |
17,073 |
|||||
| |
Year ended June 30, 2003 |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Supply, distribution and marketing |
Terminals, pipelines, tugs and barges |
Corporate |
Total consolidated |
|||||||||
| Revenues from external customers | $ | 5,520,684 | $ | 39,973 | $ | — | $ | 5,560,657 | |||||
| Inter-segment revenues | — | 44,229 | — | 44,229 | |||||||||
| Revenues | $ | 5,520,684 | $ | 84,202 | $ | — | $ | 5,604,886 | |||||
Identifiable assets |
$ |
557,794 |
$ |
378,395 |
$ |
84,277 |
$ |
1,020,466 |
|||||
Capital expenditures |
$ |
649 |
$ |
135,498 |
$ |
862 |
$ |
137,009 |
|||||
128
(24) FINANCIAL RESULTS BY QUARTER (UNAUDITED)
(in thousands, except per share amounts)
| |
Three Months Ended |
|
||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2005 |
|||||||||||||||
| |
September 30, 2004 |
December 31, 2004 |
March 31, 2005 |
June 30, 2005 |
||||||||||||
| Revenues | $ | 2,055,724 | $ | 1,839,056 | $ | 2,275,922 | $ | 2,378,668 | $ | 8,549,370 | ||||||
Net operating margins |
$ |
36,221 |
$ |
31,608 |
$ |
98,280 |
$ |
25,805 |
$ |
191,914 |
||||||
Net earnings |
$ |
3,828 |
$ |
4,249 |
$ |
47,065 |
$ |
676 |
$ |
55,818 |
||||||
Net earnings attributable to common stockholders |
$ |
2,719 |
$ |
3,139 |
$ |
36,721 |
$ |
135 |
$ |
44,175 |
||||||
Earnings per common share |
||||||||||||||||
Basic |
$ |
0.07 |
$ |
0.08 |
$ |
0.92 |
$ |
— |
$ |
1.10 |
||||||
Diluted |
$ |
0.07 |
$ |
0.08 |
$ |
0.90 |
$ |
— |
$ |
1.07 |
||||||
| |
Three Months Ended |
|
||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended June 30, 2004 |
|||||||||||||||
| |
September 30, 2003 |
December 31, 2003 |
March 31, 2004 |
June 30, 2004 |
||||||||||||
| Revenues | $ | 1,738,735 | $ | 1,653,352 | $ | 2,090,484 | $ | 2,250,531 | $ | 7,733,102 | ||||||
Net operating margins |
$ |
25,591 |
$ |
22,781 |
$ |
54,339 |
$ |
19,198 |
$ |
121,909 |
||||||
Net earnings (loss) |
$ |
1,976 |
$ |
(943 |
) |
$ |
18,372 |
$ |
(876 |
) |
$ |
18,529 |
||||
Net earnings (loss) attributable to common stockholders |
$ |
1,285 |
$ |
(1,634 |
) |
$ |
14,351 |
$ |
(1,567 |
) |
$ |
14,469 |
||||
Earnings (loss) per common share |
||||||||||||||||
Basic |
$ |
0.03 |
$ |
(0.04 |
) |
$ |
0.36 |
$ |
(0.04 |
) |
$ |
0.37 |
||||
Diluted |
$ |
0.03 |
$ |
(0.04 |
) |
$ |
0.36 |
$ |
(0.04 |
) |
$ |
0.36 |
||||
129
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
There were no changes in or disagreements with accountants on accounting and financial disclosures during the year ended June 30, 2005.
ITEM 9A. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission's rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (whom we refer to as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of June 30, 2005, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of June 30, 2005, our disclosure controls and procedures were effective.
There were no changes in our internal control over financial reporting that occurred during the fiscal quarter ended June 30, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
Management has used the framework set forth in the report entitled "Internal Control—Integrated Framework" published by the committee of Sponsoring Organizations of the Treadway Commission ("COSO") to evaluate the effectiveness of the Company's internal control over financial reporting. Based on that evaluation, management has concluded that the Company's internal control over financial reporting was effective as of June 30, 2005. Our management's assessment of the effectiveness of the Company's internal control over financial reporting as of June 30, 2005 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears herein.
130
September 9, 2005
| /s/ DONALD H. ANDERSON Donald H. Anderson Chief Executive Officer |
||
/s/ RANDALL J. LARSON Randall J. Larson Chief Financial Officer and Chief Accounting Officer |
131
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
TransMontaigne Inc.:
We have audited management's assessment, included in the accompanying "Management's Report on Internal Control Over Financial Reporting," that TransMontaigne Inc. maintained effective internal control over financial reporting as of June 30, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). TransMontaigne Inc.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that TransMontaigne Inc. maintained effective internal control over financial reporting as of June 30, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, TransMontaigne Inc. maintained, in all material respects, effective internal control over financial reporting as of June 30, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TransMontaigne Inc. and subsidiaries as of
132
June 30, 2005 and 2004, 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, 2005, and our report dated September 12, 2005 expressed an unqualified opinion on those consolidated financial statements. Our report refers to a change in the method of accounting for inventories—discretionary volumes in 2003.
| KPMG LLP | ||
Denver, Colorado September 12, 2005 |
None.
133
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth the names, ages and positions of our directors and executive officers:
| Name |
Age |
Position |
||
|---|---|---|---|---|
| Cortlandt S. Dietler | 83 | Chairman and Director | ||
| Donald H. Anderson | 56 | Vice Chairman, Chief Executive Officer, President and Director | ||
| William S. Dickey | 47 | Executive Vice President and Chief Operating Officer | ||
| Randall J. Larson | 48 | Executive Vice President, Chief Financial Officer and Chief Accounting Officer | ||
| Frederick W. Boutin | 50 | Senior Vice President and Treasurer | ||
| Erik B. Carlson | 58 | Senior Vice President, Corporate Secretary and General Counsel | ||
| Wayne W. Murdy | 61 | Director | ||
| John A. Hill | 60 | Director | ||
| Bryan H. Lawrence | 60 | Director | ||
| Harold R. Logan, Jr. | 57 | Director and Chairman of Finance Committee | ||
| Edwin H. Morgens | 64 | Director and Chairman of Compensation Committee | ||
| Walter P. Schuetze | 71 | Director and Chairman of Audit Committee | ||
Cortlandt S. Dietler has been the Chairman of TransMontaigne Inc. since April 1995, and served as Chief Executive Officer from April 1995 to September 1999. He was the founder, Chairman and Chief Executive Officer of Associated Natural Gas Corporation, a natural gas gathering, processing and marketing company, prior to its 1994 merger with PanEnergy Corporation. From 1994 to 1997, Mr. Dietler served as an Advisory Director to PanEnergy Corporation prior to its merger with Duke Energy Corporation in March 1997. Mr. Dietler currently serves as a Director of Hallador Petroleum Company, Cimarex Energy Co., Forest Oil Corporation and Carbon Energy Corporation. Industry affiliations include: Member, National Petroleum Council; Director, American Petroleum Institute; and past Director, Independent Petroleum Association of America.
Donald H. Anderson has been Director, Vice Chairman and Chief Executive Officer of TransMontaigne Inc. since September 1999, and has served as President since January 2000. From 1997 through September 1999, Mr. Anderson was the Executive Director and a Principal of Western Growth Capital LLC, a Colorado-based private equity investment and consulting firm. From December 1994 until March 1997, Mr. Anderson was Chairman, President and Chief Executive Officer of PanEnergy Services, PanEnergy's non-jurisdictional operating subsidiary. From December 1994 until March 1997, Mr. Anderson also served as a Director of TEPPCO Partners, LLP. Mr. Anderson was previously President, Chief Operating Officer and Director of Associated Natural Gas Corporation from 1989 until its merger with PanEnergy Corporation in 1994. Mr. Anderson is a director of Bear Paw Energy, LLC.
William S. Dickey has been an Executive Vice President and Chief Operating Officer of TransMontaigne Inc. since May 2000. From January 1999 until May 2000, Mr. Dickey was a Vice President of TEPPCO Partners, LLP. From 1994 to 1998, Mr. Dickey served as Vice President and Chief Financial Officer of Associated Natural Gas, Inc. and its successor, Duke Energy Field Services.
Randall J. Larson has been an Executive Vice President and Chief Accounting Officer of TransMontaigne Inc. since May 2002. Mr. Larson served as Executive Vice President, Chief Accounting Officer and Controller of TransMontaigne Inc. from May 2002 until January 2003 and
134
was appointed Chief Financial Officer on January 1, 2003. From July 1994 through April 2002, Mr. Larson was a partner with KPMG LLP, most recently in KPMG's San Jose, California office. Prior to joining the San Jose office in 1996, Mr. Larson was a partner in KPMG's Department of Professional Practice in the national office in New York City. From July 1992 to June 1994, Mr. Larson served as a Professional Accounting Fellow in the Office of Chief Accountant of the Securities and Exchange Commission. Mr. Larson began his accounting career with KPMG in 1981 in the Denver, Colorado office.
Frederick W. Boutin has been Senior Vice President and Treasurer of the Company since June 2003. Mr. Boutin also served as Senior Vice President of the Company from September 1996 to March 2002. In addition, Mr. Boutin served as Vice President of TransMontaigne Product Services Inc. from February 2002 to June 2003; Vice President of Coastal Tug and Barge, Inc. from February 2003 to June 2003; Vice President of Coastal Fuels Marketing, Inc. from February 2003 to June 2003; and Senior Vice President and Director of TransMontaigne Transport Inc. from February 2002 to the present. From 1985 to 1995, Mr. Boutin served as a Vice President of Associated Natural Gas, Inc. and its successor, Duke Energy Field Services.
Erik B. Carlson has been the Senior Vice President, Corporate Secretary and General Counsel of TransMontaigne Inc. since January 1998. From February 1983 until January 1998, Mr. Carlson served as Senior Vice President, General Counsel and Corporate Secretary of Associated Natural Gas Corporation and its successor, Duke Energy Field Services.
Wayne W. Murdy has been a Director of TransMontaigne Inc. since September 2003. Mr. Murdy is the Chief Executive Officer and Chairman of the Board of Directors of Newmont Mining Corporation ("Newmont"), an international mining company headquartered in Denver, Colorado. Newmont is the world's largest gold producer with mining operations and assets located on five continents. Prior to becoming the Chief Executive Officer of Newmont in 2001 and Chairman of the Board of Directors of Newmont in 2002, Mr. Murdy served as President of Newmont from 1999 to 2002, Executive Vice President and Chief Financial Officer from 1996 to 1999 and Senior Vice President and Chief Financial Officer from 1992 to 1996. Mr. Murdy has been a Director of Newmont since 1999. Mr. Murdy also serves as a Trustee of the Denver Art Museum.
John A. Hill has been a Director of TransMontaigne Inc. since April 1995. Mr. Hill has been Vice Chairman of the Board, Managing Director and founder of First Reserve Corporation, ("First Reserve"), a private equity fund sponsor specializing in management buyouts and acquisitions in the energy and energy-related industries since June 2000. From 1983 until June 2000, Mr. Hill was Chairman of First Reserve. Mr. Hill is Chairman of the Board of Trustees of the Putnam Mutual Funds in Boston and serves as a Director of Devon Energy Corporation and various private companies owned by First Reserve and Continuum Health Partners.
Bryan H. Lawrence has been a Director of TransMontaigne Inc. since April 1995. From 1996 to 1997, Mr. Lawrence served as Managing Director of Dillon, Read & Co. Inc., an investment banking firm. In 1997, Mr. Lawrence established Yorktown Partners LLC to manage Yorktown Energy Partners III, L.P. and predecessor partnerships previously managed by Dillon, Read & Co. Inc. Mr. Lawrence also serves as a Director of Vintage Petroleum, Inc., D&K Healthcare Services, Inc., Hallador Petroleum Company and Crosstex Energy, L.P. (each a United States public company), and Cavell Energy Corporation (a Canadian public company), and certain privately-owned companies in which affiliates of Yorktown Partners LLC hold equity interests including PetroSantander Inc., Savoy Energy, L.P., Athanor BV, Camden Resources, Inc., Crosstex Energy Holdings Inc., ESI Energy Services Inc., Ellora Energy Inc., Dernick Resources Inc., Cinco Natural Resources Corporation, Peak Energy Resources, Inc., Approach Resources Inc., Century Exploration Company and Compass Petroleum Ltd.
135
Harold R. Logan, Jr. has been a Director of TransMontaigne Inc. since April 1995 and has provided consulting services to TransMontaigne Inc. on a contractual basis since January 2003. He served as Executive Vice President and Treasurer of TransMontaigne Inc. from April 1995 to December 2002 and as Chief Financial Officer of TransMontaigne Inc. from March 2000 to December 2002. From 1985 to 1994, Mr. Logan was Senior Vice President/Finance and a Director of Associated Natural Gas Corporation. Prior to joining Associated Natural Gas Corporation, Mr. Logan was with Dillon, Read & Co. Inc. and Rothschild, Inc. Mr. Logan also serves as Director of Lion Oil Company, Suburban Propane Partners, L.P., Graphic Packaging Corporation, The Houston Exploration Company and Rivington Capital Advisors LLC.
Edwin H. Morgens has been a Director of TransMontaigne Inc. since June 1996. Mr. Morgens has been Chairman of Morgens, Waterfall, Vintiadis & Company, Inc., an investment management firm, since 1970. In addition, Mr. Morgens serves as a Director of Programmer's Paradise, Inc.
Walter P. Schuetze has been a Director of TransMontaigne Inc. and Chairman of the Company's Audit Committee, since October 1, 2002. Mr. Schuetze began his accounting career in 1957 with the public accounting firm of Eaton & Huddle in San Antonio, Texas, which merged with Peat, Marwick, Mitchell & Co. (now KPMG LLP) in 1958. He was a partner in KPMG from 1965 to 1973, when he was appointed to the Financial Accounting Standards Board, after which he again served as a partner in KPMG LLP from 1976 to 1992. In January 1992, Mr. Schuetze was appointed Chief Accountant to the Securities and Exchange Commission of the United States of America and served in that capacity through March 1995, when he retired. In November 1997, Mr. Schuetze was appointed Chief Accountant of the Commission's Division of Enforcement and served in that capacity through mid-February 2000. He then served as a consultant to the Commission's Division of Enforcement from March 2000 through February 2002 on matters involving accounting and auditing. Since April 1, 2002, he also has been a member of the Board of Directors of Computer Associates International, Inc. and currently serves as chairman of that company's audit committee. Since March 2003, he has been a member of the Board of Directors of NES Rentals and currently serves as chairman of that company's audit committee.
There are no family relationships among any of our directors and our executive officers.
Audit Committee of the Board of Directors
The Board of Directors has a standing Audit Committee. The Audit Committee consists of Walter P. Schuetze, Edwin H. Morgens and Wayne W. Murdy. Our Board has determined that each member of the Audit Committee is independent under Section 303.02 of the New York Stock Exchange listing standards and Section 10A(m)(3) of the Securities Exchange Act of 1934, as amended. Mr. Schuetze has been designated by the Board as an "audit committee financial expert" as that term is defined in Item 401(h) of Regulation S-K based upon his education and employment experience as more fully detailed in Mr. Schuetze's biography set forth above.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our executive officers and directors, and persons who own more than ten percent of a registered class of our equity securities (collectively, "Reporting Persons") to file with the SEC initial reports of ownership and reports of changes in ownership of the common stock and other equity securities of TransMontaigne Inc. Specific due dates for those reports have been established, and we are required to report herein any failure to file reports by those due dates. Reporting Persons are also required by SEC regulations to furnish TransMontaigne Inc. with copies of all Section 16(a) reports they file.
136
To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required during the fiscal year ended June 30, 2005, all Section 16(a) filing requirements applicable to such Reporting Persons were complied with.
Code of Business Conduct and Ethics
The Audit Committee has adopted a Code of Business Conduct and Ethics (the "Code"), which has been ratified and approved by the Board. The Code applies to all employees, officers and Directors of TransMontaigne Inc. and its subsidiaries. The Audit Committee has also adopted a Code of Ethics for Senior Financial Officers (the "Financial Ethics Code"), which has been ratified and approved by the Board. The Financial Ethics Code applies to our senior financial officers, including the Chief Executive Officer, the Chief Financial Officer and the Chief Accounting Officer or persons performing similar functions.
Copies of the Code and the Financial Ethics Code are available on our website at www.transmontaigne.com under the heading "Investor Relations."
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
The following table sets forth certain information regarding compensation earned during each of our last three fiscal years by all individuals serving as TransMontaigne Inc.'s Chief Executive Officer and each of the Company's four other most highly compensated executive officers based on salary and bonus earned in the fiscal year ended June 30, 2005 (collectively, the "Named Executive Officers").
| |
Annual Compensation |
Long Term Compensation Awards |
|
||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Name and Principal Position |
Year |
Salary(1) |
Bonus |
Other Annual Compensation |
Securities Underlying Options(#) |
Restricted Stock Awards |
All Other Compensation(2) |
||||||||||||
| Donald H. Anderson Vice Chairman of the Board, Chief Executive Officer and President |
2005 2004 2003 |
$ |
315,000 315,000 315,000 |
$ |
100,000 75,000 100,000 |
— — — |
— — — |
$ |
302,500 299,000 174,400 |
(3) (4) (5) |
$ |
6,150 6,000 5,500 |
|||||||
| William S. Dickey Executive Vice President and Chief Operating Officer |
2005 2004 2003 |
$ |
250,000 250,000 240,000 |
$ |
100,000 112,500 150,000 |
— — — |
— — — |
$ |
363,000 269,100 218,000 |
(6) (7) (8) |
$ |
6,150 6,000 5,500 |
|||||||
| Randall J. Larson Executive Vice President, Chief Financial Officer and Chief Accounting Officer |
2005 2004 2003 |
$ |
250,000 250,000 250,000 |
$ |
100,000 112,500 30,000 |
$ |
— — 12,352 |
(9) |
— — — |
$ |
363,000 269,100 109,000 |
(10) (11) (12) |
$ |
6,150 2,606 2,538 |
|||||
| Erik B. Carlson Senior Vice President, General Counsel and Secretary |
2005 2004 2003 |
$ |
215,000 215,000 215,000 |
$ |
50,000 60,000 75,000 |
— — — |
— — — |
$ |
151,250 149,500 130,800 |
(13) (14) (15) |
$ |
6,150 4,962 5,500 |
|||||||
| Frederick W. Boutin Senior Vice President and Treasurer |
2005 2004 2003 |
$ |
215,000 215,000 215,000 |
$ |
50,000 60,000 30,000 |
— — — |
— — — |
$ |
151,250 119,600 65,400 |
(16) (17) (18) |
$ |
6,150 6,000 5,500 |
|||||||
- (1)
- Amounts shown set forth all cash compensation earned by each of the Named Executive Officers in the years shown, including salaries deferred under our Savings and Profit Sharing Plan (the "401(k) Plan") pursuant to Section 401(k) of the Internal Revenue Code.
137
- (2)
- Amounts
shown set forth our matching contributions to the 401(k) Plan.
- (3)
- Represents
50,000 shares of restricted stock granted on October 25, 2004,when the market price was $6.05. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date. As of June 30, 2005, Mr. Anderson has a total of 127,000
non-vested restricted shares outstanding, representing a value of $1,333,500, calculated using the fair market value of our common stock at June 30, 2005, $10.50 per share.
- (4)
- Represents
50,000 shares of restricted stock granted on October 25, 2003, when the market price was $5.98. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.
- (5)
- Represents
40,000 shares of restricted stock granted on October 25, 2002, when the market price was $4.36. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.
- (6)
- Represents
60,000 shares of restricted stock granted on October 25, 2004, when the market price was $6.05. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date. As of June 30, 2005, Mr. Dickey has a total of 145,500
non-vested restricted shares outstanding, representing a value of $1,527,750, calculated using the fair market value of our common stock at June 30, 2005, $10.50 per share.
- (7)
- Represents
45,000 shares of restricted stock granted on October 25, 2003, when the market price was $5.98. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.
- (8)
- Represents
50,000 shares of restricted stock granted on October 25, 2002, when the market price was $4.36. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.
- (9)
- The
other 2003 annual compensation for Mr. Larson consists of reimbursement for certain relocation expenses.
- (10)
- Represents
60,000 shares of restricted stock granted on October 25, 2004 when the market price was $6.05. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date. As of June 30, 2005, Mr. Larson has a total of 148,000
non-vested restricted shares outstanding, representing a value of $1,554,000, calculated using the fair market value of our common stock at June 30, 2005, $10.50 per share.
- (11)
- Represents
45,000 shares of restricted stock granted on October 25, 2003 when the market price was $5.98. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date
- (12)
- Represents
25,000 shares of restricted stock granted on October 25, 2002, when the market price was $4.36. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.
- (13)
- Represents
25,000 shares of restricted stock granted on October 25, 2004, when the market price was $6.05. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date. As of June 30, 2005, Mr. Carlson has a total of 72,500
non-vested restricted shares outstanding, representing a value of $761,250, calculated using the fair market value of our common stock at June 30, 2005, $10.50 per share
- (14)
- Represents
25,000 shares of restricted stock granted on October 25, 2003, when the market price was $5.98. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date
- (15)
- Represents 30,000 shares of restricted stock granted on October 25, 2002, when the market price was $4.36. The restricted stock award vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.
138
- (16)
- Represents
25,000 shares of restricted stock granted on October 25, 2004, when the market price was $6.05. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date. As of June 30, 2005, Mr. Boutin has a total of 56,500
non-vested restricted shares outstanding, representing a value of $593,250, calculated using the fair market value of our common stock at June 30, 2005, $10.50 per share.
- (17)
- Represents
20,000 shares of restricted stock granted on October 25, 2003, when the market price was $5.98. The restricted stock award vests 10% after the first year, 20% after
the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date
- (18)
- Represents 15,000 shares of restricted stock granted on October 25, 2002, when the market price was $4.36. The restricted stock award vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.
Option Grants In Last Fiscal Year
No stock options were granted to the Named Executive Officers under our Equity Incentive Plan, as amended (the "1997 Incentive Plan") during the fiscal year ended June 30, 2005.
Aggregated Option Exercises In Last Fiscal Year And Fiscal Year End Option Values
The following table provides information with respect to the options that were exercised during fiscal year ended June 30, 2005 and the value as of June 30, 2005 of unexercised options held by the Named Executive Officers. The value of unexercised options at the fiscal year end is calculated using the difference between the option exercise price and the fair market value of our common stock at June 30, 2005, $10.50 per share.
| |
|
|
Number of Securities Underlying Unexercised Options at Fiscal Year-End(#) |
|
|
|||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
|
|
Value of Unexercised Options At Fiscal Year-End($) |
|||||||||
| |
Shares Acquired on Exercise(#) |
|
||||||||||
| |
Value Realized($) |
|||||||||||
| Name |
Exercisable |
Unexercisable |
Exercisable |
Unexercisable |
||||||||
| Donald H. Anderson | — | — | 130,000 | — | 767,500 | — | ||||||
| William S. Dickey | — | — | 100,000 | — | 500,000 | — | ||||||
| Randall J. Larson | — | — | 45,000 | 30,000 | 245,250 | 163,500 | ||||||
| Erik B. Carlson | — | — | 30,000 | — | 202,500 | — | ||||||
| Frederick W. Boutin | — | — | 30,000 | — | 202,500 | — | ||||||
Employment Contracts And Termination Of Employment And Change In Control Agreements
With the authorization and approval of the board of directors, we have has entered into change in control agreements with certain executive officers and key employees of TransMontaigne Inc. and its subsidiaries, including the named executive officers listed above in the Summary Compensation Table. The agreements are for an initial term of three years, from April 12, 2001 to April 11, 2004 with respect to all named executive officers with the exception of Mr. Larson, whose change in control agreement has an initial term of three years, from May 1, 2002 to April 30, 2005, after which the agreements automatically renew on the anniversary date for consecutive one year periods, unless terminated by either party upon ninety days prior notice; provided, however, that notwithstanding any such notice, the agreement will continue in effect for twenty-four months in the event an actual or threatened change in control (as defined in the agreement) occurs during the initial term or any extension thereof. The agreements provide that if the named executive officer is terminated other than for cause during the term of the agreement, or within two years after a change in control of TransMontaigne Inc., or if the named executive officer terminates his employment for good reason within such time period, the named executive officer is entitled to receive a lump-sum severance
139
payment equal to a multiple of two times the sum of such named executive officer's annual salary and target bonus, as then in effect, together with certain other payments and benefits, including continuation of employee welfare benefits. In addition, should the named executive officer be subject to the excise tax on excess parachute payments as a result of such payment and payments under other plans due to a change in control, an additional payment will be made to restore the after-tax severance payment due the named executive officer to the same amount which the named executive officer would have retained had the excise tax not been imposed.
Compensation Of Directors
Our directors who are also our employees receive no additional compensation for services on the board of directors or committees of the board. Directors who are not employees were paid an annual fee of $30,000 through June 30, 2005, payable quarterly. All directors are reimbursed for reasonable out-of-pocket expenses incurred in attending meetings of the board or any committee or otherwise by reason of their being a director. An additional sum of $30,000 per year was paid to the non-employee director serving as Chairman of the Audit Committee and additional sums of $20,000 per year and $10,000 per year were paid to the non-employee directors serving as Chairman of the Finance Committee and the Compensation Committee, respectively. This compensation of directors and committee chairmen is currently in effect for our fiscal year ending June 30, 2006. In addition, discretionary grants of restricted stock, stock options or other stock-based awards may be made to non-employee directors pursuant to the 1997 Incentive Plan. On May 12, 2003, 20,000 shares of restricted stock were granted to Walter P. Schuetze in his capacity as a member of the board of directors when the market price was $4.50. On May 6, 2004, 10,000 shares of restricted stock were granted to Wayne Murdy, 10,000 shares of restricted stock were granted to Edwin Morgens, and 5,000 shares of restricted were granted to Walter P. Schuetze, in their respective capacity as members of the board of directors when the market price was $5.09. The restricted stock award vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous service on the board since the grant date.
Compensation Committee Interlocks and Insider Participation
During the fiscal year ended June 30, 2005, Edwin H. Morgens and Bryan H. Lawrence served as members of the Compensation Committee. There were no Compensation Committee interlocks between us and any other entity.
140
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table sets forth certain information regarding the beneficial ownership of common stock and common stock equivalents as of August 1, 2005 by each Director and nominee, and by each individual serving as an executive officer as of August 1, 2005 and who is named in the Summary Compensation table set forth under "Executive Compensation" below, by each person known by TransMontaigne Inc. to own more than 5% of the outstanding shares of common stock and by all Directors and those serving as executive officers as of August 1, 2005 as a group. The information set forth below is based solely upon information furnished by such individuals or contained in filings made by such beneficial owners with the SEC.
The calculation of the percentage of beneficial ownership is based on 49,114,860 shares of common stock outstanding as of August 1, 2005. Beneficial ownership is determined in accordance with the rules of the SEC and includes voting and investment power with respect to shares. To our knowledge, except under applicable community property laws or as otherwise indicated, the persons named in the table have sole voting and sole investment power with respect to all shares beneficially owned. Shares of common stock underlying outstanding warrants or options that are currently exercisable or exercisable within 60 days of August 1, 2005 are deemed outstanding for the purpose of computing the percentage of beneficial ownership of the person holding those options or warrants, but are not deemed outstanding for computing the percentage of beneficial ownership of any other person.
| |
Common Stock |
|
|||||
|---|---|---|---|---|---|---|---|
| |
Percent of Voting Power(2) |
||||||
| Beneficial Owner |
Number of Shares |
Percent of Class(1) |
|||||
| Cortlandt S. Dietler(3) | 1,777,267 | 3.62 | % | 3.4 | % | ||
| Donald H. Anderson(4) | 405,956 | * | * | ||||
| Harold R. Logan, Jr.(5) | 328,201 | * | * | ||||
| William S. Dickey(6) | 374,807 | * | * | ||||
| Randall J. Larson(7) | 255,424 | * | * | ||||
| Erik B. Carlson(8) | 189,620 | * | * | ||||
| Frederick W. Boutin(9) | 274,104 | * | * | ||||
| John A. Hill(10) | 143,235 | * | * | ||||
| Bryan H. Lawrence(11) | 3,305,064 | 6.59 | % | 6.3 | % | ||
| Edwin H. Morgens(12) | 255,555 | * | * | ||||
| Wayne W. Murdy(13) | 9,627 | * | * | ||||
| Walter P. Schuetze(14) | 25,000 | * | * | ||||
| Lehman Brothers Holdings Inc.(15) | 2,635,822 | 5.20 | % | 5.0 | % | ||
| Yorktown Energy Partners III, L.P.(16) | 3,227,818 | 6.44 | % | 6.1 | % | ||
| Morgan Stanley Capital Group, Inc.(17) | 5,500,000 | 10.07 | % | 9.4 | % | ||
| All Directors and Executive Officers as a Group (12 Persons)(18) | 7,343,860 | 14.56 | % | 13.2 | % | ||
- *
- Less
than 1% of the shares of common stock deemed outstanding, assuming conversion of all of our preferred stock outstanding as of August 1, 2005 into common stock.
- (1)
- Calculated pursuant to Rule 13d-3(d) of the Securities Exchange Act of 1934, as amended. Under Rule 13d-3(d), shares not outstanding that are subject to options, warrants, rights, or conversion privileges exercisable within sixty days of the date of this table (August 1, 2005) are deemed outstanding for the purpose of calculating the number and percentage owned by such person. The shares of common stock issuable upon conversion of the outstanding shares of Series B Preferred are also deemed outstanding for the purpose of computing the percentage of beneficial ownership of the person holding those shares, but are not deemed outstanding for computing the percentage of beneficial ownership of any other person.
141
- (2)
- The
percentage of voting power column represents the combined voting power of our shares of common stock and Series B Preferred stock outstanding on August 1, 2005. The
holders of our Series B Preferred vote together as a single class with the holders of the common stock, on an as-converted basis, on all matters submitted to a vote other than the
election of directors. As of August 1, 2005, there were 24,197,150 shares of Series B Preferred outstanding convertible into 3,666,235 shares of common stock.
- (3)
- Includes
2,000 shares held by Mr. Dietler's spouse, as to which Mr. Dietler disclaims beneficial ownership; and 11,000 shares of restricted stock subject to vesting.
- (4)
- Includes
130,000 shares issuable upon the exercise of outstanding options and 127,000 shares of restricted stock subject to vesting. Restricted stock vests 10% after the first year,
20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment.
- (5)
- Includes
30,000 shares issuable upon the exercise of outstanding options and 3,000 shares of restricted stock subject to vesting. Restricted stock vests 10% after the first year, 20%
after the second year, 30% after the third year and 40% after the fourth year of continuous employment.
- (6)
- Includes
60,000 shares owned by DQ Investment Group, a family general partnership, of which Mr. Dickey is a general partner. Mr. Dickey disclaims beneficial ownership of
these shares. Also includes 100,000 shares issuable upon exercise of outstanding options and 145,500 shares of restricted stock subject to vesting. Restricted stock vests 10% after the first year, 20%
after the second year, 30% after the third year and 40% after the fourth year of continuous employment.
- (7)
- Includes
45,000 shares issuable upon exercise of outstanding options and 148,000 shares of restricted stock subject to vesting. Restricted stock vests 10% after the first year, 20%
after the second year, 30% after the third year and 40% after the fourth year of continuous employment.
- (8)
- Includes
550 shares held in an IRA for the benefit of Mr. Carlson's spouse, and 3,840 shares and 3,725 shares held in trust for Mr. Carlson's son and daughter,
respectively, as to all of which Mr. Carlson disclaims beneficial ownership. Also includes 30,000 shares issuable upon the exercise of outstanding options and 72,500 shares of restricted stock
subject to vesting. Restricted stock vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment.
- (9)
- Includes
30,000 shares issuable upon the exercise of outstanding options and 56,500 shares of restricted stock subject to vesting. Restricted stock vests 10% after the first year, 20%
after the second year, 30% after the third year and 40% after the fourth year of continuous employment.
- (10)
- Represents
shares held directly by Mr. Hill.
- (11)
- Includes
3,227,818 shares reported as beneficially owned by Yorktown Partners LLC, of which 1,020,549 are issuable upon conversion of the Series B Preferred beneficially owned
by Yorktown Partners LLC. Mr. Lawrence is a founder and an affiliate of Yorktown Partners LLC and disclaims beneficial ownership of these shares.
- (12)
- Includes
206,886 shares held by the Edwin Morgens and Linda Morgens 1993 Trust. Mr. Morgens disclaims beneficial ownership of these shares. Also includes 9,000 shares of
restricted stock subject to vesting. Restricted stock vests 10% after the first year, 20% after the second year, 30% after the third year, and 40% after the fourth year of continuous service as a
director.
- (13)
- Includes
9,000 shares of restricted stock subject to vesting. Restricted stock vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the
fourth year of continuous service as a director.
- (14)
- Includes
18,500 shares of restricted stock subject to vesting. Restricted stock vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the
fourth year of continuous service as a director.
- (15)
- The
number of shares shown as beneficially owned by Lehman Brothers Holdings Inc. and Lehman Brothers Inc. consist of 1,016,515 shares of common stock owned by Lehman
Brothers Inc. and the 1,619,307 shares of common stock issuable upon the conversion of the Series B Preferred owned by LB I Group Inc., a wholly-owned subsidiary of Lehman
Brothers Holdings, Inc. The address of Lehman Brothers Holdings Inc., Lehman Brothers Inc. and LBI Group Inc. is 745 Seventh Avenue, New York, NY 10019. Lehman
Brothers Inc. is a registered broker-dealer and is wholly-owned, and the principal subsidiary of Lehman Brothers Holdings Inc. Lehman Brothers Inc. has informed us that no
individual natural person holds voting and investment power over such shares.
- (16)
- Yorktown Partners LLC, as investment manager to Yorktown Energy Partners III, L.P. as an agent through an irrevocable power of attorney, is deemed to beneficially own an aggregate of 3,227,818 shares of common stock, 1,020,549 of which
142
are shares issuable upon conversion of the Series B Preferred. The address for Yorktown Partners LLC and Yorktown Energy Partners III, L.P. is 410 Park Avenue, New York, NY 10022. The natural person who holds voting and investment power over such shares is, to our knowledge, Peter A. Leidel.
- (17)
- Includes
5,500,000 shares of common stock issuable upon the exercise of outstanding warrants. Morgan Stanley Capital Group Inc. is a wholly-owned subsidiary of Morgan Stanley,
a Delaware Corporation. The address of Morgan Stanley and Morgan Stanley Capital Group Inc. is 1585 Broadway, New York, NY 10036.
- (18)
- Of such 7,343,860 shares, (a) 365,000 represent shares issuable upon the exercise of outstanding options, (b) 600,000 represent shares of restricted stock subject to vesting, (c) 1,020,549 represent shares of our common stock that are issuable upon conversion of Series B Preferred, (d) 3,227,818 shares indicated as being deemed beneficially owned by Yorktown Partners LLC and deemed beneficially owned by Mr. Lawrence, are included only once in the aggregate number of shares held by all directors and executive officers as a group, and (e) directors and executive officers disclaim beneficial ownership with respect to 3,497,747 shares.
Equity Compensation Plan Information
The following table sets forth certain information regarding our common stock that may be issued upon the exercise of options, warrants and rights under all of our equity compensation plans as of June 30, 2005.
| Plan Category |
Number of Securities to be issued upon exercise of outstanding options, warrants and rights(1) (a) |
Weighted-average exercise price of outstanding options, warrants and rights(1) (b) |
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(1) (c) |
||||
|---|---|---|---|---|---|---|---|
| Equity compensation plans approved by security holders(2) | 767,902 | $ | 4.55 | 1,748,916 | |||
| Equity compensation plans not approved by security holders | — | — | — | ||||
| Total | 767,902 | $ | 4.55 | 1,748,916 | |||
- (1)
- This
table includes the stock options outstanding under the 1997 Incentive Plan, our only equity compensation plan as of June 30, 2005. There were no warrants and rights
outstanding at June 30, 2005 under our equity compensation plan.
- (2)
- The stockholders approved the 1997 Incentive Plan in 1997, and approved amendments to the 1997 Incentive Plan in 1999 and in 2002. The 1999 amendment to the 1997 Incentive Plan increased the number of authorized shares from 1,800,000 to 3,500,000 and added an "evergreen" provision to automatically increase the number of shares available for issuance under the 1997 Incentive Plan beginning on June 30, 2000, and on each June 30 thereafter during the term of the 1997 Incentive Plan, a number of shares of our common stock equal to one percent (1%) of the total number of issued and outstanding shares of our common stock on the last day of the immediately preceding fiscal year. The 2002 amendment to the 1997 Incentive Plan provides for the grant of equity-based awards to our non-employee directors from time to time. The 1997 Incentive Plan terminates on August 27, 2007.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Effective December 31, 2002, Mr. Harold R. Logan, Jr. resigned as our Executive Vice President and Chief Financial Officer. Effective January 1, 2003, we entered into a consulting agreement with Mr. Logan pursuant to which Mr. Logan agreed to perform certain financial and banking consulting services for us for a period of two years ("Initial Term"), after which the agreement is automatically renewed for additional terms of one (1) year each ("Renewal Term"), unless earlier terminated by either party upon written notice to the other party at least ninety (90) days prior to the end of the Initial Term or any Renewal Term. The agreement provides annual compensation to Mr. Logan of
143
$100,000 for the first year of services and $75,000 for the second year of services. Thereafter, compensation shall be as mutually agreed between Mr. Logan and us. For the fiscal year ended June 30, 2005, Mr. Logan was paid $13,689.20. Mr. Logan has agreed to continue as a member of our board of directors and to serve as Chairman of the Finance Committee of the Board. Under the 1997 Incentive Plan, Mr. Logan continues to vest in his options awarded while an employee provided he continues as a consultant to us or is a member of the board of directors.
Mr. Logan is also a director of Lion Oil Company, in which we own an 18.04% ownership interest. We purchased $10,317,126 of refined petroleum products from and sold $209,280 of refined petroleum products to Lion Oil Company in the year ended June 30, 2005, all of which product purchases and sales were made at prices negotiated between us and Lion Oil Company or through independent brokers. We believe the prices paid by and to Lion Oil Company were comparable to prices that would have been paid by and to independent third parties.
During the 2005 fiscal year, we paid $263,625 to Arapahoe Development, Inc. ("Arapahoe"), owned by Cortlandt S. Dietler, Chairman of the Board of Directors, for flights aboard an aircraft owned by Arapahoe. Of the total amount, $150,195 was related directly to company business and $113,430 was related to travel in conjunction with the underwriting and initial public offering of units representing limited partnership interests in TransMontaigne Partners. We believe that the prices paid for those flights were competitive with rates charged by other aircraft leasing companies for similar services.
All related party transactions are subject to review and oversight by our Audit Committee.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
DISCLOSURE OF FEES PAID OR ACCRUED FOR KPMG LLP
DURING THE YEARS ENDED JUNE 30:
| |
2005 |
2004 |
2003 |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Audit fees: | ||||||||||
| Audit fees and quarterly reviews(1) | $ | 1,294,792 | $ | 545,130 | $ | 395,000 | ||||
| Comfort letter and consents(2) | 171,200 | 64,025 | 127,594 | |||||||
| 1,465,992 | 609,155 | 522,594 | ||||||||
| Audit-related fees—audit of an employee benefit plan | 14,500 | 13,000 | 12,000 | |||||||
| Tax fees | — | — | — | |||||||
| All other fees | — | — | — | |||||||
| Total fees | $ | 1,480,492 | $ | 622,155 | $ | 534,594 | ||||
- (1)
- For
the year ended June 30, 2005, fees include approximately $315,000 for fees associated with the audit work performed on the Company's internal control over financial
reporting and approximately $340,000 for fees associated with the audit work performed on TransMontaigne Partners L.P.
- (2)
- For the year ended June 30, 2005, fees include approximately $168,000 for fees associated with the TransMontaigne Partners L.P. registration statement on Form S-1, as amended, effective May 24, 2005.
The Audit Committee will annually evaluate the types of audit and non-audit services (permitted by law) which may be entered into with pre-approval authority granted by the Audit Committee, subject to certain limits, and will grant that authority, if appropriate, pursuant to a resolution of the Audit Committee.
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ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
- (a)
- The
following documents are filed as a part of this report.
- (1)
- Consolidated Financial Statements
TransMontaigne Inc.
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of June 30, 2005 and 2004
Consolidated Statements of Operations for the years ended June 30, 2005, 2004 and 2003
Consolidated Statements of Preferred Stock and Common Stockholders' Equity for the years ended June 30, 2005, 2004 and 2003
Consolidated Statements of Cash Flows for the years ended June 30, 2005, 2004 and 2003
Notes to Consolidated Financial Statements
- (2)
- Financial Statement Schedules
Valuation and qualifying accounts.
- (3)
- Exhibits:
A list of exhibits required by Item 601 of Regulation S-K to be filed as part of this report:
| Exhibit Number |
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 Exhibit 2.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed on August 15, 2001). | |
2.2 |
Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc. dated January 13, 2003 (incorporated by reference to Exhibit 99.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed on March 17, 2003). |
|
2.3 |
First Amendment to Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc. dated February 28, 2003 (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Current Report on Form 8-K filed on March 17, 2003). |
|
2.4 |
Second Amendment to Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc., dated as of June 27, 2003 (incorporated by reference to Exhibit 2.3 of TransMontaigne Inc.'s Registration Statement on Form S-4 filed on July 22, 2003). |
|
3.1A |
Restated Articles of Incorporation and Certificate of Merger (incorporated by reference to Exhibit 3.1 of TransMontaigne Oil Company's Form 10-K 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 Exhibit 3.1B of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 1998). |
|
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3.1C |
Certificate of Amendment of Restated Certificate of Incorporation of TransMontaigne Inc. dated December 18, 1998 (incorporated by reference to Exhibit 3.1C of TransMontaigne Inc.'s Form 10-Q for the quarter ended December 31, 1998). |
|
3.1D |
Certificate of Designations of Series B Redeemable Convertible Preferred Stock (incorporated by reference to Exhibit 99.4 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002). |
|
3.2 |
Amended and Restated Bylaws of TransMontaigne Inc. (incorporated by reference to Exhibit 3.2 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002). |
|
4.1 |
Indenture dated as of May 30, 2003 among TransMontaigne Inc., the Guarantors party thereto and Wells Fargo Bank Minnesota, National Association, as trustee, with respect to the 91/8% Series B Senior Subordinated Notes due 2010 (incorporated by reference to Exhibit 4.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed June 3, 2003). |
|
4.2 |
Form of 91/8% Series B Senior Subordinated Notes due 2010 (included in Exhibit 4.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed June 3, 2003). |
|
4.3 |
Warrants to Purchase Common Stock of TransMontaigne Inc., dated as of November 23, 2004, by TransMontaigne Inc. in favor of Morgan Stanley Capital Group Inc. (incorporated by reference to Exhibit 4.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed on November 30, 2004). |
|
4.4 |
Registration Rights Agreement, dated as of November 23, 2004, by and between TransMontaigne Inc. and Morgan Stanley Capital Group Inc. (incorporated by reference to Exhibit 4.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed on November 30, 2004). |
|
10.1* |
TransMontaigne Oil Company Equity Incentive Plan (incorporated by reference to Exhibit 10.2 TransMontaigne Oil Company's Definitive Proxy Statement filed in connection with the August 28, 1997 Annual Meeting of Shareholders). |
|
10.1A* |
Amendment to TransMontaigne Inc. Equity Incentive Plan, effective March 17, 1999 (incorporated by reference to Exhibit A of TransMontaigne Inc.'s Definitive Proxy Statement on Schedule 14A filed on October 26, 1999). |
|
10.1B* |
Amendment to TransMontaigne Inc. Equity Incentive Plan, effective March 17, 1999 (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Registration Statement on Form S-8 filed on October 17, 2001). |
|
10.1C* |
Amendment to TransMontaigne Inc. Equity Incentive Plan, effective November 21, 2002 (incorporated by reference to Exhibit A of TransMontaigne Inc.'s Definitive Proxy Statement on Schedule 14A filed on October 16, 2002). |
|
10.2 |
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 Exhibit 99.6 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002). |
|
10.3 |
Amended and Restated Louis Dreyfus Corporation Registration Rights Agreement dated June 27, 2002 between TransMontaigne Inc. and Louis Dreyfus Corporation (incorporated by reference to Exhibit 99.7 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002). |
|
10.4 |
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 Exhibit 99.5 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002). |
146
10.5 |
Form of Preferred Stock Recapitalization Agreement dated as of June 27, 2002 (without exhibits) (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002). |
|
10.6 |
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 Exhibit 99.8 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002). |
|
10.7* |
Change in Control Agreement between TransMontaigne Inc. and Donald H. Anderson dated April 12, 2001 (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002). |
|
10.8* |
Change in Control Agreement between TransMontaigne Inc. and Erik B. Carlson dated April 12, 2001 (incorporated by reference to Exhibit 10.2 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002). |
|
10.9* |
Change in Control Agreement between TransMontaigne Inc. and William S. Dickey dated April 12, 2001 (incorporated by reference to Exhibit 10.4 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002). |
|
10.10* |
Change in Control Agreement between TransMontaigne Inc. and Randall J. Larson dated May 1, 2002 (incorporated by reference to Exhibit 10.6 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002). |
|
10.11 |
Consulting Agreement by and between Harold R. Logan, Jr. and TransMontaigne Inc. effective as of January 1, 2003 (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Form 10-Q for the quarter ended March 31, 2003). |
|
10.12 |
Amended and Restated Senior Working Capital Credit Facility, dated May 27, 2005, with the lenders party thereto, JPMorgan Chase Bank, N.A. and UBS AG, Stamford Branch, as syndication agents, Société Générale, New York Branch and Wells Fargo Foothill, LLC, as the documentation agents, and Wachovia Bank, National Association, as agent (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed on June 3, 2005). |
|
10.13 |
Omnibus Agreement, dated May 27, 2005 among TransMontaigne Inc., TransMontaigne Partners L.P., TransMontaigne GP L.L.C., TransMontaigne Operating GP L.L.C. and TransMontaigne Operating Company L.P. (incorporated by reference to Exhibit 10.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed on June 3, 2005). |
|
10.14 |
Terminaling and Transportation Services Agreement, dated May 27, 2005 among TransMontaigne Partners L.P., TransMontaigne Product Services Inc. and Coastal Fuels Marketing, Inc. (incorporated by reference to Exhibit 10.3 of TransMontaigne Inc.'s Current Report on Form 8-K filed on June 3, 2005). |
|
10.15 |
Product Supply Agreement, dated as of November 4, 2004, between TransMontaigne Product Services Inc. and Morgan Stanley Capital Group Inc. (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed on January 7, 2005). [Portions of this exhibit have been omitted pursuant to a request for confidential treatment filed with the Securities and Exchange Commission.] |
|
10.16 |
First Amendment to Product Supply Agreement, dated as of November 23, 2004, between TransMontaigne Product Services Inc. and Morgan Stanley Capital Group Inc. (incorporated by reference to Exhibit 10.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed on January 7, 2005). [Portions of this exhibit have been omitted pursuant to a request for confidential treatment filed with the Securities and Exchange Commission.] |
|
12.1 |
Statement of Computation of Ratios of Earnings to Fixed Charges. FILED HEREWITH. |
147
21.1 |
List of Subsidiaries. FILED HEREWITH. |
|
23.1 |
Audit Report on Schedule and Consent of Registered Public Accounting Firm. FILED HEREWITH. |
|
31.1 |
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH. |
|
31.2 |
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH. |
|
32.1 |
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH. |
|
32.2 |
Certification of 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. |
|
99.1 |
Financial Statement Schedule. FILED HEREWITH. |
- *
- Identifies each management compensation plan or arrangement
148
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 13, 2005
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 13, 2005.
| 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/ RANDALL J. LARSON Randall J. Larson |
Executive Vice President, Chief Financial Officer and Chief Accounting Officer |
|||
/s/ JOHN A. HILL John A. Hill |
Director |
|||
/s/ BRYAN H. LAWRENCE Bryan H. Lawrence |
Director |
|||
/s/ HAROLD R. LOGAN, JR. Harold R. Logan, Jr. |
Director |
|||
/s/ EDWIN H. MORGENS Edwin H. Morgens |
Director |
149
/s/ WAYNE W. MURDY Wayne W. Murdy |
Director |
|||
/s/ WALTER P. SCHUETZE Walter P. Schuetze |
Director |
150
| Exhibit Number |
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 Exhibit 2.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed on August 15, 2001). |
|
2.2 |
Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc. dated January 13, 2003 (incorporated by reference to Exhibit 99.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed on March 17, 2003). |
|
2.3 |
First Amendment to Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc. dated February 28, 2003 (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Current Report on Form 8-K filed on March 17, 2003). |
|
2.4 |
Second Amendment to Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc., dated as of June 27, 2003 (incorporated by reference to Exhibit 2.3 of TransMontaigne Inc.'s Registration Statement on Form S-4 filed on July 22, 2003). |
|
3.1A |
Restated Articles of Incorporation and Certificate of Merger (incorporated by reference to Exhibit 3.1 of TransMontaigne Oil Company's Form 10-K 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 Exhibit 3.1B of TransMontaigne Inc.'s Form 10-Q 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 Exhibit 3.1C of TransMontaigne Inc.'s Form 10-Q for the quarter ended December 31, 1998). |
|
3.1D |
Certificate of Designations of Series B Redeemable Convertible Preferred Stock (incorporated by reference to Exhibit 99.4 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002). |
|
3.2 |
Amended and Restated Bylaws of TransMontaigne Inc. (incorporated by reference to Exhibit 3.2 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002). |
|
4.1 |
Indenture dated as of May 30, 2003 among TransMontaigne Inc., the Guarantors party thereto and Wells Fargo Bank Minnesota, National Association, as trustee, with respect to the 91/8% Series B Senior Subordinated Notes due 2010 (incorporated by reference to Exhibit 4.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed June 3, 2003). |
|
4.2 |
Form of 91/8% Series B Senior Subordinated Notes due 2010 (included in Exhibit 4.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed June 3, 2003). |
|
4.3 |
Warrants to Purchase Common Stock of TransMontaigne Inc., dated as of November 23, 2004, by TransMontaigne Inc. in favor of Morgan Stanley Capital Group Inc. (incorporated by reference to Exhibit 4.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed on November 30, 2004). |
|
4.4 |
Registration Rights Agreement, dated as of November 23, 2004, by and between TransMontaigne Inc. and Morgan Stanley Capital Group Inc. (incorporated by reference to Exhibit 4.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed on November 30, 2004). |
10.1* |
TransMontaigne Oil Company Equity Incentive Plan (incorporated by reference to Exhibit 10.2 TransMontaigne Oil Company's Definitive Proxy Statement filed in connection with the August 28, 1997 Annual Meeting of Shareholders). |
|
10.1A* |
Amendment to TransMontaigne Inc. Equity Incentive Plan, effective March 17, 1999 (incorporated by reference to Exhibit A of TransMontaigne Inc.'s Definitive Proxy Statement on Schedule 14A filed on October 26, 1999). |
|
10.1B* |
Amendment to TransMontaigne Inc. Equity Incentive Plan, effective March 17, 1999 (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Registration Statement on Form S-8 filed on October 17, 2001). |
|
10.1C* |
Amendment to TransMontaigne Inc. Equity Incentive Plan, effective November 21, 2002 (incorporated by reference to Exhibit A of TransMontaigne Inc.'s Definitive Proxy Statement on Schedule 14A filed on October 16, 2002). |
|
10.2 |
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 Exhibit 99.6 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002). |
|
10.3 |
Amended and Restated Louis Dreyfus Corporation Registration Rights Agreement dated June 27, 2002 between TransMontaigne Inc. and Louis Dreyfus Corporation (incorporated by reference to Exhibit 99.7 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002). |
|
10.4 |
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 Exhibit 99.5 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002). |
|
10.5 |
Form of Preferred Stock Recapitalization Agreement dated as of June 27, 2002 (without exhibits) (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002). |
|
10.6 |
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 Exhibit 99.8 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002). |
|
10.7* |
Change in Control Agreement between TransMontaigne Inc. and Donald H. Anderson dated April 12, 2001 (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002). |
|
10.8* |
Change in Control Agreement between TransMontaigne Inc. and Erik B. Carlson dated April 12, 2001 (incorporated by reference to Exhibit 10.2 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002). |
|
10.9* |
Change in Control Agreement between TransMontaigne Inc. and William S. Dickey dated April 12, 2001 (incorporated by reference to Exhibit 10.4 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002). |
|
10.10* |
Change in Control Agreement between TransMontaigne Inc. and Randall J. Larson dated May 1, 2002 (incorporated by reference to Exhibit 10.6 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002). |
|
10.11 |
Consulting Agreement by and between Harold R. Logan, Jr. and TransMontaigne Inc. effective as of January 1, 2003 (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Form 10-Q for the quarter ended March 31, 2003). |
10.12 |
Amended and Restated Senior Working Capital Credit Facility, dated May 27, 2005, with the lenders party thereto, JPMorgan Chase Bank, N.A. and UBS AG, Stamford Branch, as syndication agents, Société Générale, New York Branch and Wells Fargo Foothill, LLC, as the documentation agents, and Wachovia Bank, National Association, as agent (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed on June 3, 2005). |
|
10.13 |
Omnibus Agreement, dated May 27, 2005 among TransMontaigne Inc., TransMontaigne Partners L.P., TransMontaigne GP L.L.C., TransMontaigne Operating GP L.L.C. and TransMontaigne Operating Company L.P. (incorporated by reference to Exhibit 10.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed on June 3, 2005). |
|
10.14 |
Terminaling and Transportation Services Agreement, dated May 27, 2005 among TransMontaigne Partners L.P., TransMontaigne Product Services Inc. and Coastal Fuels Marketing, Inc. (incorporated by reference to Exhibit 10.3 of TransMontaigne Inc.'s Current Report on Form 8-K filed on June 3, 2005). |
|
10.15 |
Product Supply Agreement, dated as of November 4, 2004, between TransMontaigne Product Services Inc. and Morgan Stanley Capital Group Inc. (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed on January 7, 2005). [Portions of this exhibit have been omitted pursuant to a request for confidential treatment filed with the Securities and Exchange Commission.] |
|
10.16 |
First Amendment to Product Supply Agreement, dated as of November 23, 2004, between TransMontaigne Product Services Inc. and Morgan Stanley Capital Group Inc. (incorporated by reference to Exhibit 10.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed on January 7, 2005). [Portions of this exhibit have been omitted pursuant to a request for confidential treatment filed with the Securities and Exchange Commission.] |
|
12.1 |
Statement of Computation of Ratios of Earnings to Fixed Charges. FILED HEREWITH. |
|
21.1 |
List of Subsidiaries. FILED HEREWITH. |
|
23.1 |
Audit Report on Schedule and Consent of Registered Public Accounting Firm. FILED HEREWITH. |
|
31.1 |
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH. |
|
31.2 |
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH. |
|
32.1 |
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH. |
|
32.2 |
Certification of 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. |
|
99.1 |
Financial Statement Schedule. FILED HEREWITH. |
- *
- Identifies each management compensation plan or arrangement