e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
Mark One
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Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2006
OR
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Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 |
For the transition period from ___to ___.
Commission file number 000-50056
MARTIN MIDSTREAM PARTNERS L.P.
(Exact name of registrant as specified in its charter)
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Delaware
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05-0527861 |
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State or other jurisdiction of
incorporation or organization
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(I.R.S. Employer Identification No.) |
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4200 Stone Road Kilgore, Texas
(Address of principal executive offices)
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75662
(Zip Code) |
903-983-6200
(Registrants telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
NONE
Securities Registered Pursuant to Section 12(g) of the Act:
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Title of each class
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Name of each exchange on which registered |
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Common Units representing
limited partnership interests
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NASDAQ |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.
Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements the past 90 days.
Yes þ No o
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 registrants
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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated
filer in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o Accelerated filer þ Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act).
Yes o No þ
As of June 30, 2006, 9,282,652 common units were outstanding. The aggregate market value of
the common units held by non-affiliates of the registrant as of such date approximated
$245,347,657. There were 10,603,808 of the registrants common units and 2,552,018 of the
registrants subordinated units outstanding as of March 5, 2007.
DOCUMENTS INCORPORATED BY REFERENCE: None.
PART I
Item 1.
Business
Overview
We are a publicly traded limited partnership with a diverse set of operations focused
primarily in the United States Gulf Coast region. Our five primary business lines include:
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Terminalling and storage services for petroleum products and by-products |
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Natural gas services |
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Marine transportation services for petroleum products and by-products |
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Sulfur gathering, processing and distribution |
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Fertilizer manufacturing and distribution |
The petroleum products and by-products we collect, transport, store and market are produced
primarily by major and independent oil and gas companies who often turn to third parties, such as
us, for the transportation and disposition of these products. In addition to these major and
independent oil and gas companies, our primary customers include independent refiners, large
chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. We
operate primarily in the Gulf Coast region of the United States. This region is a major hub for
petroleum refining, natural gas gathering and processing and support services for the exploration
and production industry.
We were formed in 2002 by Martin Resource Management Corporation (Martin Resource
Management), a privately-held company whose initial predecessor was incorporated in 1951 as a
supplier of products and services to drilling rig contractors. Since then, Martin Resource
Management has expanded its operations through acquisitions and internal expansion initiatives as
its management identified and capitalized on the needs of producers and purchasers of hydrocarbon
products and by-products and other bulk liquids. Martin Resource Management owns an approximate
38.6% limited partnership interest in us. Furthermore, it owns and controls our general partner,
which owns a 2.0% general partner interest and incentive distribution rights in us.
Martin Resource Management operated our business segments for several years. Martin Resource
Management began operating our natural gas services business in the 1950s and our sulfur business
in the 1960s. It began our marine transportation business in the late 1980s. It entered into our
fertilizer and terminalling and storage businesses in the early 1990s. In recent years, Martin
Resource Management has increased the size of our asset base through expansions and strategic
acquisitions.
Primary Business Segments
Our primary business segments can be generally described as follows:
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Terminalling and Storage. We own or operate 17 marine terminal facilities
and four inland terminal facilities located in the United States Gulf Coast region that
provide storage and handling services for producers and suppliers of petroleum products
and by-products, lubricants and other liquids. We also provide land rental to oil and
gas companies along with storage and handling services for lubricants and fuel oil. |
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Natural Gas Services. Through our acquisition of Prism Gas Systems I, L.P.
(Prism Gas), we have ownership interests in over 440 miles of natural gas gathering
pipelines located in the natural gas producing regions of Central and East Texas,
Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal waters in the
Gulf of Mexico as well as a 150 MMcfd capacity natural gas processing plant located in
East Texas which is currently being expanded to 250 MMcfd. In addition to our newly
acquired natural gas gathering and processing business, we distribute natural gas
liquids or, NGLs. We purchase NGLs primarily from natural gas processors. We store
NGLs in our supply |
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and storage facilities for resale to propane retailers, refineries and industrial NGL
users in Texas and the Southeastern United States. We own three NGL supply and storage
facilities with an aggregate above ground storage capacity of approximately 132,000
gallons and we lease approximately 72 million gallons of underground storage capacity
for NGLs. |
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Marine Transportation. We own a fleet of 37 inland marine tank barges, 16
inland push boats and four offshore tug barge units that transport petroleum products
and by-products primarily in the United States Gulf Coast region. We provide these
transportation services on a fee basis primarily under annual contracts. In addition,
our marine segment manages our sulfur segments marine assets. |
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Sulfur. We gather, process and distribute sulfur predominately produced by
oil refineries primarily located in the United States Gulf Coast region. We process
molten sulfur into prilled, or pelletized, sulfur under both fee-based volume contracts
and buy/sell contracts at our facility in Port of Stockton, California. In December
2005, we completed the construction of an additional sulfur priller at our Neches
terminal in Beaumont, Texas. In July 2005, we acquired the remaining interests in CF
Martin Sulphur L.P. (CF Martin Sulphur) not previously owned by us. CF Martin
Sulphur gathered, transported and stored molten sulfur supplied by oil refineries. |
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Fertilizer. We own and operate six fertilizer production plants and one
emulsified sulfur blending plant that manufacture primarily sulfur-based fertilizer
products for wholesale distributors and industrial users. These plants are located in
Illinois, Texas and Utah. |
2006 Developments and Subsequent Events
Recent Acquisitions
Acquisition of the La Force Marine Vessel. In November 2006, we acquired the La Force, an
offshore tug, for $6.0 million from a third party. This vessel is a 5,100 horse power offshore tug
that was rebuilt in 1999 with new engines installed in 2005. The addition of the La Force to our
fleet will eliminate the need for chartered offshore horsepower.
Acquisition of Asphalt Terminals. In August 2006 and October 2006, respectively, we acquired
the assets of Gulf States Asphalt Company LP and Prime Materials and Supply Corporation (Prime),
for $4.9 million. These assets are located in Houston, Texas and Port Neches, Texas. In
connection with these acquisitions, we entered into an agreement with Martin Resource Management,
whereby Martin Resource Management will operate the acquired facilities through a terminalling
service agreement based upon throughput rates and will assume all additional expenses to operate
the facilities.
Acquisition of the Corpus Christi Barge Terminal. In July 2006, we acquired a marine terminal
located near Corpus Christi, Texas and associated assets from Koch Pipeline Company, L.P. for $6.2
million, which was all allocated to property, plant and equipment. The terminal is located on
approximately 25 acres of land and includes three tanks with a combined capacity of approximately
240,000 barrels, pump and piping infrastructure for truck unloading and product delivery to two oil
docks.
Acquisition of the Texan, Ponciana and M450. In January 2006, we acquired the Texan, an
offshore tug, and the Ponciana, an offshore NGL barge, for $5.9 million from Martin Resource
Management. In February 2006, we acquired the M450, an offshore barge, for $1.6 million from a
third party.
Other Developments
Increased Quarterly Distribution. We declared a quarterly cash distribution for the fourth
quarter of 2006 of $0.62 per common and subordinated unit on January 22, 2007, reflecting an
increase of $0.01 per unit over the quarterly distribution paid in respect of the third quarter of
2006.
Issuance of Common Units. In December 2006, we issued 470,484 common units to Martin Product
Sales LLC, an affiliate of Martin Resource Management, for approximately $15.3 million, including a
capital contribution of approximately $0.3 million made by our general partner in order to maintain
its 2% general partner interest in us. These funds were used to pay down our revolving line of
credit.
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Conversion of Subordinated Units. On November 14, 2006, 850,672 of our 3,402,690 outstanding
subordinated units owned by Martin Resource Management and its subsidiaries converted into common
units on a one-for-one basis following our quarterly cash distribution on such date. Additional
conversions of our outstanding subordinated units may occur in the future provided that certain
distribution thresholds contained in our partnership agreement are met by us.
Public Offering. In January 2006, we completed a follow-on public offering of 3,450,000
common units, resulting in proceeds of $95.4 million, after payment of underwriters discounts,
commissions and offering expenses. Our general partner contributed $2.1 million in cash to us in
conjunction with the offering in order to maintain its 2% general partner interest in us. Of the
net proceeds, $62.0 million was used to pay then current balances under our revolving credit
facility and $7.5 million was used to fund a portion of the redemption price for our U.S.
Government Guaranteed Ship Financing Bonds. The remainder of the net proceeds has been or will be
used to fund future organic growth projects.
Business Strategy
The key components of our business strategy are to:
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Pursue Strategic Acquisitions. We monitor the marketplace to identify and
pursue accretive acquisitions that expand the services and products we offer or that
expand our geographic presence. After acquiring other businesses, we will attempt to
utilize our industry knowledge, network of customers and suppliers and strategic asset
base to operate the acquired businesses more efficiently and competitively, thereby
increasing revenues and cash flow. We believe that our diversified base of operations
provides multiple platforms for strategic growth through acquisitions. |
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Pursue Organic Growth Projects. We continually evaluate economically
attractive organic expansion opportunities in new or existing areas of operation that
will allow us to leverage our existing market position, increase the distributable cash
flow from our existing assets through improved utilization and efficiency, and leverage
our existing customer base. |
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Pursue Internal Organic Growth by Attracting New Customers and Expanding
Services Provided to Existing Customers. We seek to identify and pursue opportunities
to expand our customer base across all of our business segments. We generally begin a
relationship with a customer by transporting or marketing a limited range of products
and services. We believe expanding our customer base and our service and product
offerings to existing customers is the most efficient and cost effective method of
achieving organic growth in revenues and cash flow. We believe significant
opportunities exist to expand our customer base and provide additional services and
products to existing customers. |
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Expand Geographically. We work to identify and assess other attractive
geographic markets for our services and products based on the market dynamics and the
cost associated with penetration of such markets. We typically enter a new market
through an acquisition or by securing at least one major customer or supplier and then
dedicating or purchasing assets for operation in the new market. Once in a new
territory, we seek to expand our operations within this new territory both by targeting
new customers and by selling additional services and products to our original customers
in the territory. |
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Pursue Strategic Alliances. Many of our larger customers are establishing
strategic alliances with midstream service providers such as us to address logistical
and transportation problems or achieve operational synergies. These strategic alliances
are typically structured differently than our regular commercial relationships, with
the goal that such alliances would expand our business relationships with our customers
and suppliers. We intend to pursue strategic alliances with customers in the future. |
Competitive Strengths
We believe we are well positioned to execute our business strategy because of the following
competitive strengths:
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Asset Base and Integrated Distribution Network. We operate a diversified
asset base that, together with the services provided by Martin Resource Management,
enables us to offer our customers an |
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integrated distribution network consisting of transportation, terminalling and midstream
logistical services while minimizing our dependence on the availability and pricing of
services provided by third parties. Our integrated distribution network enables us to
provide customers a complementary portfolio of transportation, terminalling,
distributions and other midstream services for petroleum products and by-products. |
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Strategically Located Assets. We believe we are one of the largest
providers of shore bases and one of the largest lubricant distributors and marketers in
the United States Gulf Coast region. In addition, we are one of the largest operators
of marine service terminals in the United States Gulf Coast region providing broad
geographic coverage and distribution capability of our products and services to our
customers. Our natural gas gathering and processing assets are focused in areas that
have continued to experience high levels of drilling activity and natural gas
production. |
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Specialized Transportation Equipment and Storage Facilities. We have the
assets and expertise to handle and transport certain petroleum products and by-products
with unique requirements for transportation and storage, such as molten sulfur and
asphalt. For example, we own facilities and resources to transport molten sulfur and
asphalt, which must be maintained at temperatures between approximately 275 and 350
degrees Fahrenheit to remain in liquid form. We believe these capabilities help us
enhance relationships with our customers by offering them services to handle their
unique product requirements. |
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Ability to Grow Our Natural Gas Gathering and Processing Services. We
believe that, with our Prism Gas assets, we have opportunities for organic growth in
our natural gas gathering and processing operations through increasing fractionation
capacity, pipeline expansions, new pipeline construction and bolt-on acquisitions. |
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Experienced Management Team and Operational Expertise. Members of our
executive management team and the heads of our principal business lines have, on
average, more than 26 years of experience in the industries in which we operate.
Further, these individuals have been employed by Martin Resource Management, on
average, for more than 23 years. Our management team has a successful track record of
creating internal growth and completing acquisitions. We believe our management teams
experience and familiarity with our industry and businesses are important assets that
assist us in implementing our business strategies. |
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Strong Industry Reputation and Established Relationships with Suppliers and
Customers. We believe we have established a reputation in our industry as a reliable
and cost-effective supplier of services to our customers and have a track record of
safe, efficient operation of our facilities. Our management has also established
long-term relationships with many of our suppliers and customers. We believe we benefit
from our managements reputation and track record, and from these long-term
relationships. |
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Financial Flexibility. We believe the borrowings available under our credit
facility and our ability to issue additional partnership units provide us with the
financial flexibility necessary to enable us to pursue expansion and acquisition
opportunities. |
Terminalling and Storage Segment
Industry Overview. The United States petroleum distribution system moves petroleum products
and by-products from oil refinery and natural gas processing facilities to end users. This
distribution system is comprised of a network of terminals, storage facilities, pipelines, tankers,
barges, rail cars and trucks. Terminals play a key role in moving these products throughout the
distribution system by providing storage, blending and other ancillary services.
In the 1990s, the petroleum industry entered a period of consolidation. Refiners and
marketers developed large-scale, cost-efficient operations resulting in several refinery
acquisitions, combinations, alliances and joint ventures. This consolidation resulted in major oil
companies integrating the various components of their businesses, including terminalling and
storage. However, major integrated oil companies later concentrated their focus and resources on
their core competencies of exploration, production, refining and retail marketing and examined ways
to lower their distribution costs. Additionally, the Federal Trade Commission required some
divestitures of terminal assets in markets in which merged companies, alliances and joint ventures
were regarded as having excessive market power.
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As a result of these factors, oil and gas companies began to increasingly rely on third
parties such as us to perform many terminalling and storage services.
Although many large energy and chemical companies own terminalling and storage facilities,
these companies also use third party terminalling and storage services. Major energy and chemical
companies typically have a strong demand for terminals owned by independent operators when such
terminals are strategically located at or near key transportation links, such as deep-water ports.
Major energy and chemical companies also need independent terminal storage when their owned storage
facilities are inadequate, either because of lack of capacity, the nature of the stored material or
specialized handling requirements.
The Gulf Coast region is a major hub for petroleum refining. Approximately two-thirds of
United States refining capacity expansion in the 1990s occurred in this region. Growth in the
refining and natural gas processing industries has increased the volume of petroleum products and
by-products that are transported within the Gulf Coast region, which consequently has increased the
need for terminalling and storage services.
The marine and offshore oil and gas exploration and production industries use terminal
facilities in the Gulf Coast region as shore bases that provide them logistical support services as
well as provide a broad range of products, including fuel oil, lubricants, chemicals and supplies.
The demand for these types of terminals, services and products is driven primarily by offshore
exploration, development and production in the Gulf of Mexico. Offshore activity is greatly
influenced by current and projected prices of oil and natural gas.
Marine Terminals. We own or operate 17 marine terminals along the Gulf Coast from Tampa,
Florida to Corpus Christi, Texas. Our terminal assets are located at strategic distribution points
for the products we handle and are in close proximity to our customers. Further, the location and
composition of our terminals are structured to complement our other businesses and reflect our
strategy to provide a broad range of integrated services in the handling and transportation of
petroleum products and by-products. We developed our terminalling and storage assets by acquiring
existing terminalling and storage facilities and then customizing and upgrading these facilities as
needed to integrate the facilities into our petroleum product and by-product transportation network
and to more effectively service customers. We expect to continue to acquire facilities, streamline
their operations and customize and upgrade them as part of our growth strategy. We also continually
evaluate opportunities to add services and increase access to our terminals to attract more
customers and create additional revenues.
We are one of the largest operators of marine service terminals in the Gulf Coast region.
These terminals are used to distribute and market lubricants and the full service terminals also
provide shore bases for companies that are operating in the offshore exploration and production
industry. Customers are primarily oil and gas exploration and production companies and oilfield
service companies such as drilling fluid companies, marine transportation companies, and offshore
construction companies. Shore bases typically provide logistical support including the storing and
handling of tubular goods, loading and unloading bulk materials, providing facilities from which
major and independent oil companies can communicate with and control offshore operations and
leasing dockside facilities to companies which provide complementary products and services such as
drilling fluids and cementing services. We generate revenues from our terminals that have shore
bases by fees that we charge our customers under land rental contracts for the use of our terminal
facility for these shore bases. These contracts generally provide us a fixed land rental fee and
additional rental fees that are determined based on a percentage of the sales value of the products
and services delivered from the shore base. We also generate revenues through the distribution and
marketing of lubricants. Lubricants are used in the operation of offshore drilling rigs, offshore
production and transmission platforms, and various ships and equipment engaged in marine
transportation. In addition, Martin Resource Management, through contractual arrangements, pays us
for terminalling and storage of fuel oil at these terminal facilities.
Our 17 marine terminals are divided generally into three classes of terminals: (i) full
service terminals, (ii) fuel and lubricant terminals and (iii) specialty petroleum terminals.
Full Service Terminals. We own or operate eight full service terminals. These terminal
facilities provide logistical support services, distribute and market lubricants and provide
storage and handling services for fuel oil. The significant difference between our full service
terminals and our fuel and lubricant terminals is that our full service terminals generate
additional revenues by providing shore bases to support our customers operating activities related
to the offshore exploration and production industry. One typical use for our shore bases is for
drilling fluids manufacturers to manufacture and sell drilling fluids to the offshore drilling
industry. Offshore drilling companies may also set up service facilities at these terminals to
support their offshore operations. Customers are primarily oil and gas
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exploration and production companies, and oilfield service companies such as drilling fluids
companies, marine transportation companies, and offshore construction companies.
The following is a summary description of our eight full service terminals:
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Terminal |
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Location |
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Acres |
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Tanks |
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Aggregate Capacity |
Pelican Island
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Galveston, Texas
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51.3 |
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14 |
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57,200 Bbls. |
Harbor Island(1)
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Harbor Island, Texas
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25.5 |
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10 |
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37,400 Bbls. |
Freeport
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Freeport, Texas
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17.8 |
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1 |
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8,300 Bbls. |
Port OConnor(2)
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Port OConnor, Texas
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22.8 |
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8 |
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7,000 Bbls. |
Sabine Pass(3)
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Sabine Pass, Texas
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23.1 |
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11 |
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18,100 Bbls. |
Cameron East(4)
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Cameron, Louisiana
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34.3 |
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7 |
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33,000 Bbls. |
Cameron West(5)
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Cameron, Louisiana
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16.9 |
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5 |
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19,000 Bbls. |
Venice (6)
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Venice, Louisiana
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2.8 |
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2 |
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15,000 Bbls. |
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A portion of this terminal is located on land owned by a third party and leased under a lease
that expires in January 2010 and can be extended by us through January 2015. |
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This terminal is located on land owned by a third party and leased under a lease that expires
in March 2009 and can be extended by us through March 2014. |
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A portion of this terminal is located on land owned by a third party and leased under a lease
that expires in September 2016 and can be renewed by us through September 2036. |
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This terminal is located on land owned by third parties and leased under a lease that expires
in March 2012 and can be extended by us through March 2022. |
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This terminal is located on land owned by a third party and leased under a lease that expires
in February 2008 and can be extended by us through February 2013. |
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This terminal is located on land owned by a third party and leased under a sublease
agreement that expires in August 2009 and can be extended by us through August 2024. |
Fuel and Lubricant Terminals. We own or operate four lubricant and fuel oil terminals located
in the Gulf Coast region that provide storage and handling service for lubricants and fuel oil. We
also distribute and market lubricants at these terminals.
The following is a summary description of our fuel and lubricant terminals:
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Terminal |
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Location |
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Tanks |
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Aggregate Capacity |
Amelia
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Amelia, Louisiana
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17 |
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14,900 Bbls. |
Berwick(1)
Intracoastal
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Berwick, Louisiana
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4 |
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24,900 Bbls. |
City(2)(3)
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Intracoastal City, Louisiana
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17 |
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34,300 Bbls. |
Fourchon(4)
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Fourchon, Louisiana
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7 |
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30,100 Bbls. |
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This terminal is located on land owned by third parties and leased under a lease that expires
in September 2007 and can be extended by us through September 2017. |
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A portion of this terminal is located on land owned by a third party at which we throughput
fuel oil pursuant to an agreement that expires in November 2007. |
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A portion of this terminal is located on land owned by third parties and leased under a lease
that expires in April 2009 and can be extended by us through April 2014. |
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This terminal is located on land owned by a third party at which we throughput lubricants and
fuel oil pursuant to an agreement that expires in January 2017. |
Specialty Petroleum Terminals. We own or operate five terminal facilities providing storage
and handling services for some or all of the following: anhydrous ammonia, asphalt, sulfur,
sulfuric acid, fuel oil, crude oil and other petroleum products and by-products. Our specialty
terminals have an aggregate storage capacity of approximately 1.75 million barrels. Each of these
terminals has storage capacity for petroleum products and by-products and has assets to handle
products transported by vessel, barge and truck. Our Tampa terminal is located on approximately 10
acres of land owned by the Tampa Port Authority that was leased to us under a 10-year lease that
expired on December 15, 2006. We are currently leasing this facility on a month-to-month basis and
have received a proposal for a new lease agreement that extends the term of the lease for 10 years
with two five year options. Our Stanolind terminal is located on approximately 11 acres of land
owned by Martin Resource Management and us and located on the Neches River in
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Beaumont. Our Neches terminal is a deep water marine terminal located near Beaumont, Texas on
approximately 50 acres of land owned by us. Our Ouachita County terminal is located on
approximately six acres of land owned by us on the Ouachita River in southern Arkansas. Our Corpus
Christi terminal is located on approximately 25 acres of land owned by us and has access to the
waterfront via marine docks owned by the Port of Corpus Christi.
At our Tampa, Neches, Stanolind and Corpus Christi terminals, our customers are primarily
large oil refining and natural gas processing companies. We charge a fixed monthly fee for the use
of our facilities, based on the capacity of the applicable tank. We conduct a substantial portion
of our terminalling and storage operations under long-term contracts, which enhances the stability
and predictability of our operations and cash flow. We attempt to balance our short term and long
term terminalling contracts in order to allow us to maintain a consistent level of cash flow while
maintaining flexibility to earn higher storage revenues when demand for storage space increases. At
our Ouachita County terminal, Cross Oil Refining & Marketing, Inc., a related party owned by Martin
Resource Management, operates the terminal under a long-term terminalling agreement whereby we
receive a throughput fee. We also continually evaluate opportunities to add services and increase
access to our terminals to attract more customers and create additional revenues. The following is
a summary description of our specialty marine terminals:
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Aggregate |
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Terminal |
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Location |
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Tanks(3) |
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Capacity |
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Products |
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Description |
Tampa(1)
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Tampa, Florida
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7 |
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719,000 Bbls.
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Asphalt and fuel oil
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Marine terminal,
loading/unloading
for vessels,
barges and trucks |
Stanolind(2)
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Beaumont, Texas
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2 |
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160,000 Bbls.
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Asphalt and fuel oil
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Marine terminal,
loading/unloading
for vessels,
barges and trucks |
Neches
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Beaumont, Texas
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7 |
|
|
500,400 Bbls.
|
|
Ammonia, asphalt, fuel
oil, sulfuric acid and
fertilizer
|
|
Marine terminal,
loading/unloading
for vessels,
barges, railcars
and trucks |
Ouachita County
|
|
Ouachita County,
Arkansas
|
|
|
2 |
|
|
77,500 Bbls.
|
|
Crude oil
|
|
Marine terminal,
loading/unloading
for vessels, barges
and trucks |
Corpus Christi
|
|
Corpus Christi,
Texas
|
|
|
3 |
|
|
249,000Bbls.
|
|
Fuel oil and diesel
|
|
Marine Terminal,
loading/unloading
barges and vessels
and unloading
trucks |
|
|
|
(1) |
|
This terminal is located on land owned by the Tampa Port Authority that was leased to us
under a lease that expired in December 2006. We are currently leasing this facility on a
month-to-month basis and have received a proposal for a new lease agreement that extends the
term for 10 years with two additional five year extension options. |
|
(2) |
|
A portion of this terminal is located on land owned by Martin Resource Management and on land
we own. We use marine terminal, loading and unloading, and other common use facilities owned
by Martin Resource Management under a perpetual use, ingress-egress and utility facilities
easement. |
|
(3) |
|
In addition to the tanks listed in the table we own one tank at our Tampa terminal and three
tanks at the Stanolind terminal in connection with our sulfur business. Martin Resource
Management owns two tanks at the Stanolind terminal. |
Inland Terminals. We own or operate four inland terminals. At Mont Belvieu, Texas, we own a
rail unloading terminal where we unload and measure petroleum by-products and transport these
products via a half-mile pipeline to Enterprise Products Texas Operating L.P.s NGL fractionator
facility. Our fees for the use of this facility are based on the number of gallons unloaded at the
terminal. In Channelview, Texas, we operate an inland terminal used for lubricant storage,
packaging and distribution. This terminal is used as our central hub for lubricant distribution
where we receive, package, and ship our lubricants to our terminals or directly to customers. In
Houston, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin
Resource Management through a terminalling
- 7 -
service agreement based upon throughput rates. In Port Neches, Texas, we own an asphalt
terminal whose use is dedicated to an affiliate of Martin Resource Management through a
terminalling service agreement based upon throughput rates.
The following is a summary description our inland terminals:
|
|
|
|
|
|
|
|
|
Terminal |
|
Location |
|
Aggregate Capacity |
|
Products |
|
Description |
Channelview(1)
|
|
Houston, Texas
|
|
10,000 sq. ft.
warehouse
|
|
Lubricants
|
|
Truck
loading/unloading
|
Mont Belvieu
South Houston
|
|
Mont Belvieu, Texas
|
|
20 rail car spaces
|
|
Propane-propylene
mix
|
|
Rail car unloading |
Asphalt
|
|
Houston, Texas
|
|
71,000 bbls
|
|
Asphalt
|
|
Asphalt Processing
and storage |
Port Neches Asphalt
|
|
Port Neches, Texas
|
|
31,250 bbls
|
|
Asphalt
|
|
Asphalt Processing and storage |
|
|
|
(1) |
|
This terminal is located on land owned by a third party and leased to us under a lease that
expires in May 2009 and can be extended by us to May 2014. |
Competition. We compete with independent terminal operators and major energy and chemical
companies that own their own terminalling and storage facilities. We believe many customers prefer
to contract with independent terminal operators rather than terminal operators owned by integrated
energy and chemical companies that may have refining or marketing interests that compete with the
customers.
Independent terminal owners generally compete on the basis of the location and versatility of
terminals, service and price. A favorably-located terminal has access to various cost effective
transportation modes, both to and from the terminal, such as waterways, railroads, roadways and
pipelines. Terminal versatility depends upon the operators ability to handle diverse products,
some of which have complex or specialized handling and storage requirements. The service function
of a terminal includes, among other things, the safe storage of product at specified temperature,
moisture and other conditions, and receiving and delivering product to and from the terminal. All
of these services must be in compliance with applicable environmental and other regulations.
We believe we successfully compete for terminal customers because of the strategic location of
our terminals along the Gulf Coast, our integrated transportation services, our reputation, the
prices we charge for our services and the quality and versatility of our services. Additionally,
while some companies have significantly more terminalling and storage capacity than us, not all
terminalling and storage facilities located in the markets we serve are equipped to properly handle
specialty products such as asphalt, sulfur or sulfuric acid. As a result, our facilities typically
command higher terminal fees when compared to fees charged for terminalling and storage of other
petroleum products.
The principal competitive factors affecting our terminals which provide lubricant distribution
and marketing as well as shore bases at certain terminals, are the locations of the facilities,
availability of competing logistical support services, and the experience of personnel and
dependability of service. The distribution and marketing of our lubricant products is brand
sensitive, and we encounter brand loyalty competition. Shore base rental contracts are generally
long-term contracts and provide more protection from competition. Our primary competitors for both
lubricants and shore bases include several independent operations as well as major companies that
maintain their own similarly equipped marine terminals, shore bases and lubricant supply sources.
Natural Gas Services Segment
NGL Industry Overview. NGLs are produced through natural gas processing. They are also a
by-product of crude oil refining. NGL consists of hydrocarbons that are vapors at atmospheric
temperatures and pressures but change to liquid phase under pressure. NGLs include ethane,
propane, normal butane, iso butane and natural gasoline.
- 8 -
Ethane is almost entirely used as a petrochemical feedstock in the production of ethylene and
propylene. Propane is used as a petrochemical feedstock in the production of ethylene and
propylene, as a fuel for heating, for industrial applications, as motor fuel and as a refrigerant.
Normal butane is used as a petrochemical feedstock, as a blend stock for motor gasoline and as a
component in aerosol propellants. Normal butane can also be made into iso butane through
isomerization. Iso butane is used in the production of motor gasoline, petrochemical feedstock and
as a component in aerosol propellants. Natural gasoline is used as a component of motor gasoline
and as a petrochemical feedstock.
NGL Facilities. We purchase NGLs primarily from major domestic oil refiners and natural gas
processors. We transport NGLs using Martin Resource Managements land transportation fleet or by
contracting with common carriers, owner-operators and railroad tank cars. We typically enter into
annual contracts with independent retail propane distributors to deliver their estimated annual
volume requirements based on prevailing market prices. We believe dependable delivery is very
important to these customers and in some cases may be more important than price. We ensure adequate
supply of NGLs through:
|
|
|
storage of NGLs purchased in off-peak months; |
|
|
|
|
efficient use of the transportation fleet of vehicles owned by Martin Resource Management; and |
|
|
|
|
product management expertise to obtain supplies when needed. |
The following is a summary description of our owned and leased NGL facilities:
|
|
|
|
|
|
|
NGL Facility(1) |
|
Location |
|
Capacity |
|
Description |
Retail terminals
|
|
Kilgore, Texas
|
|
90,000 gallons
|
|
Retail propane distribution |
|
|
Longview, Texas
|
|
30,000 gallons
|
|
Retail propane distribution |
|
|
Henderson, Texas
|
|
12,000 gallons
|
|
Retail propane
distribution storage |
|
|
Arcadia, Louisiana(2)
|
|
65 million gallons
|
|
Underground storage |
|
|
Hattiesburg, Mississippi(3)
|
|
4.2 million gallons
|
|
Underground storage |
|
|
Mt. Belvieu, Texas(3)
|
|
2.8 million gallons
|
|
Underground storage |
|
|
|
(1) |
|
In addition, under a throughput agreement, we are entitled to the sole access to and
use of a truck loading and unloading and pipeline distribution terminal owned by Martin
Resource Management and located at Mont Belvieu, Texas. Effective each January 1, this
agreement automatically renews for consecutive one-year periods unless either party
terminates the agreement by giving written notice to the other party at least 30 days prior
to the expiration of the then-applicable term. This terminal facility has a storage
capacity of 330,000 gallons. |
|
(2) |
|
We lease our underground storage at Arcadia, Louisiana from Martin Resource Management
under a three-year product storage agreement, which is renewable on a yearly basis
thereafter subject to a re-determination of the lease rate for each subsequent year. |
|
(3) |
|
We lease our underground storage at Hattiesburg, Mississippi and Mont Belvieu, Texas from
third parties under one-year lease agreements, which have been renewed annually for more
than 20 years. |
Our NGL customers that utilize these assets consist of retail propane distributors, industrial
processors and refiners. For the year ended December 31, 2006, we sold approximately 37% of our NGL
volume to independent retail propane distributors located in Texas and the southeastern United
States and approximately 63% of our NGL volume to refiners and industrial processors.
NGL Competition. We compete with large integrated NGL producers and marketers, as well as
small local independent marketers. NGLs compete primarily with natural gas, electricity and fuel
oil as an energy source, principally on the basis of price, availability and portability.
NGL Seasonality. The level of NGL supply and demand is subject to changes in domestic
production, weather, inventory levels and other factors. While production is not seasonal,
residential and wholesale demand is highly seasonal. This imbalance causes increases in inventories
during summer months when consumption is low and decreases in inventories during winter months when
consumption is high. If inventories are low at the start of the winter, higher prices are more
likely to occur during the winter. Additionally, abnormally cold weather can put extra upward
pressure on prices during the winter because there are less readily available sources of additional
supply except
- 9 -
for imports which are less accessible and may take several weeks to arrive. General economic
conditions and inventory levels have a greater impact on industrial and refinery use of NGLs than
the weather.
Although the NGL industry is subject to seasonality factors, such factors generally do not
affect our natural gas services business because we do not consume NGLs. We generally maintain
consistent margins in our natural gas services business because we attempt to pass increases and
decreases in the cost of NGLs directly to our customers. We generally try to coordinate our sales
and purchases of NGLs based on the same daily price index of NGLs in order to decrease the impact
of NGL price volatility on our profitability.
Prism Gas Acquisition. On November 10, 2005 we acquired Prism Gas. Following this
acquisition, Prism Gas is operated and reported as part of our natural gas services business
segment, which has been expanded to include natural gas gathering and processing as well as the NGL
services business described herein.
Prism Gas has ownership interests in over 440 miles of natural gas gathering pipelines located
in the natural gas producing regions of North Central Texas and East Texas, Northwest Louisiana,
the Texas Gulf Coast and offshore Texas and federal waters in the Gulf of Mexico as well as a 150
MMcfd natural gas processing plant located in East Texas which is currently being expanded to 250
MMcfd. The underlying assets are in two operating areas:
North Central Texas and East Texas
|
|
|
The North Central Texas and East Texas area assets consist of the Waskom
Processing Plant, the McLeod Gathering System, the Hallsville Gathering System, the
Marshall Line, Bosque County Pipeline and the East Texas Gathering System. |
|
|
|
|
Waskom Processing Plant The Waskom Processing Plant, located in Harrison
County in East Texas, currently has 150 MMcfd of processing capacity with full
fractionation facilities. In January 2007, the Waskom fractionator was expanded to a
capacity of 12,500 barrels per day. In addition, an increase in the processing
capacity of the plant to 250 MMcfd is expected to be completed by the end of the second
quarter of 2007. For the year ended December 31, 2006, inlet throughput and NGL
fractionation averaged approximately 183 MMcfd and 7,677 bpd, respectively. Prism Gas
owns an unconsolidated 50% operating interest in the Waskom Processing Plant with
CenterPoint Energy Gas Processing, Inc. owning the remaining 50% non-operating
interest. We reflect the results of operations from this facility using the equity
method of accounting. |
|
|
|
|
McLeod Gathering System The McLeod Gathering System, located in East Texas and
Northwest Louisiana, is a low pressure gathering system connected to the Waskom
Processing Plant, providing processing and blending services for natural gas with high
nitrogen and high liquids content gathered by the system. For the year ended December
31, 2006, the McLeod Gathering System gathered approximately 6 MMcfd of natural gas.
Prism Gas owns a consolidated 100% interest in this system. |
|
|
|
|
Hallsville Gathering System The Hallsville Gathering System, which
Prism Gas constructed in 2006, is located in Harrison County, Texas, provides gathering
and centralized compression for producers in the Oak Hill Field of East Texas. The
system operates at low pressure and redelivers gas to two interstate and three
intrastate markets via the Oakhill Gathering System. Prism Gas owns a consolidated
100% interest in this system. |
|
|
|
|
The Marshall Line The Marshall Line is a 10 gathering line that Prism
Gas began leasing from Kinder Morgan Texas in 2006. It is located in Harrison County,
Texas. The Marshall Line gathers gas at intermediate pressure and feeds the Waskom
Processing Plant. Prism Gas owns a consolidated 100% interest in the lease. |
|
|
|
|
Bosque County Pipeline The Bosque County Pipeline, gathers gas in four
North Central Texas counties centered around Bosque County. Prism Gas owns an
unconsolidated 20% non-operating |
- 10 -
|
|
|
interest in a partnership that owns the lease rights to the assets of the Bosque
County Pipeline, with Panther Pipeline Ltd. owning a 42.5% operating interest and
Star of Texas, et al owning the remaining 37.5% interest. |
|
|
|
|
East Texas Gathering System The East Texas Gathering System, located in
Panola County, Texas, is comprised of gathering systems built to gather gas produced in
this area to market outlets. Prism Gas owns a consolidated 100% interest in these
systems. |
The natural gas supply for the Waskom Processing Plant, the McLeod Gathering System, the
Hallsville Gathering System, the Marshall Line and the East Texas Gathering System is derived
primarily from natural gas wells located in the Cotton Valley formation of East Texas and Northwest
Louisiana. The Cotton Valley formation is one of the largest tight gas plays in the U.S. and
extends over fourteen counties in East Texas and into Northwest Louisiana. Prism Gas East Texas
Operating Area includes assets that provide gathering and processing services to producers in Cass,
Gregg, Harrison, Panola, and Rusk Counties, Texas and Caddo Parish, Louisiana. The total number of
wells permitted in Prism Gas East Texas Operating Area was 1,878 and 1,512 in calendar years 2006
and 2005, respectively. These annual permit numbers include 22 permits for horizontal wells in
2006 and 10 permits for horizontal wells in 2005. Improved technology, drilling applications and
commodity prices have enhanced the economics of drilling in the Cotton Valley formation. This
increase in drilling activity has provided us with access to newly developed natural gas supplies.
The natural gas supply for the Bosque County Pipeline is expected to be derived primarily from
natural gas wells in the Barnett Shale formation of North Central Texas. The Bosque County
Pipeline is located in the southern extension of the Barnett Shale formation.
Our primary suppliers of natural gas to the Waskom Processing Plant include BP America
Production Company, Centerpoint Energy Gas Transmission Company and Devon Energy Corporation, which
collectively represented approximately 62% of the 160 MMcfd of natural gas supplied in 2005 and
approximately 61% of the 183 MMcfd of natural gas supplied for the year ended December 31, 2006. A
substantial portion (approximately 35%) of the Waskom Processing Plants inlet volumes are derived
from production at BPs Blocker, East Mountain, Carthage and Woodlawn fields in East Texas.
Production from these fields is dedicated to the Waskom Processing Plant under a contract with BP
for the life of the Waskom partnership. We receive natural gas at the Waskom Processing Plant from
our McLeod Gathering System. We also receive a significant amount of trucked-in NGLs that are
fractionated, treated and stabilized at the Waskom Processing Plant. The tightening of pipeline dew
point specifications and access to local markets with high NGL demand has resulted in increased
trucked-in NGL volumes at the Waskom Processing Plant. In October 2006, we began construction to
expand the fractionator to 12,500 bpd. to provide additional capacity for this increase in
trucked-in NGL volumes. This expansion was completed in late January 2007.
There are currently three competing processing plants, with another two under construction,
that operate or will operate within a 40-mile radius of our Waskom facility. Drilling activity in
the Cotton Valley trend is moving north from the Panola-Harrison County line further into Harrison
County. Our plant is the preferred gas plant for much of this new production due to its proximity
to the increased drilling activity. In addition, the Waskom Processing Plant is the only plant in
this area that has full fractionation capability with access to strong local markets for NGLs.
Purchasers of NGLs fractionated at Waskom include various chemical companies and other industrial
distributors. Prior to the Prism Gas acquisition, we were one of the largest purchasers of NGLs at
the Waskom Processing Plant.
The Waskom Processing Plants processing contracts are predominately percent-of-liquids (POL)
contracts, in which we retain a portion of the NGLs recovered as a processing fee. The plant also
operates under percent-of-proceeds (POP) contracts in which we retain a portion of both the residue
gas and the NGLs as payment for services. There are currently only two minor contracts for
processing on a keep-whole basis. We are not contractually required to process these keep-whole
volumes and, therefore, only process natural gas related to these contracts under profitable
conditions.
The McLeod Gathering System is a low-pressure gathering system that provides an outlet for
high nitrogen and high liquids content gas. In June 2003, Prism Gas constructed a pipeline to tie
the McLeod Gathering System to the Waskom Processing Plant to provide an outlet for high nitrogen
gas. As a result, the majority of gas gathered on
- 11 -
the McLeod Gathering System is transported to the Waskom Processing Plant for processing and
blending. Revenue from the McLeod Gathering System is earned through gathering and compression fees
and processing revenue. The processing revenue results from the difference in the processing
agreements with the producers and the agreement that we have with the Waskom partnership. The
processing contracts in the McLeod Gathering System are predominately percent-of-proceeds (POP)
contracts. Natural gas gathered in the region surrounding the McLeod Gathering System has two
primary outlets, including the Waskom Processing Plant.
Cotton Valley wells are now being drilled in the southern area served by the McLeod Gathering
System. The new Cotton Valley wells that have recently been tied into the system are
percent-of-liquids (POL) contracts with a small gathering fee. These contracts are typically lower
margin, higher volume contracts. In this area, competition is geographic based with the McLeod
Gathering System capturing wells that are located near the system and the competitor capturing
wells that are near its system.
The Hallsville Gathering System was constructed in 2005 and 2006 to gather low pressure gas.
The wells tied into the system are fee based gathering contracts.
The Marshall Line was leased from Kinder Morgan to provide additional sources of gas for the
Waskom Processing Plant. The gas on the system is from Cotton Valley production and is tied into
the system under percent of index based contracts.
The Bosque County Pipeline is an approximate 67 mile pipeline located in the Barnett Shale
extension. The pipeline traverses four counties with the most concentrated drilling occurring in
Bosque County. In this area competition is limited due to a lack of existing infrastructure. The
lack of infrastructure and the limited development in the area allow it to generally capture new
wells drilled in close proximity to its system.
The East Texas Gathering System was constructed in 2004 to tie producers into Gulf South
Pipeline Companys gathering system in Panola County, Texas. These lines are sized to handle
volumes that are expected to increase as producers continue to develop Cotton Valley sands in areas
that were traditionally marginal. The existing East Texas Gathering System contracts are all
fee-for-service contracts dependent on volumes gathered.
Gulf Coast
|
|
|
The Gulf Coast area assets consist of the Fishhook Gathering System and
the Matagorda Gathering System located offshore and onshore of the Texas Gulf Coast. |
|
|
|
|
Fishhook Gathering System The Fishhook Gathering System, located in
Jefferson County, Texas and offshore federal waters, gathers and transports gas in both
offshore and onshore areas. For the year ended December 31, 2006, the Fishhook Pipeline
gathered and transported approximately 32 MMcfd of natural gas. Prism Gas owns an
unconsolidated 50% non-operating interest in Panther Interstate Pipeline Energy, LLC,
the owner of the Fishhook Gathering System, with Panther Pipeline Ltd owning the
remaining 50% operating interest. We reflect the results of operations from this system
using the equity method of accounting. |
|
|
|
|
Matagorda Offshore Gathering System The Matagorda Offshore Gathering
System, located in Matagorda County, Texas and offshore Texas state waters, gathers gas
in both the offshore and onshore areas. For the year ended December 31, 2006, the
Matagorda Offshore Gathering System gathered approximately 10 MMcfd of natural gas.
Prism Gas owns an unconsolidated 50% non-operating interest in the Matagorda Offshore
Gathering System, with Panther Pipeline Ltd. owning the remaining 50% operating
interest. We reflect the results of operations from this system using the equity method
of accounting. |
The Fishhook Gathering System and the Matagorda Offshore Gathering System gather and transport
natural gas from Texas and federal waters of the Gulf of Mexico to onshore pipelines. The Fishhook
Pipeline gathers and transports natural gas principally from the eastern portion of the High Island
Area which is further offshore. The offshore natural gas supply for the Matagorda Offshore
Gathering System is produced primarily from the Brazos
- 12 -
Area blocks, which are near shore in the Texas state waters. Additionally, the Matagorda
Offshore Gathering System includes onshore gathering in Matagorda, Wharton and Brazoria Counties.
The Fishhook Gathering System is located in federal waters offshore from Beaumont, Texas and
gathers gas from producers. This area is characterized by strong drilling activity with
traditionally high volume, high decline wells. Typically, two to four of these traditional wells
are drilled near the Fishhook Gathering System each year. Contracts on this system are 100%
fee-for-service contracts with both the gathering fee and the maximum transmission fee stated in
Panther Interstate Pipeline Energy, LLCs FERC Gas Tariff, on file with the Federal Energy
Regulatory Commission. There are currently two competing pipelines in the area which limit our
ability to increase margins on this system. However, we believe that our existing relationships
with active producers will enable us to capture additional volumes from new production in this
area.
The Matagorda Offshore Gathering System gathers gas from producers. Contracts for the
offshore portion of the Matagorda Offshore Gathering System are a combination of fixed
transportation fees plus a fixed margin. The contracts for the onshore portion of the Matagorda
Offshore Gathering System are under either a fixed margin or a fixed transportation fee. There is
limited competition for the offshore portion of the pipeline. There are currently two pipelines
situated in the offshore area but they primarily gather natural gas from wells further offshore
than the Matagorda Offshore Gathering System. There are several pipelines that compete with the
onshore portion of the system. These competing pipelines result in lower margins for the onshore
portion of this system.
Marine Transportation Segment
Industry Overview. The United States inland waterway system is a vast and heavily used
transportation system. This inland waterway system is composed of a network of interconnected
rivers and canals that serve as water highways and is used to transport vast quantities of products
annually. This waterway system extends approximately 26,000 miles, of which 12,000 miles are
generally considered significant for domestic commerce.
The Gulf Coast region is a major hub for petroleum refining. Approximately two-thirds of
United States refining capacity expansion in the 1990s occurred in this region. The hydrocarbon
refining process generates products and by-products that require transportation in large quantities
from the refinery or processor. Convenient access to and use of this waterway system by the
petroleum and petrochemical industry is a major reason for the current location of United States
refineries and petrochemical facilities. Recent growth in refining and natural gas processing
capacity has increased the volume of petroleum products and by-products transported within the Gulf
Coast region, which consequently has increased the need for transportation, storage and
distribution facilities.
The marine transportation industry uses push boats and tugboats as power sources and tank
barges for freight capacity. The combination of the power source and tank barge freight capacity is
called a tow.
Marine Fleet. We own a fleet of inland and offshore tows that provide marine transportation
of petroleum products and by-products produced in oil refining and natural gas processing. Our
marine transportation system operates on the United States inland waterway system, primarily
between domestic ports along the Gulf of Mexico Intracoastal Waterway, the Mississippi River system
and the Tennessee-Tombigbee Waterway system. Our inland tows generally consist of one push boat and
one to three tank barges, depending upon the horsepower of the push boat, the river or canal
capacity and conditions, and customer requirements. Each of our offshore tows consist of one
tugboat, with much greater horsepower than an inland push boat, and one large tank barge.
We transport asphalt, fuel oil, gasoline, sulfur and other bulk liquids. The following is a
summary description of the marine vessels we use in our marine transportation business:
|
|
|
|
|
|
|
|
|
Class of Equipment |
|
Number in Class |
|
Capacity/Horsepower |
|
Description of Products Carried |
Inland tank barges
|
|
|
15 |
|
|
20,000 bbl and under
|
|
Asphalt, crude oil, fuel oil,
gasoline and sulfur(1) |
Inland tank barges
|
|
|
22 |
|
|
20,000 30,000 bbl
|
|
Asphalt, crude oil, fuel oil
and gasoline(1) |
Inland push boats
|
|
|
16 |
|
|
800 1,800
horsepower
|
|
N/A |
|
Offshore tank barges
|
|
|
4 |
|
|
40,000 bbl and 95,000
bbl
|
|
Asphalt, fuel oil and NGLs |
|
Offshore tugboats
|
|
|
4 |
|
|
3,200 7,200
horsepower
|
|
N/A |
- 13 -
|
|
|
(1) |
|
One of our 15 inland tank barges with capacity of up to 20,000 bbl, and nine of our 22 inland
tank barges with capacity of 20,000 to 30,000 bbl, are specialized and equipped to transport
asphalt. |
Our largest marine transportation customers include major and independent oil and gas refining
companies, petroleum marketing companies and Martin Resource Management. We conduct our marine
transportation services under spot contracts and under term contracts that typically range from one
to 12 months in length.
In order to maintain a balance of pricing flexibility and stable cash flow, we strive to
maintain an appropriate mix of spot versus term contracts, based on current market conditions.
We are a party to a marine transportation agreement effective January 1, 2006 under which we
provide marine transportation services to Martin Resource Management on a spot-contract basis at
applicable market rates. This agreement replaced a prior agreement between us and Martin Resource
Management covering marine transportation services which expired in November 2005. Effective each
January 1, this agreement automatically renews for consecutive one-year periods unless either party
terminates the agreement by giving written notice to the other party at least 60 days prior to the
expiration of the then-applicable term. The fees we charge Martin Resource Management are based on
applicable market rates.
Competition. We compete primarily with other marine transportation companies. The marine
barging industry has experienced significant consolidation in the past few years. The total number
of tank barges and push boats that operate in the inland waters of the United States declined from
approximately 4,200 in 1982 to approximately 2,900 in 1993 and has reduced to approximately 2,800
since 1993. We believe the earlier decrease primarily resulted from:
|
|
|
the increasing age of the domestic tank barge fleet, resulting in
retirements; |
|
|
|
|
a reduction in tax incentives, which previously encouraged speculative
construction of new equipment; |
|
|
|
|
stringent operating standards to adequately address safety and environmental risks; |
|
|
|
|
the elimination of government programs supporting small refineries; |
|
|
|
|
an increase in environmental regulations mandating expensive equipment modification; and |
|
|
|
|
more restrictive and expensive insurance. |
There are several barriers to entry into the marine transportation industry that discourage
the emergence of new competitors. Examples of these barriers to entry include:
|
|
|
significant start-up capital requirements; |
|
|
|
|
the costs and operational difficulties of complying with stringent safety
and environmental regulations; |
|
|
|
|
the cost and difficulty in obtaining insurance; and |
|
|
|
|
the number and expertise of personnel required to support marine fleet operations. |
We believe the reduction of the number of tank barges, the consolidation among barging
companies and the significant barriers to entry in the industry have resulted in a more stabilized
and favorable pricing environment for our marine transportation services.
We believe we compete favorably with many of our competitors. Historically, competition within
the marine transportation business was based primarily on price. However, we believe customers are
placing an increased emphasis on safety, environmental compliance, quality of service and the
availability of a single source of supply of a diversified package of services. In particular, we
believe customers are increasingly seeking transportation vendors that
- 14 -
can offer marine, land, rail and terminal distribution services, as well as provide
operational flexibility, safety, environmental and financial responsibility, adequate insurance and
quality of service consistent with the customers own operations and policies. We operate a
diversified asset base that, together with the services provided by Martin Resource Management,
enables us to offer our customers an integrated distribution network consisting of transportation,
terminalling, distribution and midstream logistical services for petroleum products and
by-products.
In addition to competitors that provide marine transportation services, we also compete with
providers of other modes of transportation, such as rail tank cars, tractor-trailer tank trucks
and, to a limited extent, pipelines. We believe we offer a competitive advantage over rail tank
cars and tractor-trailer tank trucks because marine transportation is a more efficient, and
generally less expensive, mode of transporting petroleum products and by-products. For example, a
typical two inland barge unit carries a volume of product equal to approximately 80 rail cars or
250 tanker trucks. Pipelines generally provide a less expensive form of transportation than marine
transportation. However, pipelines are not able to transport most of the products we transport and
are generally a less flexible form of transportation because they are limited to the fixed
point-to-point distribution of commodities in high volumes over extended periods of time.
Seasonality. The demand for our marine transportation business is subject to some seasonality
factors. Our asphalt shipments are generally higher during April through November when weather
allows for efficient road construction. However, demand for marine transportation of sulfur, fuel
oil and gasoline is directly related to production of these products in the oil refining and
natural gas processing business, which is fairly stable.
Sulfur Segment
Industry Overview. Sulfur is a natural element and is required to produce a variety of
industrial products. In the United States, approximately 11 million tons of sulfur is consumed
annually, with the Tampa, Florida area being the largest single market. Currently, all sulfur
produced in the United States is recovered sulfur, or sulfur that is a by-product from oil
refineries and natural gas processing plants. Sulfur production in the United States is principally
located along the Gulf Coast, along major inland waterways and in some areas of the western United
States.
Sulfur is an important plant nutrient and is used in the manufacture of phosphate fertilizers.
Approximately 53% of worldwide sulfur consumption is currently used for phosphate fertilizers, with
the balance used for industrial purposes. The primary application of sulfur in fertilizers occurs
in the form of sulfuric acid. Burning sulfur creates sulfur dioxide, which is subsequently oxidized
and dissolved in water to create sulfuric acid. The sulfuric acid is then combined with phosphate
rock to make phosphoric acid, the base material for most high-grade phosphate fertilizers.
In addition to agricultural applications, sulfur (usually in the form of sulfuric acid) is
essential for manufacturing pharmaceuticals, paper, chemicals, paint, steel, petroleum and other
products. Sulfuric acid is the most commonly produced chemical in the world.
Our Operations and Products. Our sulfur segment was established in April 2005, as a result of
the acquisition of the Bay Sulfur assets and the beginning of construction of a sulfur priller at
our Neches facility in Beaumont, Texas. The sulfur prilling assets we acquired from Bay Sulfur are
located at the Port of Stockton in California and are used to process molten sulfur into pellets.
These dry, bulk pellets are stored and loaded at our facility at the Port of Stockton. The sulfur
pellets are sold into certain U.S. and international agricultural markets. Our facility at the Port
of Stockton can process approximately 1,000 metric tons of molten sulfur per day. We also have
completed the construction of a sulfur priller at our Neches facility in Beaumont, Texas. This
facility has the capacity to process approximately 2,000 metric tons of molten sulfur per day. Our
sulfur prilling facilities provide refiners with an alternative market for the sale of their
residual sulfur.
On July 15, 2005, we acquired the remaining partnership interests in CF Martin Sulphur in
which we owned a 49.5% interest since November, 2000 from CF Industries, Inc. and certain
affiliates of Martin Resource Management for $18.9 million. Prior to the acquisition, CF Martin
Sulphur was managed and operated by its general partner who was equally owned and controlled by
certain affiliates of Martin Resource Management and CF Industries. Subsequent to the acquisition,
the partnership controlled the management of CF Martin Sulphur and conducted its day to day
operations. CF Martin Sulphur, a wholly owned partnership, was included in our consolidated
financial statements and included in the financial presentation of our sulfur segment. As of March
30, 2006, CF Martin Sulphur merged into Martin Operating Partnership L.P. and continues to be
reported in our sulfur segment and operates doing business as Martin Sulfur.
- 15 -
Martin Sulfur gathers molten sulfur from refiners, primarily located on the Gulf Coast, and
from natural gas processing plants, primarily located in the southwestern United States. We
transport sulfur by inland and offshore barges, rail cars and trucks. In 2006, Martin Sulfur
handled approximately 1.7 million long tons of sulfur. In the U.S. recovered sulfur is mainly kept
in liquid form from production to usage at a temperature of approximately 275 degrees Fahrenheit.
Because of the temperature requirement, the sulfur industry uses specialized equipment to store and
transport molten sulfur. We have the necessary transportation and storage assets and expertise to
handle the unique requirements for transportation and storage of molten sulfur for domestic
customers.
The term of our commercial contracts typically range from one to five years in length. The
prices in such contracts are usually tied to a published market indicator and fluctuate, typically
quarterly, according to the price movement of the indicator. We also provide barge transportation
and tank storage to large integrated oil companies that produce sulfur and fertilizer manufacturers
that consume sulfur under transportation and storage contracts that range from three to five years
in duration.
Our Sulfur Facilities. We lease approximately 180 railcars equipped to transport molten
sulfur. We own the following major marine assets and use them to ship molten sulfur from our
Beaumont, Texas terminal to our Tampa, Florida terminal:
|
|
|
|
|
|
|
Asset |
|
Class of Equipment |
|
Capacity/Horsepower |
|
Products Transported |
Margaret Sue
|
|
Offshore tank barge
|
|
10,450 long tons
|
|
Molten sulfur |
M/V Martin Explorer
|
|
Offshore tugboat
|
|
7,200 horsepower
|
|
N/A |
M/V Martin Express
|
|
Inland push boat
|
|
1,200 horsepower
|
|
N/A |
MGM 101
|
|
Inland tank barge
|
|
2,450 long tons
|
|
Molten sulfur |
MGM 102
|
|
Inland tank barge
|
|
2,450 long tons
|
|
Molten sulfur |
We own the following tanks as part of our molten sulfur business:
|
|
|
|
|
|
|
|
|
|
|
Terminal |
|
Location |
|
Tanks |
|
Total Aggregate Capacity |
|
Products Stored |
Tampa
|
|
Tampa, Florida
|
|
|
1 |
|
|
16,000 long tons
|
|
Molten sulfur |
Stanolind
|
|
Beaumont, Texas
|
|
|
3 |
|
|
46,500 long tons
|
|
Molten sulfur |
We own the following sulfur prilling facilities as part of our sulfur business:
|
|
|
|
|
|
|
Terminal |
|
Location |
|
Daily Production Capacity |
|
Products Stored |
Stockton
|
|
Stockton, California
|
|
1,000 metric tons per day
|
|
Molten and prilled sulfur |
Neches
|
|
Beaumont, Texas
|
|
2,000 metric tons per day
|
|
Molten and prilled sulfur |
Competition. Seven phosphate fertilizer manufacturers together consume a vast majority of the
total United States production of sulfur. These companies buy from resellers as well as directly
from producers. We own one of the four vessels currently used to transport molten sulfur between
Tampa, Florida and United States ports on the Gulf of Mexico. Our primary competition consists of
producers that sell their production directly to a fertilizer manufacturer that has its own
transportation assets or foreign suppliers from Mexico or Venezuela that may sell into the Florida
market.
Fertilizer Segment
Industry Overview. Fertilizers are manufactured chemicals containing nutrients known to
improve the fertility of soils. Nitrogen, phosphorus, potassium and sulfur are the four most
important nutrients for crop growth. These nutrients are found naturally in soils. However, soils
used for agriculture become depleted of these nutrients and frequently require fertilizers rich in
these essential nutrients to restore fertility. The Fertilizer Institute has estimated that the
earths soil contains less than 20% of organic plant nutrients needed to meet worldwide food
production needs. As a result, we believe mineral fertilizer production will continue to be an
important industrial market.
Industrial sulfur products are used in a wide variety of industries. For example, these
products are used in power plants, paper mills, auto and tire manufacturing plants, food processing
plants, road construction, cosmetics and pharmaceuticals. The largest consumers of industrial
sulfur products are power plants, paper mills and rubber products manufacturers.
Our Operations and Products. We entered the fertilizer manufacturing business in 1990 through
an acquisition. We acquired two additional fertilizer manufacturing companies in 1998. Over the
next two years we
- 16 -
expended significant resources to replace and update facilities and other assets at the
companies, and to integrate each of the businesses into our business. These acquisitions have
subsequently increased the profitability of our fertilizer business. In December 2005, sulfur
fertilizer production capacity was added with the purchase of the net operating assets of A & A
Fertilizer, Ltd. (A & A Fertilizer). This production capacity is located at our Neches deep-water
marine terminal near Beaumont, Texas.
Fertilizer and related sulfur products are a natural extension of our business because of our
access to sulfur and our distribution capabilities. This business allows us to leverage the sulfur
segment of our business. Our annual fertilizer and industrial sulfur products sales have grown from
approximately 62,000 tons in 1997 to approximately 210,000 tons in 2006 as a result of acquisitions
and internal growth.
We manufacture and market the following fertilizer and related sulfur products:
|
|
|
Plant nutrient sulfur products. We produce plant nutrient and agricultural
ground sulfur products at our two facilities in Odessa, Texas. We also produce plant
nutrient sulfur at our facility in Seneca, Illinois. Our plant nutrient sulfur product
is a 90% degradable sulfur product marketed under the Disper-Sul® trade name and sold
throughout the United States to direct application agricultural markets. Our
agricultural ground sulfur products are used primarily in the western United States on
grapes and vegetable crops. |
|
|
|
|
Ammonium sulfate products, NPK products and related blended products. We
produce various grades of ammonium sulfate including coarse and standard grades, a 40%
ammonium sulfate solution and a Kosher-approved food grade material. We also produce
nitrogen-phosphorus-potassium products (commonly referred to as NPK products). Our NPK
products are an ammoniated phosphate fertilizer containing nitrogen, phosphorus and
potash that we manufacture so all particles have a uniform composition. These products
primarily serve direct application agricultural markets within a 400-mile radius of our
manufacturing plant in Plainview, Texas. We blend our ammonium sulfate to make custom
grades of lawn and garden fertilizer at our facility in Salt Lake City, Utah. We
package these custom grade products under both proprietary and private labels and sell
them to major retail distributors, and other retail customers, of these products. |
|
|
|
|
Industrial sulfur products. We produce industrial sulfur products such as
emulsified sulfur, elemental pastille sulfur, and industrial ground sulfur products. We
produce emulsified sulfur at our Texarkana, Texas facility. Emulsified sulfur is
primarily used to control the sulfur content in the pulp and paper manufacturing
processes. We produce elemental pastille sulfur at our two Odessa, Texas facilities and
at our Seneca, Illinois facility. Elemental pastille sulfur is used to increase the
efficiency of the coal-fired precipitators in the power industry. These industrial
ground sulfur products are also used in a variety of dusting and wettable sulfur
applications such as rubber manufacturing, fungicides, sugar and animal feeds. |
|
|
|
|
Liquid sulfur products. We produce ammonium thiosulfate at our Neches
terminal location in Beaumont, Texas. This agricultural sulfur product is a clear
liquid containing 12% nitrogen and 26% sulfur. This product serves as a liquid plant
nutrient used directly through spray rigs or irrigation systems. It is also blended
with other NPK liquids or suspensions as well. Our market is predominantly the Mid
South and Coastal Bend area of Texas. |
Our Fertilizer Plants. The following is a summary description of our fertilizer plants:
|
|
|
|
|
|
|
Facility |
|
Location |
|
Capacity |
|
Description |
Two fertilizer plants
|
|
Odessa, Texas
|
|
70,000 tons/year
|
|
Dry sulfur fertilizer production |
Fertilizer plant
|
|
Seneca, Illinois
|
|
36,000 tons/year
|
|
Dry sulfur fertilizer production |
Fertilizer plant
|
|
Plainview Texas
|
|
180,000 tons/year
|
|
Fertilizer production |
Fertilizer plant
|
|
Salt Lake City, Utah
|
|
25,000 tons/year
|
|
Blending and packaging |
Industrial sulfur plant
|
|
Texarkana, Texas
|
|
18,000 tons/year
|
|
Emulsified sulfur production |
Fertilizer plant
|
|
Beaumont, Texas
|
|
70,000 tons/year
|
|
Liquid sulfur fertilizer
Production |
- 17 -
In the United States, fertilizer is generally sold to farmers through local dealers. These
dealers are typically owned and supplied by much larger wholesale distributors. We sell primarily
to these wholesale distributors, as well as to a small number of independent dealers throughout the
United States. Our industrial sulfur products are marketed primarily in the eastern United States,
where many paper manufacturers and power plants are located.
Our fertilizer products are sold in accordance with our price lists that vary from state to
state. We update our price lists periodically to make seasonal pricing adjustments. If necessary,
we adjust our price lists more frequently to maintain competitive pricing. These products are sold
at negotiated prices, generally set on an annual basis. We transport our fertilizer and industrial
sulfur products to our customers using third party common carriers. We utilize rail shipments for
large volume and long distance shipments where available.
Competition. We compete with several other large fertilizer and sulfur products
manufacturers. However, we believe our close proximity to our customers is a competitive advantage
for us. Because our manufacturing plants are located close to our customer base, we are able to
save on freight costs and respond quickly to customer requests, and we also believe we have greater
insight about local market conditions. Additionally, we believe the development of our sulfur
business affords us a secure and reliable source of sulfur materials.
Seasonality. Sales of our agricultural fertilizer are partly seasonal as a result of
increased demand during the growing season. Sales of our industrial sulfur-based products, however,
are generally consistent throughout the year. In 2006, approximately 18% of our product sales
volumes were to industrial users.
Our Relationship with Martin Resource Management
Martin Resource Management is engaged in the following principal business activities:
|
|
|
providing land transportation of various liquids using a fleet of trucks
and road vehicles and road trailers; |
|
|
|
|
distributing fuel oil, asphalt, sulfuric acid, marine fuel and other
liquids; |
|
|
|
|
providing marine bunkering and other shore-based marine services in
Alabama, Louisiana, Mississippi and Texas; |
|
|
|
|
operating a small crude oil gathering business in Stephens, Arkansas; |
|
|
|
|
operating a lube oil processing facility in Smackover, Arkansas; |
|
|
|
|
operating an underground NGL storage facility in Arcadia, Louisiana; |
|
|
|
|
supplying employees and services for the operation of our business; |
|
|
|
|
operating, for its account and our account, the docks, roads, loading and
unloading facilities and other common use facilities or access routes at our Stanolind
terminal; and |
|
|
|
|
operating, solely for our account, an NGL truck loading and unloading and
pipeline distribution terminal in Mont Belvieu, Texas. |
We are and will continue to be closely affiliated with Martin Resource Management as a result
of the following relationships.
Ownership
Martin Resource Management owns an approximate 38.6% limited partnership interest and a 2%
general partnership interest in us and all of our incentive distribution rights.
Management
- 18 -
Martin Resource Management directs our business operations through its ownership and control
of our general partner. We benefit from our relationship with Martin Resource Management through
access to a significant pool of management expertise and established relationships throughout the
energy industry. We do not have employees. Martin Resource Management employees are responsible
for conducting our business and operating our assets on our behalf.
Related Party Agreements
We are a party to an omnibus agreement with Martin Resource Management. The omnibus agreement
requires us to reimburse Martin Resource Management for all direct and indirect expenses it incurs
or payments it makes on our behalf or in connection with the operation of our business. We
reimbursed Martin Resource Management for $49.1 million of direct costs and expenses for the twelve
months ended December 31, 2006 compared to $42.1 million for the twelve months ended December 31,
2005. There is no monetary limitation on the amount we are required to reimburse Martin Resource
Management for direct expenses. Under the omnibus agreement, the reimbursement amount with respect
to indirect general and administrative and corporate overhead expenses was capped at $2.0 million
for the period ending October 31, 2006. Subsequently, this amount may be increased by no more than
the percentage increase in the consumer price index. In addition, Martin Resource Management and
us can agree, subject to approval of the Conflicts Committee of our general partner, to adjust this
amount for expansions of our operations and acquisitions. We reimbursed Martin Resource Management
for $1.5 million of indirect expenses for the twelve months ended December 31, 2006 compared to
$1.3 million for the twelve months ended December 31, 2005. These indirect expenses cover all of
the centralized corporate functions Martin Resource Management provides for us, such as accounting,
treasury, clerical billing, information technology, administration of insurance, general office
expenses and employee benefit plans and other general corporate overhead functions we share with
Martin Resource Management retained businesses. The omnibus agreement also contains significant
non-compete provisions and indemnity obligations. Martin Resource Management also licenses certain
of its trademarks and trade names to us under the omnibus agreement.
In addition to the omnibus agreement, we and Martin Resource Management have entered into
various other agreements that are not the result of arms-length negotiations and consequently may
not be as favorable to us as they might have been if we had negotiated them with unaffiliated third
parties. The agreements include, but are not limited to, a motor carrier agreement, a terminal
services agreement, a marine transportation agreement, a product storage agreement, a product
supply agreement, a throughput agreement, and a Purchaser Use Easement, Ingress-Egress Easement and
Utility Facilities Easement. Pursuant to the terms of the omnibus agreement, we are prohibited
from entering into certain material agreements with Martin Resource Management without the approval
of the conflicts committee of our general partners board of directors.
For a more comprehensive discussion concerning the omnibus agreement and the other agreements
that we have entered into with Martin Resource Management, please see Item 13. Certain
Relationships and Related Transactions Agreements.
Commercial
We have been and anticipate that we will continue to be both a significant customer and
supplier of products and services offered by Martin Resource Management. Our motor carrier
agreement with Martin Resource Management provides us with access to Martin Resource Managements
fleet of road vehicles and road trailers to provide land transportation in the areas served by
Martin Resource Management. Our ability to utilize Martin Resource Managements land transportation
operations is currently a key component of our integrated distribution network.
We also use the underground storage facilities owned by Martin Resource Management in our
natural gas services operations. We lease an underground storage facility from Martin Resource
Management in Arcadia, Louisiana with a storage capacity of 65 million gallons. Our use of this
storage facility gives us greater flexibility in our operations by allowing us to store a
sufficient supply of product during times of decreased demand for use when demand increases.
- 19 -
In the aggregate, our purchases of land transportation services, NGL storage services,
sulfuric acid and lube oil product purchases and sulfur and fertilizer payroll reimbursements from
Martin Resource Management accounted for approximately 14%, 7% and 6% of our total cost of products
sold during the years ended December 31, 2006, 2005 and 2004, respectively. We also purchase marine
fuel from Martin Resource Management, which we account for as an operating expense.
Correspondingly, Martin Resource Management is one of our significant customers. It primarily
uses our terminalling, marine transportation and NGL distribution services for its operations. We
provide terminalling and storage services under a terminal services agreement. We provide marine
transportation services to Martin Resource Management under a charter agreement on a spot-contract
basis at applicable market rates. Our sales to Martin Resource Management accounted for
approximately 4%, 5% and 8% of our total revenues for the years ended December 31, 2006, 2005 and
2004, respectively. In connection with the closing of the Tesoro Marine asset acquisition, we
entered into certain agreements with Martin Resource Management pursuant to which we provide
terminalling and storage and marine transportation services to Midstream Fuel and Midstream Fuel
provides terminal services to us to handle lubricants, greases and drilling fluids.
For a more comprehensive discussion concerning these commercial agreements that we have
entered into with Martin Resource Management, please see Item 13. Certain Relationships and
Related Transactions Agreements.
Approval and Review of Related Party Transactions
If we contemplate entering into a transaction, other than a routine or in the ordinary course
of business transaction, in which a related person will have a direct or indirect material
interest, the proposed transaction is submitted for consideration to the board of directors of our
general partner or to our management, as appropriate. If the board of directors is involved in the
approval process, it determines whether to refer the matter to the Conflicts Committee of
our general partners board of directors, as constituted under our limited partnership agreement.
If a matter is referred to the Conflicts Committee, it obtains information regarding the proposed
transaction from management and determines whether to engage independent legal counsel or an
independent financial advisor to advise the members of the committee regarding the transaction. If
the Conflicts Committee retains such counsel or financial advisor, it considers such advice and, in
the case of a financial advisor, such advisors opinion as to whether the transaction is fair and
reasonable to us and to our unitholders.
Our Relationship with CF Martin Sulphur, L.P.
On July 15, 2005, we acquired all of the remaining limited partnership interests in CF Martin
Sulphur from CF Industries, Inc. and certain affiliates of Martin Resource Management. Prior to
this transaction, our unconsolidated non-controlling 49.5% limited partnership interest in CF
Martin Sulphur, was accounted for using the equity method of accounting. In addition, on July 15,
2005, we acquired all of the outstanding membership interests in CF Martin Sulphurs general
partner. Subsequent to the acquisition, CF Martin Sulphur was a wholly owned partnership which is
included in the consolidated financial presentation of our sulfur segment. Effective March 30,
2006, CF Martin Sulphur was merged into us.
Prior to July 15, 2005, we were both an important supplier to and customer of CF Martin
Sulphur. We chartered one of our offshore tug/barge tanker units to CF Martin Sulphur for a
guaranteed daily rate, subject to certain adjustments. This charter, which had an unlimited term,
was terminated on November 18, 2005. CF Martin Sulphur paid to have this tug/barge tanker unit
reconfigured to carry molten sulfur. In the event CF Martin Sulphur had terminated this charter
agreement, we would have been obligated to reimburse CF Martin Sulphur for a portion of such
reconfiguration costs. As a result of the July 15, 2005 acquisition of all the outstanding
interests in CF Martin Sulphur, this contingent obligation was terminated.
Insurance
Loss of, or damage to, our vessels and cargo is insured through hull and cargo insurance
policies. Vessel operating liabilities such as collision, cargo, environmental and personal injury
are insured primarily through our participation in mutual insurance associations and other
reinsurance arrangements, pursuant to which we are potentially exposed to assessments in the event
claims by us or other members exceed available funds and reinsurance. Protection and indemnity, or
P&I, insurance coverage is provided by P&I associations and other insurance underwriters. Our
- 20 -
vessels are entered in P&I associations that are parties to a pooling agreement, known as the
International Group Pooling Agreement, or the Pooling Agreement, through which approximately 95% of
the worlds commercial shipping tonnage is reinsured through a group reinsurance policy. With
regard to collision coverage, the first $1.0 million of coverage is insured by our hull policy and
any excess is insured by a P&I association. We insure our owned cargo through a domestic insurance
company. We insure cargo owned by third parties through our P&I coverage. As a member of P&I
associations that are parties to the Pooling Agreement, we are subject to supplemental calls
payable to the associations of which we are a member, based on our claims record and the other
members of the other P&I associations that are parties to the Pooling Agreement. Except for our
marine operations, we self-insure against liability exposure up to a pre-determined amount, beyond
which we are covered by catastrophe insurance coverage.
For marine pollution claims, our insurance covers up to $1.0 billion of liability per accident
or occurrence and for non-pollution incidents, our insurance covers up to $2.0 billion of liability
per accident or occurrence. We believe our current insurance coverage is adequate to protect us
against most accident related risks involved in the conduct of our business and that we maintain
appropriate levels of environmental damage and pollution insurance coverage. However, there can be
no assurance that all risks are adequately insured against, that any particular claim will be paid
by the insurer, or that we will be able to procure adequate insurance coverage at commercially
reasonable rates in the future.
Environmental and Regulatory Matters
Our activities are subject to various federal, state and local laws and regulations, as well
as orders of regulatory bodies, governing a wide variety of matters, including marketing,
production, pricing, community right-to-know, protection of the environment, safety and other
matters.
Environmental
We are subject to complex federal, state, and local environmental laws and regulations
governing the discharge of materials into the environment or otherwise relating to protection of
human health, natural resources and the environment. These laws and regulations can impair our
operations that affect the environment in many ways, such as requiring the acquisition of permits
to conduct regulated activities; restricting the manner in which we can release materials into the
environment; requiring remedial activities or capital expenditures to mitigate pollution from
former or current operations; and imposing substantial liabilities on us for pollution resulting
from our operations. Many environmental laws and regulations can impose joint and several, strict
liability, and any failure to comply with environmental laws and regulations may result in the
assessment of administrative, civil, and criminal penalties, the imposition of investigatory and
remedial obligations, and, in some circumstances, the issuance of injunctions that can limit or
prohibit our operations.
The clear trend in environmental regulation is to place more restrictions and limitations on
activities that may affect the environment, and, thus, any changes in environmental laws and
regulations that result in more stringent and costly waste handling, storage, transport, disposal,
or remediation requirements could have a material adverse effect on our operations and financial
position. Moreover, there is inherent risk of incurring significant environmental costs and
liabilities in the performance of our operations due to our handling of petroleum hydrocarbons,
chemical substances, and wastes as well as the accidental release or spill of such materials into
the environment. Consequently, we cannot assure you that we will not incur significant costs and
liabilities as result of such handling practices, releases or spills, including those relating to
claims for damage to property and persons. In the event of future increases in costs, we may be
unable to pass on those increases to our customers. While we believe that we are in substantial
compliance with current environmental laws and regulations and that continued compliance with
existing requirements would not have a material adverse impact on us, we cannot provide any
assurance that our environmental compliance expenditures will not have a material adverse impact on
us in the future.
Superfund
The Federal Comprehensive Environmental Response, Compensation and Liability Act, as amended,
(CERCLA), also known as the Superfund law, and similar state laws, impose liability without
regard to fault or the legality of the original conduct, on certain classes of responsible
persons, including the owner or operator of a site where regulated hazardous substances have been
released into the environment and companies that disposed or arranged for the disposal of the
hazardous substances found at such site. Under CERCLA, these responsible persons may be subject to
joint and several, strict liability for the costs of cleaning up the hazardous substances that have
been
- 21 -
released into the environment, for damages to natural resources, and for the costs of certain
health studies, and it is not uncommon for neighboring landowners and other third parties to file
claims for personal injury and property damage allegedly caused by the release of hazardous
substances into the environment. Although certain hydrocarbons are not subject to CERCLAs reach
because petroleum is excluded from CERCLAs definition of a hazardous substance, in the course
of our ordinary operations we will generate wastes that may fall within the definition of a
hazardous substance. We have not received any notification that we may be potentially responsible
for cleanup costs under CERCLA.
Solid Waste
We generate both hazardous and nonhazardous solid wastes which are subject to requirements of
the federal Resource Conservation and Recovery Act, as amended (RCRA) and comparable state
statutes. From time to time, the U.S. Environmental Protection Agency (EPA) has considered making
changes in nonhazardous waste standards that would result in stricter disposal requirements for
these wastes. Furthermore, it is possible some wastes generated by us that are currently classified
as nonhazardous may in the future be designated as hazardous wastes, resulting in the wastes
being subject to more rigorous and costly disposal requirements. Changes in applicable regulations
may result in an increase in our capital expenditures or operating expenses.
We currently own or lease, and have in the past owned or leased, properties that have been
used for the manufacturing, processing, transportation and storage of petroleum products and
by-products. Solid waste disposal practices within oil and gas related industries have improved
over the years with the passage and implementation of various environmental laws and regulations.
Nevertheless, a possibility exists that hydrocarbons and other solid wastes may have been disposed
of on or under various properties owned or leased by us during the operating history of those
facilities. In addition, a number of these properties have been operated by third parties over whom
we had no control as to such entities handling of hydrocarbons, hydrocarbon by-products or other
wastes and the manner in which such substances may have been disposed of or released. State and
federal laws and regulations applicable to oil and natural gas wastes and properties have gradually
become more strict and, under such laws and regulations, we could be required to remove or
remediate previously disposed wastes or property contamination, including groundwater
contamination, even under circumstances where such contamination resulted from past operations of
third parties.
Clean Air Act
Our operations are subject to the federal Clean Air Act, as amended, and comparable state
statutes. Amendments to the Clean Air Act adopted in 1990 contain provisions that may result in the
imposition of increasingly stringent pollution control requirements with respect to air emissions
from the operations of our terminal facilities, processing and storage facilities and fertilizer
and related products manufacturing and processing facilities. Such air pollution control
requirements may include specific equipment or technologies to control emissions, permits with
emissions and operational limitations, pre-approval of new or modified projects or facilities
producing air emissions, and similar measures. For example, the Mont Belvieu terminal we use is
located in an EPA-designated ozone non-attainment area, referred to as the Houston-Galveston
non-attainment area, which is now subject to a new, EPA-adopted 8-hour standard for complying with
the national standard for ozone. Categorized as being in moderate non-attainment for ozone, the
Houston-Galveston non-attainment area has until 2010 to achieve compliance with this new standard,
which almost certainly will require the adoption of more restrictive regulations in this non-
attainment area for the issuance of air permits for new or modified facilities. In addition,
existing sources of air emissions in the Houston-Galveston area are already subject to stringent
emission reduction requirements. Failure to comply with applicable air statutes or regulations may
lead to the assessment of administrative, civil or criminal penalties, and/or result in the
limitation or cessation of construction or operation of certain air emission sources. We believe
our operations, including our manufacturing, processing and storage facilities and terminals, are
in substantial compliance with applicable requirements of the Clean Air Act and analogous state
laws.
Clean Water Act
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and
analogous state laws impose restrictions and controls on the discharge of pollutants into federal
and state waters. Regulations promulgated under these laws require entities that discharge into
federal and state waters obtain National Pollutant Discharge Elimination System (NPDES) and/or
state permits authorizing these discharges. The Clean Water Act and analogous state laws assess
penalties for releases of unauthorized pollutants into the water and impose substantial liability
for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous
state laws
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require that individual permits or coverage under general permits be obtained by covered
facilities for discharges of storm water runoff and that applicable facilities develop and
implement plans for the management of storm water runoff (referred to as storm water pollution
prevention plans or SWPPPs) as well as for the prevention and control of oil spills (referred to
as spill prevention, control and countermeasure or SPCC plans). As part of the regular overall
evaluation of our on-going operations, we are reviewing and, as necessary, updating SWPPPs for
certain of our facilities, including facilities recently acquired. In addition, we have reviewed
our SPCC plans and, where necessary, amended such plans to comply with applicable regulations
adopted by EPA in 2002.. We believe that compliance with the conditions of such permits and plans
will not have a material effect on our operations.
On August 7, 2000, a spill of molten sulfur occurred at our Stanolind terminal near Beaumont,
Texas, which at the time was owned and operated by Martin Gas Sales LLC, a wholly-owned subsidiary
of Martin Resource Management. Martin Gas Sales LLC has since changed its name to Martin Product
Sales, LLC. The Texas Department of Health and Texas Natural Resource Conservation Commission (the
predecessor agency to the present-day Texas Commission on Environmental Quality) investigated the
spill and its clean-up. These agencies found that there was no impact on public health, and that
there was no reason to remove the solidified sulfur from the river bottom. However, the United
States attorney in Beaumont, Texas, initiated an investigation under the criminal provisions of the
Clean Water Act. To avoid protracted litigation and possible criminal claims against employees,
Martin Product Sales agreed to plead guilty to a single felony violation of the federal Clean Water
Act and was sentenced to pay a $50,000 fine. As part of its plea agreement with the United States,
Martin Product Sales also agreed to implement a remedial program at our Stanolind terminal and our
sulfur loading facility in Tampa, Florida. Martin Product Sales instituted the remedial program as
of March 1, 2002, and we believe that it has been substantially implemented, although it must
remain in effect for five years. Martin Product Sales does not have any contracts with the United
States government that might be affected by a debarment or listing proceeding, and the United
States Attorneys Office has agreed to inform any agency initiating a debarment or listing
proceeding of the implementation of the remedial program. A previous criminal conviction, however,
may result in increased fines and other sanctions if Martin Product Sales is subsequently convicted
or pleads guilty to a similar offense in the future. Martin Resource Management will indemnify us
under the omnibus agreement for any losses we suffer within five years from November 6, 2002, the
date of our initial public offering that relate to or result from, this event.
Oil Pollution Act
The Oil Pollution Act of 1990, as amended (OPA) imposes a variety of regulations on
responsible parties related to the prevention of oil spills and liability for damages resulting
from such spills in United States waters. A responsible party includes the owner or operator of a
facility or vessel, or the lessee or permittee of the area in which an offshore facility is
located. The OPA assigns liability to each responsible party for oil removal costs and a variety of
public and private damages including natural resource damages. Under OPA, vessels and shore
facilities handling, storing, or transporting oil are required to develop and implement oil spill
response plans, and vessels greater than 300 tons in weight must provide to the United States Coast
Guard evidence of financial responsibility to cover the costs of cleaning up oil spills from such
vessels. The OPA also requires that all newly constructed tank barges engaged in oil transportation
in the United States be double hulled and all existing single hull tank barges be retrofitted with
double hulls or phased out by 2015. We believe we are in substantial compliance with all of these
oil spill-related and financial responsibility requirements.
Safety Regulation
The Companys marine transportation operations are subject to regulation by the United States
Coast Guard, federal laws, state laws and certain international treaties. Tank ships, push boats,
tugboats and barges are required to meet construction and repair standards established by the
American Bureau of Shipping, a private organization, and the United States Coast Guard and to meet
operational and safety standards presently established by the United States Coast Guard. We believe
our marine operations and our terminals are in substantial compliance with current applicable
safety requirements.
Occupational Health Regulations
The workplaces associated with our manufacturing, processing, terminal and storage facilities
are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and
comparable state statutes. We believe we have conducted our operations in substantial compliance
with OSHA requirements, including general industry standards, record keeping requirements and
monitoring of occupational exposure to regulated substances. In
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May 2001, Martin Resource Management paid a small fine in relation to the settlement of
alleged OSHA violations at our facility in Plainview, Texas. Although we believe the amount of this
fine and the nature of these violations were not, as an individual event, material to our business
or operations, this violation may result in increased fines and other sanctions if we are cited for
similar violations in the future. Our marine vessel operations are also subject to safety and
operational standards established and monitored by the United States Coast Guard.
In general, we expect to increase our expenditures relating to compliance with likely higher
industry and regulatory safety standards such as those described above. These expenditures cannot
be accurately estimated at this time, but we do not expect them to have a material adverse effect
on our business.
Jones Act
The Jones Act is a federal law that restricts maritime transportation between locations in the
United States to vessels built and registered in the United States and owned and manned by United
States citizens. Since we engage in maritime transportation between locations in the United States,
we are subject to the provisions of the law. As a result, we are responsible for monitoring the
ownership of our subsidiaries that engage in maritime transportation and for taking any remedial
action necessary to insure that no violation of the Jones Act ownership restrictions occurs. The
Jones Act also requires that all United States-flag vessels be manned by United States citizens.
Foreign-flag seamen generally receive lower wages and benefits than those received by United States
citizen seamen. This requirement significantly increases operating costs of United States-flag
vessel operations compared to foreign-flag vessel operations. Certain foreign governments subsidize
their nations shipyards. This results in lower shipyard costs both for new vessels and repairs
than those paid by United States-flag vessel owners. The United States Coast Guard and American
Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which
tends to result in higher regulatory compliance costs for United States-flag operators than for
owners of vessels registered under foreign flags of convenience. Following Hurricane Katrina, and
again after Hurricane Rita, emergency suspensions of the Jones Act were effectuated by the United
States government. The last suspension ended on October 24, 2005. Future suspensions of the Jones
Act or other similar actions could adversely affect our cash flow and ability to make distributions
to our unitholders.
Merchant Marine Act of 1936
The Merchant Marine Act of 1936 is a federal law that provides that, upon proclamation by the
president of the United States of a national emergency or a threat to the national security, the
United States secretary of transportation may requisition or purchase any vessel or other
watercraft owned by United States citizens (including us, provided that we are considered a United
States citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased
or requisitioned by the United States government under this law, we would be entitled to be paid
the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the
fair market value of charter hire. However, if one of our push boats or tugboats is requisitioned
or purchased and its associated tank barge is left idle, we would not be entitled to receive any
compensation for the lost revenues resulting from the idled barge. We also would not be entitled to
be compensated for any consequential damages we suffer as a result of the requisition or purchase
of any of our push boats, tugboats or tank barges.
Regulations Affecting Natural Gas Transmission, Processing and Gathering
We own a 50% non-operating interest in Panther Interstate Pipeline Energy, LLC. Panther
Interstate Pipeline Energy, LLCs Fishhook Gathering System transports natural gas in interstate
commerce and is thus subject to FERC regulations and FERC-approved tariffs as a natural gas company
under the National Gas Act of 1938 (the NGA). Under the NGA, FERC has issued orders requiring
pipelines to provide open-access transportation on a basis that is equal for all shippers. In
addition, FERC has the authority to regulate natural gas companies with respect to: rates, terms
and conditions of service; the types of services Panther Interstate Pipeline Energy, LLC may
provide to its customers; the construction of new facilities; the acquisition, extension, expansion
or abandonment of services or facilities; the maintenance and retention of accounts and records;
and relationships of affiliated companies involved in all aspects of the natural gas and energy
business.
On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of
2005 (the EP Act). The EP Act is a comprehensive compilation of tax incentives, authorized
appropriations for grants and guaranteed loans, and significant changes to the statutory policy
that affects all segments of the energy industry. With respect to regulation of natural gas
transportation, the EP Act amends the NGA and the Natural Gas Policy Act of 1978
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by increasing the criminal penalties available for violations of each act. The EP Act also
adds a new section to the NGA which provides FERC with the power to assess civil penalties of up to
$1,000,000 per day per violation of the NGA.
Additional proposals and proceedings that might affect the natural gas industry are pending
before Congress, FERC and the courts. However, we do not believe that we will be disproportionately
affected as compared to other natural gas producers and marketers by any action taken. We believe
that our natural gas gathering operations meet the tests FERC uses to establish a pipelines status
as a gatherer exempt from FERC regulation under the NGA, but FERC regulation still affects these
businesses and the markets for products derived from these businesses. FERCs policies and
practices across the range of its oil and natural gas regulatory activities, including, for
example, its policies on open access transportation, ratemaking, capacity release and market center
promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive
policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure
our unitholders that FERC will continue this approach as it considers matters such as pipeline
rates and rules and policies that may affect rights of access to oil and natural gas transportation
capacity. In addition, the distinction between FERC-regulated transmission services and federally
unregulated gathering services has been the subject of regular litigation, so, in such a
circumstance, the classification and regulation of some of our gathering facilities and intrastate
transportation pipelines may be subject to change based on future determinations by FERC and the
courts.
Other state and local regulations also affect our natural gas processing and gathering
business. Our gathering lines are subject to ratable take and common purchaser statutes in
Louisiana and Texas. Ratable take statutes generally require gatherers to take, without undue
discrimination, oil or natural gas production that may be tendered to the gatherer for handling.
Similarly, common purchaser statutes generally require gatherers to purchase without undue
discrimination as to source of supply or producer. These statutes restrict our right as an owner of
gathering facilities to decide with whom we contract to purchase or transport oil or natural gas.
Federal law leaves any economic regulation of natural gas gathering to the states. The states in
which we operate have adopted complaint-based regulation of oil and natural gas gathering
activities, which allows oil and natural gas producers and shippers to file complaints with state
regulators in an effort to resolve grievances relating to oil and natural gas gathering access and
rate discrimination. Other state regulations may not directly regulate our business, but may
nonetheless affect the availability of natural gas for purchase, processing and sale, including
state regulation of production rates and maximum daily production allowable from gas wells. While
our gathering lines currently are subject to limited state regulation, there is a risk that state
laws will be changed, which may give producers a stronger basis to challenge proprietary status of
a line, or the rates, terms and conditions of a gathering line providing transportation service.
Pursuant to the Pipeline Safety Improvement Act of 2002, the United States Department of
Transportation (DOT) has adopted regulations requiring pipeline operators to develop integrity
management programs for transportation pipelines located where a leak or rupture could do the most
harm in high consequence areas. The regulations require operators to:
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perform ongoing assessments of pipeline integrity; |
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identify and characterize applicable threats to pipeline segments that
could impact a high consequence area; |
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improve data collection, integration and analysis; |
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repair and remediate the pipeline as necessary; and |
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implement preventive and mitigating actions. |
Employees
We do not have any employees. Under our omnibus agreement with Martin Resource Management,
Martin Resource Management provides us with corporate staff and support services. These services
include centralized corporate functions, such as accounting, treasury, engineering, information
technology, insurance, administration of employee benefit plans and other corporate services.
Martin Resource Management employs approximately 396 individuals who provide direct support to our
operations. None of these employees are represented by labor unions.
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Financial Information about Segments
Information regarding our operating revenues and identifiable assets attributable to each of
our segments is presented in Note 19 to our consolidated financial statements included in this
annual report on Form 10-K.
Access to Public Filings
We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K, and amendments to these reports filed with the Securities and Exchange
Commission (SEC) under the Securities and Exchange Act of 1934. These documents may be accessed
free of charge on our website at the following address: www.martinmidstream.com. These documents
are provided as soon as is reasonably practicable after their filing with the SEC. These documents
may also be found at the SECs website at www.sec.gov. This website address is intended to be an
inactive, textual reference only, and none of the material on this website is part of this report.
Item 1A. Risk Factors
Limited partner interests are inherently different from the capital stock of a corporation,
although many of the business risks to which we are subject are similar to those that would be
faced by a corporation engaged in a business similar to ours. If any of the following risks were
actually to occur, our business, financial condition or results of operations could be materially
adversely affected. In this case, we might not be able to pay distributions on our common units,
the trading price of our common units could decline and unitholders could lose all or part of their
investment. These risk factors should be read in conjunction with the other detailed information
concerning us set forth herein.
Risks Relating to Our Business
Important factors that could cause actual results to differ materially from our expectations
include, but are not limited to, the risks set forth below. The risks described below should not be
considered to be comprehensive and all-inclusive. Additional risks that we do not yet know of or
that we currently think are immaterial may also impair our business operations, financial condition
and results of operations. If any events occur that give rise to the following risks, our business,
financial condition, or results of operations could be materially and adversely affected, and as a
result, the trading price of our common units could be materially and adversely impacted. Many of
such factors are beyond our ability to control or predict. Unitholders are cautioned not to put
undue reliance on forward-looking statements.
We may not have sufficient cash after the establishment of cash reserves and payment of our general
partners expenses to enable us to pay the minimum quarterly distribution each quarter.
We may not have sufficient available cash each quarter in the future to pay the minimum
quarterly distribution on all our units. Under the terms of our partnership agreement, we must pay
our general partners expenses and set aside any cash reserve amounts before making a distribution
to our unitholders. The amount of cash we can distribute on our common units principally depends
upon the amount of net cash generated from our operations, which will fluctuate from quarter to
quarter based on, among other things:
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the costs of acquisitions, if any; |
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the prices of petroleum products and by-products; |
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fluctuations in our working capital; |
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the level of capital expenditures we make; |
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restrictions contained in our debt instruments and our debt service requirements; |
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our ability to make working capital borrowings under our credit facility; and |
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the amount, if any, of cash reserves established by our general partner in its discretion.
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Unitholders should also be aware that the amount of cash we have available for distribution
depends primarily on our cash flow, including cash flow from working capital borrowings, and not
solely on profitability, which will be affected by non-cash items. In addition, our general partner
determines the amount and timing of asset purchases and sales, capital expenditures, borrowings,
issuances of additional partnership securities and the establishment of reserves, each of which can
affect the amount of cash available for distribution to our unitholders. As a result, we may make
cash distributions during periods when we record losses and may not make cash distributions during
periods when we record net income.
Adverse weather conditions, including droughts, hurricanes, tropical storms and other severe
weather, could reduce our results of operations and ability to make distributions to our
unitholders.
Our distribution network and operations are primarily concentrated in the Gulf Coast region
and along the Mississippi River inland waterway. Weather in these regions is sometimes severe
(including tropical storms and hurricanes) and can be a major factor in our day-to-day operations.
Our marine transportation operations can be significantly delayed, impaired or postponed by adverse
weather conditions, such as fog in the winter and spring months, and certain river conditions.
Additionally, our terminalling and storage and marine transportation operations and our assets in
the Gulf of Mexico, including our barges, push boats, tugboats and terminals, can be adversely
impacted or damaged by hurricanes, tropical storms, tidal waves or other related events. Demand for
our lubricants and the diesel fuel we throughput in our terminalling and storage segment can be
affected if offshore drilling operations are disrupted by weather in the Gulf of Mexico.
National weather conditions have a substantial impact on the demand for our products.
Unusually warm weather during the winter months can cause a significant decrease in the demand for
NGL products, fuel oil and gasoline. Likewise, extreme weather conditions (either wet or dry) can
decrease the demand for fertilizer. For example, an unusually wet spring can delay planting of
seeds, which can leave insufficient time to apply fertilizer at the planting stage. Conversely,
drought conditions can kill or severely stunt the growth of crops, thus eliminating the need to
nurture plants with fertilizer. Any of these or similar conditions could result in a decline in our
net income and cash flow, which would reduce our ability to make distributions to our unitholders.
If we incur material liabilities that are not fully covered by insurance, such as liabilities
resulting from accidents on rivers or at sea, spills, fires or explosions, our results of
operations and ability to make distributions to our unitholders could be adversely affected.
Our operations are subject to the operating hazards and risks incidental to terminalling and
storage, marine transportation and the distribution of petroleum products and by-products and other
industrial products. These hazards and risks, many of which are beyond our control, include:
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accidents on rivers or at sea and other hazards that could result in
releases, spills and other environmental damages, personal injuries, loss of life and
suspension of operations; |
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leakage of NGLs and other petroleum products and by-products; |
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fires and explosions; |
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damage to transportation, terminalling and storage facilities, and
surrounding properties caused by natural disasters; and |
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terrorist attacks or sabotage. |
Our insurance coverage may not be adequate to protect us from all material expenses related to
potential future claims for personal injury and property damage, including various legal
proceedings and litigation resulting from these hazards and risks. If we incur material liabilities
that are not covered by insurance, our operating results, cash flow and ability to make
distributions to our unitholders could be adversely affected.
Changes in the insurance markets attributable to the September 11, 2001 terrorist attacks, and
their aftermath, may make some types of insurance more difficult or expensive for us to obtain. In
addition, changes in the insurance markets attributable to the effects of Hurricanes Katrina and
Rita, and their aftermath, may make some types of insurance more difficult or expensive for us to
obtain. As a result, we may be unable to secure the levels and types of
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insurance we would otherwise have secured prior to such events. Moreover, the insurance that
may be available to us may be significantly more expensive than our existing insurance coverage.
The price volatility of petroleum products and by-products can reduce our results of operations and
ability to make distributions to our unitholders.
We purchase petroleum products and by-products such as molten sulfur, sulfur derivatives and
NGLs, and sell these products to wholesale and bulk customers and to other end users. Since the
closing of the Tesoro Marine asset acquisition, we and our affiliates also distribute and market
lubricants. We also generate revenues through the terminalling and storage of certain products for
third parties. The price and market value of petroleum products and by-products can be volatile.
Our revenues have been adversely affected by this volatility during periods of decreasing prices
because of the reduction in the value and resale price of our inventory. Future price volatility
could have an adverse impact on our results of operations, cash flow and ability to make
distributions to our unitholders.
Increasing energy prices could adversely affect our results of operations.
Increasing energy prices could adversely affect our results of operations. Diesel fuel,
natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price
of these products would increase our operating expenses which could adversely affect our results of
operations including net income and cash flows. We cannot assure unitholders that we will be able
to pass along increased operating expenses to our customers.
Restrictions in our credit facility may prevent us from making distributions to our unitholders.
The payment of principal and interest on our indebtedness reduces the cash available for
distribution to our unitholders. In addition, we are prohibited by our credit facility from making
cash distributions during an event of default or if the payment of a distribution would cause an
event of default thereunder. Our leverage and various limitations in our credit facility may reduce
our ability to incur additional debt, engage in certain transactions and capitalize on acquisition
or other business opportunities that could increase cash flows and distributions to our
unitholders.
If we do not have sufficient capital resources for acquisitions or opportunities for expansion, our
growth will be limited.
We intend to explore acquisition opportunities in order to expand our operations and increase
our profitability. We may finance acquisitions through public and private financing, or we may use
our limited partner interests for all or a portion of the consideration to be paid in acquisitions.
Distributions of cash with respect to these equity securities or limited partner interests may
reduce the amount of cash available for distribution to the common units. In addition, in the event
our limited partner interests do not maintain a sufficient valuation, or potential acquisition
candidates are unwilling to accept our limited partner interests as all or part of the
consideration, we may be required to use our cash resources, if available, or rely on other
financing arrangements to pursue acquisitions. If we use funds from operations, other cash
resources or increased borrowings for an acquisition, the acquisition could adversely impact our
ability to make our minimum quarterly distributions to our unitholders. Additionally, if we do not
have sufficient capital resources or are not able to obtain financing on terms acceptable to us for
acquisitions, our ability to implement our growth strategies may be adversely impacted.
Our recent and future acquisitions may not be successful, may substantially increase our
indebtedness and contingent liabilities, and may create integration difficulties.
As part of our business strategy, we intend to acquire businesses or assets we believe
complement our existing operations. We may not be able to successfully integrate recent or any
future acquisitions, including Prism Gas, into our existing operations or achieve the desired
profitability from such acquisitions. These acquisitions may require substantial capital
expenditures and the incurrence of additional indebtedness. If we make acquisitions, our
capitalization and results of operations may change significantly. Further, any acquisition could
result in:
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post-closing discovery of material undisclosed liabilities of the acquired business or assets; |
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the unexpected loss of key employees or customers from the acquired businesses; |
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difficulties resulting from our integration of the operations, systems and
management of the acquired business; and |
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an unexpected diversion of our managements attention from other
operations. |
If recent or any future acquisitions are unsuccessful or result in unanticipated events or if
we are unable to successfully integrate acquisitions into our existing operations, such
acquisitions could adversely affect our results of operations, cash flow and ability to make
distributions to our unitholders.
Demand for our terminalling and storage services is substantially dependent on the level of
offshore oil and gas exploration, development and production activity.
The level of offshore oil and gas exploration, development and production activity
historically has been volatile and is likely to continue to be so in the future. The level of
activity is subject to large fluctuations in response to relatively minor changes in a variety of
factors that are beyond our control, including:
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prevailing oil and natural gas prices and expectations about future prices and price volatility; |
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the cost of offshore exploration for, and production and transportation of, oil and natural gas; |
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worldwide demand for oil and natural gas; |
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consolidation of oil and gas and oil service companies operating offshore; |
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availability and rate of discovery of new oil and natural gas reserves in offshore areas; |
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local and international political and economic conditions and policies; |
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technological advances affecting energy production and consumption; |
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weather conditions; |
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environmental regulation; and |
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the ability of oil and gas companies to generate or otherwise obtain funds
for exploration and production. |
We expect levels of offshore oil and gas exploration, development and production activity to
continue to be volatile and affect demand for our terminalling and storage services.
Our NGL and fertilizer businesses are seasonal and could cause our revenues to vary.
The demand for NGL and natural gas is highest in the winter. Therefore, revenue from our
natural gas services business is higher in the winter than in other seasons. Our fertilizer
business experiences an increase in demand during the spring, which increases the revenue generated
by this business line in this period compared to other periods. The seasonality of the revenue from
these business lines may cause our results of operations to vary on a quarter to quarter basis and
thus could cause our cash available for quarterly distributions to fluctuate from period to period.
The highly competitive nature of our industry could adversely affect our results of operations and
ability to make distributions to our unitholders.
We operate in a highly competitive marketplace in each of our primary business segments. Most
of our competitors in each segment are larger companies with greater financial and other resources
than we possess. We may lose customers and future business opportunities to our competitors and any
such losses could adversely affect our results of operations and ability to make distributions to
our unitholders.
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Our business is subject to compliance with environmental laws and regulations that may expose us to
significant costs and liabilities and adversely affect our results of operations and ability to
make distributions to our unitholders.
Our business is subject to federal, state and local environmental laws and regulations
governing the discharge of materials into the environment or otherwise relating to protection of
human health, natural resources and the environment. These laws and regulations may impose numerous
obligations that are applicable to our operations, such as requiring the acquisition of permits to
conduct regulated activities; restricting the manner in which we can release materials into the
environment; requiring remedial activities or capital expenditures to mitigate pollution from
former of current operations; and imposing substantial liabilities on us for pollution resulting
from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection
Agency and analogous state agencies, have the power to enforce compliance with these laws and
regulations and the permits issued under them, oftentimes requiring difficult and costly actions.
Many environmental laws and regulations can impose joint and several strict liability, and any
failure to comply with environmental laws, regulations and permits may result in the assessment of
administrative, civil, and criminal penalties, the imposition of investigatory and remedial
obligations, and, in some circumstances, the issuance of injunctions that can limit or prohibit our
operations. The clear trend in environmental regulation is to place more restrictions and
limitations on activities that may affect the environment, and, thus, any changes in environmental
laws and regulations that result in more stringent and costly waste handling, storage, transport,
disposal, or remediation requirements could have a material adverse effect on our operations and
financial position.
The loss or insufficient attention of key personnel could negatively impact our results of
operations and ability to make distributions to our unitholders. Additionally, if neither Ruben
Martin nor Scott Martin is the chief executive officer of our general partner, amounts we owe under
our credit facility may become immediately due and payable.
Our success is largely dependent upon the continued services of members of the senior
management team of Martin Resource Management. Those senior executive officers have significant
experience in our businesses and have developed strong relationships with a broad range of industry
participants. The loss of any of these executives could have a material adverse effect on our
relationships with these industry participants, our results of operations and our ability to make
distributions to our unitholders. Additionally, if neither Ruben Martin nor Scott Martin is the
chief executive officer of our general partner, the lender under our credit facility could declare
amounts outstanding thereunder immediately due and payable. If such event occurs, our results of
operations and our ability to make distribution to our unitholders could be negatively impacted.
We do not have employees. We rely solely on officers and employees of Martin Resource
Management to operate and manage our business. Martin Resource Management operates businesses and
conducts activities of its own in which we have no economic interest. There could be competition
for the time and effort of the officers and employees who provide services to our general partner.
If these officers and employees do not or cannot devote sufficient attention to the management and
operation of our business, our results of operation and ability to make distributions to our
unitholders may be reduced.
Our loss of significant commercial relationships with Martin Resource Management could adversely
impact our results of operations and ability to make distributions to our unitholders.
Martin Resource Management provides us with various services and products pursuant to various
commercial contracts. The loss of any of these services and products provided by Martin Resource
Management could have a material adverse impact on our results of operations, cash flow and ability
to make distributions to our unitholders. Additionally, we provide terminalling and storage and
marine transportation services to Martin Resource Management to support its businesses under
various commercial contracts. The loss of Martin Resource Management as a customer could have a
material adverse impact on our results of operations, cash flow and ability to make distributions
to our unitholders.
Our business would be adversely affected if operations at our transportation, terminalling and
storage and distribution facilities experienced significant interruptions. Our business would also
be adversely affected if the operations of our customers and suppliers experienced significant
interruptions.
Our operations are dependent upon our terminalling and storage facilities and various means of
transportation. We are also dependent upon the uninterrupted operations of certain facilities owned
or operated by our suppliers and
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customers. Any significant interruption at these facilities or inability to transport products
to or from these facilities or to or from our customers for any reason would adversely affect our
results of operations, cash flow and ability to make distributions to our unitholders. Operations
at our facilities and at the facilities owned or operated by our suppliers and customers could be
partially or completely shut down, temporarily or permanently, as the result of any number of
circumstances that are not within our control, such as:
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catastrophic events, including hurricanes; |
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environmental remediation; |
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labor difficulties; and |
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disruptions in the supply of our products to our facilities or means of transportation. |
Additionally, terrorist attacks and acts of sabotage could target oil and gas production
facilities, refineries, processing plants, terminals and other infrastructure facilities. Any
significant interruptions at our facilities, facilities owned or operated by our suppliers or
customers, or in the oil and gas industry as a whole caused by such attacks or acts could have a
material adverse affect on our results of operations, cash flow and ability to make distributions
to our unitholders.
Our marine transportation business would be adversely affected if we do not satisfy the
requirements of the Jones Act, or if the Jones Act were modified or eliminated.
The Jones Act is a federal law that restricts domestic marine transportation in the United
States to vessels built and registered in the United States. Furthermore, the Jones Act requires
that the vessels be manned and owned by United States citizens. If we fail to comply with these
requirements, our vessels lose their eligibility to engage in coastwise trade within United States
domestic waters.
The requirements that our vessels be United States built and manned by United States citizens,
the crewing requirements and material requirements of the Coast Guard and the application of United
States labor and tax laws significantly increase the costs of United States flagged vessels when
compared with foreign flag vessels. During the past several years, certain interest groups have
lobbied Congress to repeal the Jones Act to facilitate foreign flag competition for trades and
cargoes reserved for United States flagged vessels under the Jones Act and cargo preference laws.
If the Jones Act were to be modified to permit foreign competition that would not be subject to the
same United States government imposed costs, we may need to lower the prices we charge for our
services in order to compete with foreign competitors, which would adversely affect our cash flow
and ability to make distributions to our unitholders. Following Hurricane Katrina and again after
Hurricane Rita, emergency suspensions of the Jones Act were effectuated by the United States
government. The last suspension ended on October 24, 2005. Future suspensions of the Jones Act or
other similar actions could result in similar consequences.
Our marine transportation business would be adversely affected if the United States Government
purchases or requisitions any of our vessels under the Merchant Marine Act.
We are subject to the Merchant Marine Act of 1936, which provides that, upon proclamation by
the President of the United States of a national emergency or a threat to the national security,
the United States Secretary of Transportation may requisition or purchase any vessel or other
watercraft owned by United States citizens (including us, provided that we are considered a United
States citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased
or requisitioned by the United States government under this law, we would be entitled to be paid
the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the
fair market value of charter hire. However, if one of our push boats or tugboats is requisitioned
or purchased and its associated tank barge is left idle, we would not be entitled to receive any
compensation for the lost revenues resulting from the idled barge. We also would not be entitled to
be compensated for any consequential damages we suffer as a result of the requisition or purchase
of any of our push boats, tugboats or tank barges. If any of our vessels are purchased or
requisitioned for an extended period of time by the United States government, such transactions
could have a material adverse affect on our results of operations, cash flow and ability to make
distributions to our unitholders.
Regulations affecting the domestic tank vessel industry may limit our ability to do business,
increase our costs and adversely impact our results of operations and ability to make distributions
to our unitholders.
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The U.S. Oil Pollution Act of 1990, or OPA 90, provides for the phase out of single-hull
vessels and the phase-in of the exclusive operation of double-hull tank vessels in U.S. waters for
barges that carry petroleum products that are regulated under OPA 90. Under OPA 90, substantially
all tank vessels that do not have double hulls will be phased out by 2015 and will not be permitted
to enter U.S. ports or trade in U.S. waters. The phase out dates vary based on the age of the
vessel and other factors. All but one of our offshore tank barges are double-hull vessels which
have no phase out date. We have 13 single-hull barges that will be phased out of the petroleum
product trade by the year 2015. The phase out of these single-hull vessels in accordance with OPA
90 may require us to make substantial capital expenditures, which could adversely affect our
operations and market position and reduce our cash available for distribution.
Risks Relating to Our Acquisition of Prism Gas
A decline in the volume of natural gas and NGLs delivered to our facilities could adversely affect
our results of operations, cash flows and financial condition.
Our profitability could be materially impacted by a decline in the volume of natural gas and
NGLs transported, gathered or processed at our facilities. A material decrease in natural gas
production, as a result of depressed commodity prices, a decrease in exploration and development
activities or otherwise, could result in a decline in the volume of natural gas and NGLs handled by
our facilities.
The natural gas and NGLs available to our facilities will be derived from reserves produced
from existing wells. These reserves naturally decline over time. To offset this natural decline,
our facilities will need access to additional reserves.
Our profitability is dependent upon prices and market demand for natural gas and NGLs, which are
beyond our control and have been volatile.
We are subject to significant risks due to fluctuations in commodity prices. These risks
relate primarily to: (1) the purchase of certain volumes of natural gas at a price that is a
percentage of a relevant index; and (2) certain processing contracts for Prism Gas whereby we are
exposed to natural gas and NGL commodity price risks.
The margins we realize from purchasing and selling a portion of the natural gas that we
transport through our pipeline systems decrease in periods of low natural gas prices because our
gross margins are based on a percentage of the index price. For the years ended December 31, 2006
and 2005, Prism Gas purchased approximately 40% and 54%, respectively, of our gas at a percentage
of relevant index. Accordingly, a decline in the price of natural gas could have an adverse impact
on our results of operations.
In the past, the prices of natural gas and NGLs have been extremely volatile and we expect
this volatility to continue. For example, in 2005, the spot price of Henry Hub natural gas ranged
from a high of $15.39 per MMBtu to a low of $5.50 per MMBtu. From January 1, 2006 through December
31, 2006, the same price ranged from $11.23 per MMBtu to $4.75 per MMBtu. On December 29, 2006 the
spot price was $6.30 per MMBtu.
We may not be successful in balancing our purchases and sales. In addition, a producer could
fail to deliver contracted volumes or deliver in excess of contracted volumes, or a consumer could
purchase less than contracted volumes. Any of these actions could cause our purchases and sales not
to be balanced. If our purchases and sales are not balanced, we will face increased exposure to
commodity price risks and could have increased volatility in our operating income.
The markets and prices for residue gas and NGLs depend upon factors beyond our control. These
factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and
economic conditions and other factors, including:
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the impact of weather on the demand for oil and natural gas; |
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the level of domestic oil and natural gas production; |
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the level of domestic industrial and manufacturing activity; |
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the availability of imported oil and natural gas; |
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actions taken by foreign oil and gas producing nations; |
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the availability of local, intrastate and interstate transportation systems; |
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the availability and marketing of competitive fuels; |
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the impact of energy conservation efforts; and |
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the extent of governmental regulation and taxation. |
Our hedging activities may have a material adverse effect on our earnings, profitability, cash
flows and financial condition.
As of December 31, 2006, Prism Gas has hedged approximately 60%, 45% and 14% of its commodity
risk by volume for 2007, 2008 and 2009, respectively. These hedging arrangements are in the form
of swaps for crude oil, natural gas and ethane. We anticipate entering into additional hedges in
2007 and beyond to further reduce our exposure to commodity price movements. The intent of these
arrangements is to reduce the volatility in our cash flows resulting from fluctuations in commodity
prices.
We entered into these derivative transactions with an investment grade subsidiary of a major
oil company and investment grade banks. While we anticipate that future derivative transactions
will be entered into with investment grade counterparties, and that we will actively monitor the
credit rating of such counterparties, it is nevertheless possible that losses will result from
counterparty credit risk in the future.
Management will continue to evaluate whether to enter into any new hedging arrangements, but
there can be no assurance that we will enter into any new hedging arrangements or that our future
hedging arrangements will be on terms similar to our existing hedging arrangements. Also, we may
seek in the future to further limit our exposure to changes in natural gas, NGL and condensate
commodity prices and we may seek to limit our exposure to changes in interest rates by using
financial derivative instruments and other hedging mechanisms from time to time. To the extent we
hedge our commodity price and interest rate risk, we may forego the benefits we would otherwise
experience if commodity prices or interest rates were to change in our favor.
Despite our hedging program, we remain exposed to risks associated with fluctuations in
commodity prices. The extent of our commodity price risk is related largely to the effectiveness
and scope of our hedging activities. For example, the derivative instruments we utilize are based
on posted market prices, which may differ significantly from the actual natural gas, NGL and
condensate prices that we realize in our operations. Furthermore, we have entered into derivative
transactions related to only a portion of the volume of our expected natural gas supply and
production of NGLs and condensate from our processing plants; as a result, we will continue to have
direct commodity price risk to the unhedged portion. Our actual future production may be
significantly higher or lower than we estimated at the time we entered into the derivative
transactions for that period. If the actual amount is higher than we estimated, we will have
greater commodity price risk than we intended. If the actual amount is lower than the amount that
is subject to our derivative financial instruments, we might be forced to satisfy all or a portion
of our derivative transactions without the benefit of the cash flow from our sale of the underlying
physical commodity, resulting in a reduction of our liquidity.
As a result of these factors, our hedging activities may not be as effective as we intend in
reducing the volatility of our cash flows, and in certain circumstances may actually increase the
volatility of our cash flows. In addition, even though our management monitors our hedging
activities, these activities can result in substantial losses. Such losses could occur under
various circumstances, including if a counterparty does not perform its obligations under the
applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or our hedging
policies and procedures are not properly followed or do not perform as planned. We cannot assure
our unitholders that the steps we take to monitor our hedging activities will detect and prevent
violations of our risk management policies and procedures, particularly if deception or other
intentional misconduct is involved. For additional information regarding our hedging activities,
please see Item 7A. Quantitative and Qualitative Disclosures about Market Risk Commodity Price
Risk.
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We typically do not obtain independent evaluations of natural gas reserves dedicated to our
gathering and pipeline systems; therefore, volumes of natural gas on our systems in the future
could be less than we anticipate.
We make internal evaluations of natural gas reserves based on publicly available information.
However, we typically do not obtain independent evaluations of natural gas reserves connected to
our systems due to the unwillingness of producers to provide reserve information as well as the
cost of such evaluations to verify publicly available information. Accordingly, we do not have
independent estimates of total reserves dedicated to our systems or the anticipated life of such
reserves. If the total reserves or estimated life of the reserves connected to our gathering
systems are less than we anticipate and we are unable to secure additional sources of natural gas,
then the volumes of natural gas on our systems in the future could be less than we anticipate. A
decline in the volumes of natural gas on our systems could have a material adverse effect on our
business, results of operations, financial condition and our ability to make cash distributions to
our unitholders.
We depend on certain natural gas producer customers for a significant portion of our supply of
natural gas and NGLs. The loss of any of these customers could result in a decline in our volumes,
revenues and cash available for distribution.
We rely on certain natural gas producer customers for a significant portion of our natural gas
and NGL supply. While some of these customers are subject to long-term contracts, we may be unable
to negotiate extensions or replacements of these contracts on favorable terms, if at all. The loss
of all or even a portion of the natural gas volumes supplied by these customers, as a result of
competition or otherwise, could have a material adverse effect on our business, results of
operations and financial condition, unless we were able to acquire comparable volumes from other
sources.
We may not successfully balance our purchases and sales of natural gas, which would increase our
exposure to commodity price risks.
We purchase from producers and other customers a significant amount of the natural gas that
flows through our natural gas gathering, processing and transportation systems for resale to third
parties, including natural gas marketers and end-users. We may not be successful in balancing our
purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in
excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of
these actions could cause our purchases and sales to be unbalanced. While we attempt to balance our
purchases and sales, if our purchases and sales are unbalanced, we will face increased exposure to
commodity price risks and could have increased volatility in our operating income and cash flows.
If third-party pipelines and other facilities interconnected to our natural gas and NGL pipelines
and facilities become unavailable to transport or produce natural gas and NGLs, our revenues and
cash available for distribution could be adversely affected.
We depend upon third party pipelines and other facilities that provide delivery options to and
from our pipelines and facilities for the benefit of our customers. Since we do not own or operate
any of these pipelines or other facilities, their continuing operation is not within our control.
If any of these third-party pipelines and other facilities become unavailable to transport or
produce natural gas and NGLs, our revenues and cash available for distribution could be adversely
affected.
The industry in which we operate is highly competitive, and increased competitive pressure could
adversely affect our business and operating results.
We compete with similar enterprises in our respective areas of operation. Some of our
competitors are large oil, natural gas and petrochemical companies that have greater financial
resources and access to supplies of natural gas and NGLs than we do. Some of these competitors may
expand or construct gathering, processing and transportation systems that would create additional
competition for the services we provide to our customers. In addition, our customers who are
significant producers of natural gas may develop their own gathering, processing and transportation
systems in lieu of using ours. Likewise, our customers who produce NGLs may develop their own
systems to transport NGLs in lieu of using ours. Our ability to renew or replace existing contracts
with our customers at rates sufficient to maintain current revenues and cash flows could be
adversely affected by the activities of our competitors and our customers. All of these competitive
pressures could have a material adverse effect on our business, results of operations, financial
condition and ability to make cash distributions to our unitholders.
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A change in the jurisdictional characterization of some of our assets by federal, state or local
regulatory agencies or a change in policy by those agencies may result in increased regulation of
our assets, which may cause our revenues to decline and operating expenses to increase.
We believe that our natural gas gathering operations meet the tests the Federal Energy
Regulatory Commission, or FERC, uses to establish a pipelines status as a gatherer exempt from
FERC regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still affects these
businesses and the markets for products derived from these businesses. FERCs policies and
practices across the range of its oil and natural gas regulatory activities, including, for
example, its policies on open access transportation, ratemaking, capacity release and market center
promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive
policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure
our unitholders that FERC will continue this approach as it considers matters such as pipeline
rates and rules and policies that may affect rights of access to oil and natural gas transportation
capacity. In addition, the distinction between FERC-regulated transmission services and federally
unregulated gathering services has been the subject of regular litigation, so, in such a
circumstance, the classification and regulation of some of our gathering facilities and intrastate
transportation pipelines may be subject to change based on future determinations by FERC and the
courts.
Other state and local regulations also affect our business. Our gathering lines are subject to
ratable take and common purchaser statutes in Louisiana and Texas. Ratable take statutes generally
require gatherers to take, without undue discrimination, oil or natural gas production that may be
tendered to the gatherer for handling. Similarly, common purchaser statutes generally require
gatherers to purchase without undue discrimination as to source of supply or producer. These
statutes restrict our right as an owner of gathering facilities to decide with whom we contract to
purchase or transport oil or natural gas. Federal law leaves any economic regulation of natural gas
gathering to the states. The states in which we operate have adopted complaint-based regulation of
oil and natural gas gathering activities, which allows oil and natural gas producers and shippers
to file complaints with state regulators in an effort to resolve grievances relating to oil and
natural gas gathering access and rate discrimination. Other state regulations may not directly
regulate our business, but may nonetheless affect the availability of natural gas for purchase,
processing and sale, including state regulation of production rates and maximum daily production
allowable from gas wells. While our gathering lines currently are subject to limited state
regulation, there is a risk that state laws will be changed, which may give producers a stronger
basis to challenge the rates, terms and conditions of a gathering line providing transportation
service.
Panther Interstate Pipeline Energy, LLC is also subject to regulation by FERC with respect to
issues other than ratemaking
Under the NGA, FERC has the authority to regulate natural gas companies, such as Panther
Interstate Pipeline Energy, LLC with respect to: rates, terms and conditions of service; the types
of services Panther Interstate Pipeline Energy, LLC may provide to its customers; the construction
of new facilities; the acquisition, extension, expansion or abandonment of services or facilities;
the maintenance and retention of accounts and records; and relationships of affiliated companies
involved in all aspects of the natural gas and energy business. FERCs actions in any of these
areas or modifications to its current regulations could impair Panther Interstate Pipeline Energy,
LLCs ability to compete for business, the costs it incurs to operate, or the acquisition or
construction of new facilities.
We may incur significant costs and liabilities resulting from pipeline integrity programs and
related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, the United States Department of
Transportation (DOT) has adopted regulations requiring pipeline operators to develop integrity
management programs for transportation pipelines located where a leak or rupture could do the most
harm in high consequence areas. The regulations require operators to:
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perform ongoing assessments of pipeline integrity; |
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identify and characterize applicable threats to pipeline segments that
could impact a high consequence area; |
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improve data collection, integration and analysis; |
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repair and remediate the pipeline as necessary; and |
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implement preventive and mitigating actions. |
We currently estimate that we will incur costs of less than $1.0 million between 2006 and 2010
to implement pipeline integrity management program testing along certain segments of our natural
gas and NGL pipelines. This does not include the costs, if any, of any repair, remediation,
preventative or mitigating actions that may be determined to he necessary as a result of the
testing program, which costs could be substantial.
We do not own all of the land on which our pipelines and facilities are located, which could
disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and
we are therefore subject to the possibility of more onerous terms and/or increased costs to retain
necessary land use if we do not have valid rights of way or if such rights of way lapse or
terminate. We obtain the rights to construct and operate our pipelines on land owned by third
parties and governmental agencies for a specific period of time. Our loss of these rights, through
our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on
our business, results of operations and financial condition and our ability to make cash
distributions to our unitholders.
Risks Relating to an Investment in the Common Units
Units available for future sales by us or our affiliates could have an adverse impact on the price
of our common units or on any trading market that may develop.
Martin Resource Management and its subsidiaries currently hold 2,552,018 subordinated units
and 2,632,799 common units. All of the subordinated units will convert into common units at the end
of the subordination period and some may convert earlier.
Common units will generally be freely transferable without restriction or further registration
under the Securities Act, except that any common units held by an affiliate of ours may not be
resold publicly except in compliance with the registration requirements of the Securities Act or
under an exemption under Rule 144 or otherwise.
Our partnership agreement provides that, after the subordination period, we may issue an
unlimited number of limited partner interests of any type without a vote of the unitholders. During
the subordination period, our general partner, without the approval of our unitholders, may cause
us to issue up to 1,500,000 additional common units. Our general partner may also cause us to issue
an unlimited number of additional common units or other equity securities of equal rank with the
common units, without unitholder approval, in a number of circumstances such as:
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the issuance of common units in additional public offerings or in
connection with acquisitions that increase cash flow from operations on a pro forma,
per unit basis; |
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the conversion of subordinated units into common units; |
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the conversion of units of equal rank with the common units into common
units under some circumstances; or |
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the conversion of our general partners general partner interest in us and
its incentive distribution rights into common units as a result of the withdrawal of
our general partner. |
Our partnership agreement does not restrict our ability to issue equity securities ranking
junior to the common units at any time. Any issuance of additional common units or other equity
securities would result in a corresponding decrease in the proportionate ownership interest in us
represented by, and could adversely affect the cash distributions to and market price of, common
units then outstanding.
Under our partnership agreement, our general partner and its affiliates have the right to
cause us to register under the Securities Act and applicable state securities laws the offer and
sale of any units that they hold. Subject to the terms and conditions of our partnership agreement,
these registration rights allow the general partner and its affiliates or their assignees holding
any units to require registration of any of these units and to include any of these units in a
registration by us of other units, including units offered by us or by any unitholder. Our general
partner will continue to
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have these registration rights for two years following its withdrawal or removal as a general
partner. In connection with any registration of this kind, we will indemnify each unitholder
participating in the registration and its officers, directors, and controlling persons from and
against any liabilities under the Securities Act or any applicable state securities laws arising
from the registration statement or prospectus. Except as described below, the general partner and
its affiliates may sell their units in private transactions at any time, subject to compliance with
applicable laws. Our general partner and its affiliates, with our concurrence, have granted
comparable registration rights to their bank group to which their partnership units have been
pledged.
The sale of any common or subordinated units could have an adverse impact on the price of the
common units or on any trading market that may develop.
Unitholders have less power to elect or remove management of our general partner than holders of
common stock in a corporation. Common unitholders will not have sufficient voting power to elect
or remove our general partner without the consent of Martin Resource Management.
Unlike the holders of common stock in a corporation, unitholders have only limited voting
rights on matters affecting our business and therefore limited ability to influence managements
decisions regarding our business. Unitholders did not elect our general partner or its directors
and will have no right to elect our general partner or its directors on an annual or other
continuing basis. Martin Resource Management elects the directors of our general partner. Although
our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and
our unitholders, the directors of our general partner also have a fiduciary duty to manage our
general partner in a manner beneficial to Martin Resource Management and its shareholders.
If unitholders are dissatisfied with the performance of our general partner, they will have a
limited ability to remove our general partner. Our general partner generally may not be removed
except upon the vote of the holders of at least 66 2/3% of the outstanding units voting together as
a single class. Because our general partner and its affiliates, including Martin Resource
Management, control 39.4% of our outstanding limited partnership units, our general partner
initially cannot be removed without the consent of it and its affiliates.
If our general partner is removed without cause during the subordination period and units held
by our general partner and its affiliates are not voted in favor of removal, all remaining
subordinated units will automatically be converted into common units and any existing arrearages on
the common units will be extinguished. A removal under these circumstances would adversely affect
the common units by prematurely eliminating their contractual right to distributions and
liquidation preference over the subordinated units, which preferences would otherwise have
continued until we had met certain distribution and performance tests. Cause is narrowly defined to
mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding
our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in
its capacity as our general partner. Cause does not include most cases of charges of poor
management of our business, so the removal of our general partner because of the unitholders
dissatisfaction with our general partners performance in managing our partnership will most likely
result in the termination of the subordination period.
Unitholders voting rights are further restricted by our partnership agreement provision
prohibiting any units held by a person owning 20% or more of any class of units then outstanding,
other than our general partner, its affiliates, their transferees and persons who acquired such
units with the prior approval of our general partners directors, from voting on any matter. In
addition, our partnership agreement contains provisions limiting the ability of unitholders to call
meetings or to acquire information about our operations, as well as other provisions limiting the
unitholders ability to influence the manner or direction of management.
As a result of these provisions, it will be more difficult for a third party to acquire our
partnership without first negotiating the acquisition with our general partner. Consequently, it is
unlikely the trading price of our common units will ever reflect a takeover premium.
Our general partners discretion in determining the level of our cash reserves may adversely affect
our ability to make cash distributions to our unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus cash
reserves it determines in its reasonable discretion to be necessary to fund our future operating
expenditures. In addition, our partnership agreement permits our general partner to reduce
available cash by establishing cash reserves for the proper
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conduct of our business, to comply with applicable law or agreements to which we are a party
or to provide funds for future distributions to partners. These cash reserves will affect the
amount of cash available for distribution to our unitholders.
Unitholders may not have limited liability if a court finds that we have not complied with
applicable statutes or that unitholder action constitutes control of our business.
The limitations on the liability of holders of limited partner interests for the obligations
of a limited partnership have not been clearly established in some states. The holder of one of our
common units could be held liable in some circumstances for our obligations to the same extent as a
general partner if a court were to determine that:
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we had been conducting business in any state without compliance with the
applicable limited partnership statute; or |
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the right or the exercise of the right by our unitholders as a group to
remove or replace our general partner, to approve some amendments to our partnership
agreement, or to take other action under our partnership agreement constituted
participation in the control of our business. |
Our general partner generally has unlimited liability for our obligations, such as our debts
and environmental liabilities, except for our contractual obligations that are expressly made
without recourse to our general partner. In addition, under some circumstances, a unitholder may be
liable to us for the amount of a distribution for a period of nine years from the date of the
distribution.
Our partnership agreement contains provisions that reduce the remedies available to unitholders for
actions that might otherwise constitute a breach of fiduciary duty by our general partner.
Our partnership agreement limits the liability and reduces the fiduciary duties of our general
partner to the unitholders. Our partnership agreement also restricts the remedies available to
unitholders for actions that would otherwise constitute breaches of our general partners fiduciary
duties. For example, our partnership agreement:
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permits our general partner to make a number of decisions in its sole
discretion. This entitles our general partner to consider only the interests and
factors that it desires, and it has no duty or obligation to give any consideration to
any interest of, or factors affecting, us, our affiliates or any limited partner; |
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provides that our general partner is entitled to make other decisions in
its reasonable discretion which may reduce the obligations to which our general
partner would otherwise be held; |
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generally provides that affiliated transactions and resolutions of
conflicts of interest not involving a required vote of unitholders must be fair and
reasonable to us and that, in determining whether a transaction or resolution is fair
and reasonable, our general partner may consider the interests of all parties
involved, including its own; and |
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provides that our general partner and its officers and directors will not
be liable for monetary damages to us, our limited partners or assignees for errors of
judgment or for any acts or omissions if our general partner and those other persons
acted in good faith. |
Unitholders are treated as having consented to the various actions contemplated in our
partnership agreement and conflicts of interest that might otherwise be considered a breach of
fiduciary duties under applicable state law.
We may issue additional common units without unitholder approval, which would dilute unitholder
ownership interests.
During the subordination period, our general partner, without the approval of our unitholders,
may cause us to issue up to 1,500,000 additional common units. Our general partner may also cause
us to issue an unlimited number of additional common units or other equity securities of equal rank
with the common units, without unitholder approval, in a number of circumstances such as:
- 38 -
|
|
|
the issuance of common units in additional public offerings or in
connection with acquisitions that increase cash flow from operations on a pro forma,
per unit basis; |
|
|
|
|
the conversion of subordinated units into common units; |
|
|
|
|
the conversion of units of equal rank with the common units into common
units under some circumstances; or |
|
|
|
|
the conversion of our general partners general partner interest in us and
its incentive distribution rights into common units as a result of the withdrawal of
our general partner. |
After the subordination period, we may issue an unlimited number of limited partner interests
of any type without the approval of our unitholders. Our partnership agreement does not give our
unitholders the right to approve our issuance of equity securities ranking junior to the common
units at any time.
On November 14, 2006, 850,672 of our 3,402,690 outstanding subordinated units owned by Martin
Resource Management and its subsidiaries converted into common units on a one for one basis
following our distribution of available cash on such date. Additional conversion of our
outstanding subordinated units will occur following our quarterly distributions of available cash
provided that certain distribution thresholds are met by us.
The issuance of additional common units or other equity securities of equal or senior rank
will have the following effects:
|
|
|
our unitholders proportionate ownership interest in us will decrease; |
|
|
|
|
the amount of cash available for distribution on a per unit basis may decrease; |
|
|
|
|
because a lower percentage of total outstanding units will be subordinated
units, the risk that a shortfall in the payment of the minimum quarterly distribution
will be borne by our common unitholders will increase; |
|
|
|
|
the relative voting strength of each previously outstanding unit will diminish; |
|
|
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|
the market price of the common units may decline; and |
|
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|
the ratio of taxable income to distributions may increase. |
The control of our general partner may be transferred to a third party, and that party could
replace our current management team, without unitholder consent. Additionally, if Martin Resource
Management no longer controls our general partner, amounts we owe under our credit facility may
become immediately due and payable.
Our general partner may transfer its general partner interest to a third party in a merger or
in a sale of all or substantially all of its assets without the consent of the unitholders.
Furthermore, there is no restriction in our partnership agreement on the ability of the owner of
our general partner to transfer its ownership interest in our general partner to a third party. A
new owner of our general partner could replace the directors and officers of our general partner
with its own designees and to control the decisions taken by our general partner. Martin Resource
Management and its affiliates have pledged their interests in our general partner and us to their
bank group. If, at any time, Martin Resource Management no longer controls our general partner, the
lenders under our credit facility may declare all amounts outstanding thereunder immediately due
and payable. If such event occurs, we may be required to refinance our debt on unfavorable terms,
which could negatively impact our results of operations and our ability to make distribution to our
unitholders.
Our general partner has a limited call right that may require unitholders to sell their common
units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units,
our general partner will have the right, but not the obligation, which it may assign to any of its
affiliates or to us, to acquire all, but not less than all, of the remaining common units held by
unaffiliated persons at a price not less than the then-current
- 39 -
market price. As a result, unitholders may be required to sell their common units at an
undesirable time or price and may not receive any return on their investment. Unitholders may also
incur a tax liability upon a sale of their units. No provision in our partnership agreement, or in
any other agreement we have with our general partner or Martin Resource Management, prohibits our
general partner or its affiliates from acquiring more than 80% of our common units. For additional
information about this call right and unitholders potential tax liability, please see Risk
Factors Tax Risks Tax gain or loss on the disposition of our common units could be different
than expected.
Our common units have a limited trading volume compared to other publicly traded securities.
Our common units are quoted on the NASDAQ National Market under the symbol MMLP. However,
daily trading volumes for our common units are, and may continue to be, relatively small compared
to many other securities quoted on the NASDAQ National Market. The price of our common units may,
therefore, be volatile.
Failure to achieve and maintain effective internal controls in accordance with Section 404 of the
Sarbanes-Oxley Act could have a material adverse effect on our unit price.
In order to comply with Section 404 of the Sarbanes-Oxley Act, we periodically document and
test our internal control procedures. Section 404 of the Sarbanes-Oxley Act requires annual
management assessments of the effectiveness of our internal controls over financial reporting and a
report by our independent auditors addressing these assessments. During the course of our testing
we may identify deficiencies which we may not be able to address in time to meet the deadline
imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. In addition,
if we fail to maintain the adequacy of our internal controls, as such standards are modified,
supplemented or amended from time to time, we may not be able to ensure that we can conclude on an
ongoing basis that we have effective internal controls over financial reporting in accordance with
Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal
control environment could have a material adverse effect on the price of our common units.
Risks Relating to Our Relationship with Martin Resource Management
Cash reimbursements due to Martin Resource Management may be substantial and will reduce our cash
available for distribution to our unitholders.
Under our omnibus agreement with Martin Resource Management, Martin Resource Management
provides us with corporate staff and support services on behalf of our general partner that are
substantially identical in nature and quality to the services it conducted for our business prior
to our formation. The omnibus agreement requires us to reimburse Martin Resource Management for the
costs and expenses it incurs in rendering these services, including an overhead allocation to us of
Martin Resource Managements indirect general and administrative expenses from its corporate
allocation pool. These payments may be substantial. Payments to Martin Resource Management will
reduce the amount of available cash for distribution to our unitholders.
Martin Resource Management has conflicts of interest and limited fiduciary responsibilities, which
may permit it to favor its own interests to the detriment of our unitholders.
Martin Resource Management owns an approximate 38.6% limited partnership interest in us.
Furthermore, it owns and controls our general partner, which owns a 2.0% general partner interest
and incentive distribution rights in us. Conflicts of interest may arise between Martin Resource
Management and our general partner, on the one hand, and our unitholders, on the other hand. As a
result of these conflicts, our general partner may favor its own interests and the interests of
Martin Resource Management over the interests of our unitholders. Potential conflicts of interest
between us, Martin Resource Management and our general partner could occur in many of our
day-to-day operations including, among others, the following situations:
|
|
|
Officers of Martin Resource Management who provide services to us also
devote significant time to the businesses of Martin Resource Management and are
compensated by Martin Resource Management for that time. |
|
|
|
|
Neither our partnership agreement nor any other agreement requires Martin
Resource Management to pursue a business strategy that favors us or utilizes our assets
or services. Martin Resource Managements directors and officers have a fiduciary duty
to make these decisions in the best interests |
- 40 -
|
|
|
of the shareholders of Martin Resource Management without regard to the best interests
of the unitholders. |
|
|
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|
Martin Resource Management may engage in limited competition with us. |
|
|
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|
Our general partner is allowed to take into account the interests of
parties other than us, such as Martin Resource Management, in resolving conflicts of
interest, which has the effect of reducing its fiduciary duty to our unitholders. |
|
|
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|
Under our partnership agreement, our general partner may limit its
liability and reduce its fiduciary duties, while also restricting the remedies
available to our unitholders for actions that, without the limitations and reductions,
might constitute breaches of fiduciary duty. As a result of purchasing units, our
unitholders will be treated as having consented to some actions and conflicts of
interest that, without such consent, might otherwise constitute a breach of fiduciary
or other duties under applicable state law. |
|
|
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|
Our general partner determines which costs incurred by Martin Resource
Management are reimbursable by us. |
|
|
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|
Our partnership agreement does not restrict our general partner from
causing us to pay it or its affiliates for any services rendered on terms that are fair
and reasonable to us or from entering into additional contractual arrangements with any
of these entities on our behalf. |
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|
Our general partner controls the enforcement of obligations owed to us by
Martin Resource Management. |
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|
Our general partner decides whether to retain separate counsel, accountants
or others to perform services for us. |
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The audit committee of our general partner retains our independent
auditors. |
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|
In some instances, our general partner may cause us to borrow funds to
permit us to pay cash distributions, even if the purpose or effect of the borrowing is
to make a distribution on the subordinated units, to make incentive distributions or to
accelerate the expiration of the subordination period. |
|
|
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|
Our general partner has broad discretion to establish financial reserves
for the proper conduct of our business. These reserves also will affect the amount of
cash available for distribution. Our general partner may establish reserves for
distribution on the subordinated units, but only if those reserves will not prevent us
from distributing the full minimum quarterly distribution, plus any arrearages, on the
common units for the following four quarters. |
Martin Resource Management and its affiliates may engage in limited competition with us.
Martin Resource Management and its affiliates may engage in limited competition with us. For a
discussion of the non-competition provisions of the omnibus agreement, please see Item 13. Certain
Relationships and Related Transactions Agreements Omnibus Agreement. If Martin Resource
Management does engage in competition with us, we may lose customers or business opportunities,
which could have an adverse impact on our results of operations, cash flow and ability to make
distributions to our unitholders.
Tax Risks
The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash
available for distribution to unitholders.
The anticipated after-tax economic benefit of an investment in us depends largely on our
classification as a partnership for federal income tax purposes. We have not requested, and do not
plan to request, a ruling from the IRS on this or any other matter affecting us.
- 41 -
If we were treated as a corporation for federal income tax purposes, we would pay tax on our
income at corporate rates, which is currently a maximum of 35%, and would likely pay state income
tax at various rates. Distributions to unitholders would generally be taxed again to them as
corporate distributions, and no income, gains, losses or deductions would flow through to
unitholders. Because a tax would be imposed upon us as a corporation, the cash available for
distribution to unitholders would be substantially reduced. Treatment of us as a corporation would
result in a material reduction in the anticipated cash flow and after-tax return to our unitholders
and therefore would likely result in a substantial reduction in the value of the common units.
Current law may change so as to cause us to be taxable as a corporation for federal income tax
purposes or otherwise subject us to entity-level taxation. Our partnership agreement provides that
if a law is enacted or existing law is modified or interpreted in a manner that subjects us to
taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or
local income tax purposes, then the minimum quarterly distribution amount and the target
distribution amount will be adjusted to reflect the impact of that law on us.
A successful IRS contest of the federal income tax positions we take may adversely affect the
market for our common units and the costs of any contest will be borne by our unitholders and our
general partner.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for
federal income tax purposes or any other matter affecting us. The IRS may adopt positions that
differ from our counsels conclusions. It may be necessary to resort to administrative or court
proceedings to sustain some or all of our counsels conclusions or the positions we take. A court
may not agree with some or all our counsels conclusions or the positions we take. Any contest
with the IRS may materially and adversely impact the market for our common units and the prices at
which they trade. In addition, the costs of any contest with the IRS will be borne directly or
indirectly by all of our unitholders and our general partner.
Unitholders may be required to pay taxes on income from us even if they do not receive any cash
distributions from us.
Unitholders may be required to pay federal income taxes and, in some cases, state, local and
foreign income taxes on their share of our taxable income even if they receive no cash
distributions from us. Unitholders may not receive cash distributions from us equal to their share
of our taxable income or even the tax liability that results from the taxation of their share of
our taxable income.
Tax gain or loss on the disposition of our common units could be different than expected.
If our unitholders sell their common units, they will recognize gain or loss equal to the
difference between the amount realized and their tax basis in those common units. Prior
distributions in excess of the total net taxable income unitholders were allocated for a common
unit, which decreased unitholder tax basis in that common unit, will, in effect, become taxable
income to our unitholders if the common unit is sold at a price greater than their tax basis in
that common unit, even if the price they receive is less than their original cost. A substantial
portion of the amount realized, whether or not representing gain, may be ordinary income to our
unitholders. Should the IRS successfully contest some positions we take, our unitholders could
recognize more gain on the sale of units than would be the case under those positions, without the
benefit of decreased income in prior years. In addition, if our unitholders sell their units, they
may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may
result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts
(known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of
our income allocated to organizations exempt from federal income tax, including individual
retirement accounts and other retirement plans, will be unrelated business income and will be
taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the
highest effective tax rate applicable to individuals, and non-U.S. persons will be required to file
federal income tax returns and pay tax on their share of our taxable income.
We treat a purchaser of our common units as having the same tax benefits without regard to the
sellers identity. The IRS may challenge this treatment, which could adversely affect the value of
the common units.
- 42 -
Because we cannot match transferors and transferees of common units and because of other
reasons, we have adopted depreciation positions that may not conform to all aspects of the Treasury
regulations. A successful IRS challenge to those positions could adversely affect the amount of tax
benefits available to our unitholders. It also could affect the timing of these tax benefits or the
amount of gain from the sale of common units and could have a negative impact on the value of our
common units or result in audit adjustments to our unit holders tax returns.
Unitholders may be subject to state, local and foreign taxes and return filing requirements as a
result of investing in our common units.
In addition to federal income taxes, unitholders may be subject to other taxes, such as state,
local and foreign income taxes, unincorporated business taxes and estate, inheritance, or
intangible taxes that are imposed by the various jurisdictions in which we do business or own
property. Unitholders may be required to file state, local and foreign income tax returns and pay
state and local income taxes in some or all of the various jurisdictions in which we do business or
own property and may be subject to penalties for failure to comply with those requirements. We own
property and conduct business in Alabama, Arkansas, California, Georgia, Florida, Illinois,
Louisiana, Mississippi, Texas and Utah. We may do business or own property in other states or
foreign countries in the future. It is the unitholders responsibility to file all federal, state,
local and foreign tax returns. Our counsel has not rendered an opinion on the state, local or
foreign tax consequences of an investment in our common units.
Item 1B.
Unresolved Staff Comments
None.
Item 2.
Properties
A description of our properties is contained in Item 1. Business.
We believe we have satisfactory title to our assets. Some of the easements, rights-of-way,
permits, licenses or similar documents relating to the use of the properties that have been
transferred to us in connection with our initial public offering and the assets we acquired in our
acquisitions, required the consent of third parties, which in some cases is a governmental entity.
We believe we have obtained sufficient third-party consents, permits and authorizations for the
transfer of assets necessary for us to operate our business in all material respects. With respect
to any third-party consents, permits or authorizations that have not been obtained, we believe the
failure to obtain these consents, permits or authorizations will not have a material adverse effect
on the operation of our business.
Title to our property may be subject to encumbrances, including liens in favor of our secured
lender. We believe none of these encumbrances materially detract from the value of our properties
or our interest in these properties, or materially interfere with their use in the operation of our
business.
Item 3. Legal Proceedings
From time to time, we are subject to certain legal proceedings claims and disputes that arise
in the ordinary course of our business. Although we cannot predict the outcomes of these legal
proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact
on our financial position, results of operations or liquidity.
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5. Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Our common units are traded on the NASDAQ National Market (NASDAQ) under the symbol MMLP.
As of March 1, 2007 there were approximately 33 holders of record and approximately 9,559
beneficial owners of our common units. In addition, as of that date there were 2,552,018
subordinated units representing limited partner interests outstanding. All of the subordinated
units are held by Martin Resource Management and its subsidiaries.
- 43 -
There is no established public trading market for our subordinated units. The following table
sets forth the high and low closing sale prices of our common units for the periods indicated,
based on the daily composite listing of stock transactions for the NASDAQ and cash distributions
declared per common and subordinated units during those periods:
Fiscal 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Units |
|
Distributions Declared per Unit |
Quarters Ended |
|
High |
|
Low |
|
Common |
|
Subordinated |
March 31, 2006 |
|
$ |
31.95 |
|
|
$ |
28.84 |
|
|
$ |
0.610 |
|
|
$ |
0.610 |
|
June 30, 2006 |
|
$ |
32.03 |
|
|
$ |
30.13 |
|
|
$ |
0.610 |
|
|
$ |
0.610 |
|
September 30, 2006 |
|
$ |
33.85 |
|
|
$ |
30.53 |
|
|
$ |
0.610 |
|
|
$ |
0.610 |
|
December 31, 2006 |
|
$ |
35.60 |
|
|
$ |
30.10 |
|
|
$ |
0.620 |
|
|
$ |
0.620 |
|
Fiscal 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Units |
|
Distributions Declared per Unit |
Quarters Ended |
|
High |
|
Low |
|
Common |
|
Subordinated |
March 31, 2005 |
|
$ |
34.20 |
|
|
$ |
29.03 |
|
|
$ |
0.535 |
|
|
$ |
0.535 |
|
June 30, 2005 |
|
$ |
33.99 |
|
|
$ |
30.03 |
|
|
$ |
0.550 |
|
|
$ |
0.550 |
|
September 30, 2005 |
|
$ |
34.25 |
|
|
$ |
30.19 |
|
|
$ |
0.570 |
|
|
$ |
0.570 |
|
December 31, 2005 |
|
$ |
33.04 |
|
|
$ |
29.70 |
|
|
$ |
0.610 |
|
|
$ |
0.610 |
|
On March 2, 2007, the last reported sales price of our common units as reported on the NASDAQ
was $36.50 per unit.
In connection with our formation in June 2002, we issued to our general partner a 2% general
partner interest in us in exchange for a capital contribution in the amount of $20 and issued to
Martin Resources LLC a 98% limited partner interest in the partnership in exchange for a capital
contribution in the amount of $980 in an offering exempt from registration under Section 4(2) of
the Securities Act of 1933, as amended. On November 1, 2002, in offerings exempt from registration
under Section 4(2) of the Securities Act of 1933, as amended, we (i) issued 1,543,797 subordinated
units representing limited partner interests in us (Subordinated Units) to Martin Product Sales
LLC, in connection with the contribution to us of Martin Gas Sales LLCs limited partner interests
in Martin Operating Partnership L.P. (Operating Partnership) which holds our operating assets;
(ii) issued 620,644 Subordinated Units to Midstream Fuel Service LLC, in connection with the
contribution to us of Midstream Fuel Service LLCs limited partner interests in the Operating
Partnership; (iii) issued 2,088,921 Subordinated Units to Martin Gas Marine LLC in connection with
the contribution of Martin Gas Marine LLCs limited partner interests in the Operating Partnership;
and (iv) converted a portion of the existing interest in us owned by Martin Midstream GP LLC into a
portion of its 2% general partner interest and the incentive distribution rights in us.
In connection with our public offering of 1,322,500 common units in February 2004, our general
partner contributed $0.8 million in cash to us in order to maintain its 2% general partner interest
in us.
In connection with our acquisition of Prism Gas in November, 2005, 756,480 common units were
issued to certain members of the Prism Gas management team and Martin
Resource Management. In addition our general partner contributed $0.5
million in cash to us in order to maintain its 2% general partner interest in us.
In connection with our public offering of 3,450,000 common units in January, 2006, our general
partner contributed $2.1 million in cash to us in order to maintain its 2% general partner interest
in us.
In December 2006, we issued 470,484 common units to Martin Product Sales LLC, an affiliate of
Martin Resource Management, for approximately $15.3 million, including a capital contribution of
approximately $0.3 million made by out general partner in order to maintain its 2% general partner
interest in us. This transaction was exempt from registration pursuant to either Regulation D or
Section 4(2) of the Securities Act of 1933, as amended.
On November 14, 2005, 850,672 of our 4,253,362 outstanding subordinated units owned by Martin
Resource Management and its subsidiaries converted into common units on a one-for-one basis
following our quarterly cash distribution on such date. The common units into which the
subordinated units were converted were issued in reliance on Section 3(a)(9) of the Securities Act
of 1933, as amended.
On November 14, 2006, 850,672 of our 3,402,690 outstanding subordinated units owned by Martin
Resource Management and its subsidiaries converted into common units on a one-for-one basis
following our quarterly cash distribution on such date. The common units into which the
subordinated units were converted were issued in reliance
- 44 -
on Section 3(a)(9) of the Securities Act of 1933, as amended. Additional conversions of our
outstanding subordinated units may occur in the future provided that certain distribution
thresholds provided in our partnership agreement are met by us.
Within 45 days after the end of each quarter, we will distribute all of our available cash, as
defined in our partnership agreement, to unitholders of record on the applicable record date.
During the subordination period (as described below), the common units will have the right to
receive distributions of available cash from operating surplus in an amount equal to the minimum
quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum
quarterly distribution on the common units from prior quarters, before any distributions of
available cash from operating surplus may be made on the subordinated units. Our available cash
consists generally of all cash on hand at the end of the fiscal quarter, less reserves that our
general partner determines are necessary to:
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|
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provide for the proper conduct of our business; |
|
|
|
|
comply with applicable law, any of our debt instruments, or other agreements; or |
|
|
|
|
provide funds for distributions to our unitholders and to our general
partner for any one or more of the next four quarters; |
plus all cash on hand for the quarter resulting from working capital borrowings made after the end
of the quarter on the date of determination of available cash.
Our general partner has broad discretion to establish cash reserves that it determines are
necessary or appropriate to properly conduct our business. These can include cash reserves for
future capital and maintenance expenditures, reserves to stabilize distributions of cash to the
unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply
with the terms of any of our agreements or obligations. Our distributions are effectively made 98%
to unitholders and 2% to our general partner, subject to the payment of incentive distributions to
our general partner if certain target cash distribution levels to common unitholders are achieved.
Incentive distributions to our general partner increase to 15%, 25% and 50% based on incremental
distribution thresholds as set forth in our partnership agreement.
Our ability to distribute available cash is contractually restricted by the terms of our
credit facility. Our credit facility contains covenants requiring us to maintain certain financial
ratios. We are prohibited from making any distributions to unitholders if the distribution would
cause an event of default, or an event of default is existing, under our credit facility. Please
read Item 7. Managements Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital Resources Description of Our Credit Facility.
The subordination period will extend until the first day of any quarter beginning after
September 30, 2009 in which each of the following tests are met:
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|
|
distributions of available cash from operating surplus on each of the
outstanding common units and subordinated units equaled or exceeded the minimum
quarterly distribution for each of the three consecutive, non-overlapping four-quarter
periods immediately preceding that date; |
|
|
|
|
the adjusted operating surplus as defined in the partnership agreement
generated during each of the three consecutive, non-overlapping four-quarter periods
immediately preceding that date equaled or exceeded the sum of the minimum quarterly
distributions on all of the outstanding common units and subordinated units during
those periods on a fully diluted basis and the related distribution on the 2% general
partner interest during those periods; and |
|
|
|
|
there are no arrearages in payment of the minimum quarterly distribution on
the common units. |
Upon expiration of the subordination period, each outstanding subordinated unit will convert into
one common unit and will participate pro rata with the other common units in distributions of
available cash.
The following table sets forth information regarding securities authorized for issuance under
our equity compensation plans as of December 31, 2006.
- 45 -
Equity Compensation Plan Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of securities |
|
|
Number of |
|
|
|
|
|
remaining available for |
|
|
securities to be |
|
|
|
|
|
future issuance under |
|
|
issued upon exercise |
|
Weighted-average |
|
equity compensation |
|
|
of outstanding |
|
exercise price of |
|
plans (excluding |
|
|
options, Warrants |
|
outstanding options, |
|
securities reflected in |
Plan Category |
|
and rights |
|
warrants and rights |
|
column (a)) |
|
|
(a) |
|
(b) |
|
(c) |
Equity compensation plans approved by security holders |
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Equity compensation plans not approved by security holders (1) |
|
|
0 |
|
|
$ |
0 |
|
|
|
725,000 |
|
Total |
|
|
0 |
|
|
$ |
0 |
|
|
|
725,000 |
|
|
|
|
(1) |
|
Our general partner has adopted and maintains the Martin Midstream Partners L.P. Long-Term
Incentive Plan. For a description of the material features of this plan, please see Item 11.
Executive Compensation Employee Benefit Plans Martin Midstream Partners L.P. Long-Term
Incentive Plan. |
On January 24, 2006, we issued 1,000 restricted common units to each of our three independent
directors under our long-term incentive plan. These restricted common units vest in equal
installments of 250 units on each of the four anniversaries following the grant date.
Item 6. Selected Financial Data
The following table sets forth selected financial data and other operating data of Martin
Midstream Partners L.P. and our predecessor. The financial data for the period from January 1,
2002 through November 5, 2002 are derived from the audited combined financial statements of the
assets and operations of Martin Resource Management that were contributed to us in connection with
our initial public offering in November 2002 (Martin Midstream Partners Predecessor). The
financial data for the period from November 6, 2002 through December 31, 2002, and for the years
ended December 31, 2003, 2004, 2005 and 2006 are derived from the audited consolidated financial
statements of Martin Midstream Partners L.P.
The following selected financial data are qualified by reference to and should be read in
conjunction with our Consolidated and Combined Financial Statements and Notes thereto and
Managements Discussion and Analysis of Financial Condition and Results of Operations included
elsewhere in this document.
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|
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|
|
|
|
|
|
Partnership |
|
|
Predecessor |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period From |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
November 6, |
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|
Period From |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2002 |
|
|
January 1, |
|
|
|
Year Ended |
|
|
Through |
|
|
2002 Through |
|
|
|
December 31, |
|
|
December 31, |
|
|
November 5, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 |
|
|
2002 |
|
|
|
(Dollars in thousands) |
|
Income Statement Data: |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
576,384 |
|
|
$ |
438,443 |
|
|
$ |
294,144 |
|
|
$ |
192,731 |
|
|
$ |
33,746 |
|
|
$ |
116,160 |
|
|
Cost of product sold |
|
|
459,170 |
|
|
|
351,820 |
|
|
|
229,976 |
|
|
|
150,892 |
|
|
|
26,504 |
|
|
|
84,442 |
|
Operating expenses |
|
|
65,387 |
|
|
|
46,888 |
|
|
|
34,475 |
|
|
|
21,590 |
|
|
|
3,189 |
|
|
|
17,389 |
|
Selling, general, and administrative |
|
|
10,977 |
|
|
|
8,133 |
|
|
|
6,198 |
|
|
|
4,986 |
|
|
|
656 |
|
|
|
4,662 |
|
Depreciation and amortization |
|
|
17,597 |
|
|
|
12,642 |
|
|
|
8,766 |
|
|
|
4,765 |
|
|
|
747 |
|
|
|
3,741 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
553,131 |
|
|
|
419,483 |
|
|
|
279,415 |
|
|
|
182,233 |
|
|
|
31,096 |
|
|
|
110,234 |
|
Other operating income |
|
|
3,356 |
|
|
|
|
|
|
|
|
|
|
|
589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
26,609 |
|
|
|
18,960 |
|
|
|
14,729 |
|
|
|
11,087 |
|
|
|
2,650 |
|
|
|
5,926 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated entities |
|
|
8,547 |
|
|
|
1,591 |
|
|
|
912 |
|
|
|
2,801 |
|
|
|
599 |
|
|
|
2,565 |
|
Interest expense |
|
|
(12,466 |
) |
|
|
(6,909 |
) |
|
|
(3,326 |
) |
|
|
(2,001 |
) |
|
|
(345 |
) |
|
|
(3,283 |
) |
Debt prepayment premium |
|
|
(1,160 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other, net |
|
|
713 |
|
|
|
238 |
|
|
|
11 |
|
|
|
94 |
|
|
|
5 |
|
|
|
42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
22,243 |
|
|
|
13,880 |
|
|
|
12,326 |
|
|
|
11,981 |
|
|
|
2,909 |
|
|
|
5,250 |
|
Income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,959 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
22,243 |
|
|
$ |
13,880 |
|
|
$ |
12,326 |
|
|
$ |
11,981 |
|
|
$ |
2,909 |
|
|
$ |
3,291 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit |
|
$ |
1.69 |
|
|
$ |
1.58 |
|
|
$ |
1.45 |
|
|
$ |
1.64 |
|
|
$ |
.40 |
|
|
|
|
|
Weighted average limited partner units |
|
|
12,602,000 |
|
|
|
8,583,634 |
|
|
|
8,349,551 |
|
|
|
7,153,362 |
|
|
|
7,153,362 |
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- 46 -
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Partnership |
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Predecessor |
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|
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|
|
|
|
|
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|
|
|
|
|
|
|
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Period From |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
November 6, |
|
|
Period From |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2002 |
|
|
January 1, |
|
|
|
Year Ended |
|
|
Through |
|
|
2002 Through |
|
|
|
December 31, |
|
|
December 31, |
|
|
November 5, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 |
|
|
2002 |
|
|
|
(Dollars in thousands) |
|
Balance Sheet Data (at Period End): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
457,461 |
|
|
$ |
389,044 |
|
|
$ |
188,332 |
|
|
$ |
139,685 |
|
|
$ |
100,455 |
|
|
|
|
|
Due to affiliates |
|
|
10,474 |
|
|
|
3,492 |
|
|
|
429 |
|
|
|
560 |
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
174,021 |
|
|
|
192,200 |
|
|
|
73,000 |
|
|
|
67,000 |
|
|
|
35,000 |
|
|
|
|
|
Partners capital (owners equity) |
|
|
198,525 |
|
|
|
95,565 |
|
|
|
75,534 |
|
|
|
45,892 |
|
|
|
47,106 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flow provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
|
39,317 |
|
|
|
32,334 |
|
|
|
12,812 |
|
|
$ |
10,273 |
|
|
$ |
4,824 |
|
|
$ |
316 |
|
Investing activities |
|
|
(95,098 |
) |
|
|
(138,742 |
) |
|
|
(34,322 |
) |
|
|
(27,621 |
) |
|
|
(2,116 |
) |
|
|
(1,962 |
) |
Financing activities |
|
|
52,991 |
|
|
|
109,689 |
|
|
|
22,424 |
|
|
|
17,884 |
|
|
|
(6,287 |
) |
|
|
6,897 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures |
|
|
12,391 |
|
|
|
5,100 |
|
|
|
5,182 |
|
|
|
2,773 |
|
|
|
157 |
|
|
|
394 |
|
Expansion capital expenditures |
|
|
78,267 |
|
|
|
74,110 |
|
|
|
30,234 |
|
|
|
29,159 |
|
|
|
2,850 |
|
|
|
1,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
90,658 |
|
|
$ |
79,210 |
|
|
$ |
35,416 |
|
|
$ |
31,932 |
|
|
$ |
3,007 |
|
|
$ |
2,303 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per common unit (in dollars) |
|
$ |
0.620 |
|
|
$ |
0.610 |
|
|
$ |
0.535 |
|
|
$ |
0.525 |
|
|
$ |
0.308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
References in this annual report to we, ours, us or like terms when used in a historical
context refer to the assets and operations of Martin Resource Managements business contributed to
us in connection with our initial public offering on November 6, 2002. References in this annual
report to Martin Resource Management refers to Martin Resource Management Corporation and its
subsidiaries, unless the context otherwise requires. You should read the following discussion of
our financial condition and results of operations in conjunction with the consolidated financial
statements and the notes thereto included elsewhere in this annual report. For more detailed
information regarding the basis for presentation for the following information, you should read the
notes to the consolidated financial statements included elsewhere in this annual report.
Forward-Looking Statements
This annual report on Form 10-K includes forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended. Statements included in this annual report that are not historical facts
(including any statements concerning plans and objectives of management for future operations or
economic performance, or assumptions or forecasts related thereto), are forward-looking statements.
These statements can be identified by the use of forward-looking terminology including forecast,
may, believe, will, expect, anticipate, estimate, continue or other similar words.
These statements discuss future expectations, contain projections of results of operations or of
financial condition or state other forward-looking information. We and our representatives may
from time to time make other oral or written statements that are also forward-looking statements.
These forward-looking statements are made based upon managements current plans, expectations,
estimates, assumptions and beliefs concerning future events impacting us and therefore involve a
number of risks and uncertainties. We caution that forward-looking statements are not guarantees
and that actual results could differ materially from those expressed or implied in the
forward-looking statements.
Because these forward-looking statements involve risks and uncertainties, actual results could
differ materially from those expressed or implied by these forward-looking statements for a number
of important reasons, including those discussed above in Item 1A. Risk Factors Risks Related to
our Business.
Overview
We are a publicly traded limited partnership with a diverse set of operations focused
primarily in the United States Gulf Coast region. Our five primary business lines include:
- 47 -
|
|
|
Terminalling and storage services for petroleum products and by-products |
|
|
|
|
Natural gas services |
|
|
|
|
Marine transportation services for petroleum products and by-products |
|
|
|
|
Sulfur gathering, processing and distribution |
|
|
|
|
Fertilizer manufacturing and distribution |
The petroleum products and by-products we collect, transport, store and distribute are
produced primarily by major and independent oil and gas companies who often turn to third parties,
such as us, for the transportation and disposition of these products. In addition to these major
and independent oil and gas companies, our primary customers include independent refiners, large
chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. We
operate primarily in the Gulf Coast region of the United States. This region is a major hub for
petroleum refining, natural gas gathering and processing and support services to the exploration
and production industry.
2006 Developments and Subsequent Events
Recent Acquisitions
Acquisition of the La Force Marine Vessel. In November 2006, we acquired the La Force, an
offshore tug, for $6.0 million from a third party. This vessel is a 5,100 horse power offshore tug
that was rebuilt in 1999 with new engines installed in 2005. The addition of the La Force to our
fleet will eliminate the need for chartered offshore horsepower.
Acquisition of Asphalt Terminals. In August 2006 and October 2006, respectively, we acquired
the assets of Gulf States Asphalt Company LP and Prime Materials and Supply Corporation for $4.9
million. These assets are located in Houston, Texas and Port Neches, Texas. In connection with
these acquisitions, we entered into an agreement with Martin Resource Management, whereby Martin
Resource Management will operate the acquired facilities through a terminalling service agreement
based upon throughput rates and will assume all additional expenses to operate the facilities.
Acquisition of the Corpus Christi Barge Terminal. In July 2006, we acquired a marine terminal
located near Corpus Christi, Texas and associated assets from Koch Pipeline Company, LP for $6.2
million, which was all allocated to property, plant and equipment. The terminal is located on
approximately 25 acres of land and includes three tanks with a combined shell capacity of
approximately 240,000 barrels, pump and piping infrastructure for truck unloading and product
delivery to two oil docks.
Acquisition of the Texan, Ponciana and M450. In January 2006, we acquired the Texan, an
offshore tug, and the Ponciana, an offshore NGL barge, for $5.9 million from Martin Resource
Management. In February 2006 we acquired the M450, an offshore barge, for $1.6 million from a
third party.
Other Developments
Increased Quarterly Distribution. We declared a quarterly cash distribution for the fourth
quarter of 2006 of $0.62 per common and subordinated unit on January 22, 2007, reflecting an
increase of $0.01 per unit over the quarterly distribution paid in respect of the third quarter of
2006.
Issuance of Common Units. In December 2006, we issued 470,484 common units to Martin Product
Sales LLC, an affiliate of Martin Resource Management, for approximately $15.3 million, including a
capital contribution of approximately $0.3 million made by our general partner to maintain its 2%
general partner interest in us. These funds were used to pay down our revolving line of credit.
Conversion of Subordinated Units. On November 14, 2006, 850,672 of our 3,402,690 outstanding
subordinated units owned by Martin Resource Management and its subsidiaries converted into common
units on a one-for-one basis following our quarterly cash distribution on such date. Additional
conversions of our outstanding
- 48 -
subordinated units may occur in the future provided that certain distribution thresholds
contained in our partnership agreement are met by us.
Public Offering. In January 2006, we completed a follow-on public offering of 3,450,000
common units, resulting in proceeds of $95.4 million, after payment of underwriters discounts,
commissions and offering expenses. Our general partner contributed $2.1 million in cash to us in
conjunction with the offering in order to maintain its 2% general partner interest in us. Of the
net proceeds, $62.0 million was used to pay then current balances under our revolving credit
facility and $7.5 million was used to fund a portion of the redemption price for our U.S.
Government Guaranteed Ship Financing Bonds. The remainder of the net proceeds has been or will be
used to fund future organic growth projects.
Critical Accounting Policies
Our discussion and analysis of our financial condition and results of operations are based on
the historical consolidated financial statements included elsewhere herein. We prepared these
financial statements in conformity with generally accepted accounting principles. The preparation
of these financial statements required us to make estimates and assumptions that affect the
reported amounts of assets and liabilities at the dates of the financial statements and the
reported amounts of revenues and expenses during the reporting periods. We based our estimates on
historical experience and on various other assumptions we believe to be reasonable under the
circumstances. Our results may differ from these estimates. Currently, we believe that our
accounting policies do not require us to make estimates using assumptions about matters that are
highly uncertain. However, we have described below the critical accounting policies that we
believe could impact our consolidated financial statements most significantly.
You should also read Note 2, Significant Accounting Policies in Notes to Consolidated
Financial Statements contained in this annual report on Form 10-K. Some of the more significant
estimates in these financial statements include the amount of the allowance for doubtful accounts
receivable and the determination of the fair value of our reporting units under the Financial
Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 142,
Goodwill and Other Intangible Assets.
Derivatives
In accordance with Statement of Financial Accounting Standards No. 133 (SFAS No. 133),
Accounting for Derivative Instruments and Hedging Activities, all derivatives and hedging
instruments are included on the balance sheet as an asset or liability measured at fair value and
changes in fair value are recognized currently in earnings unless specific hedge accounting
criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be
offset against the change in the fair value of the hedged item through earnings or recognized in
other comprehensive income until such time as the hedged item is recognized in earnings. In early
2006, we adopted a hedging policy that allows us to use hedge accounting for financial transactions
that are designated as hedges. Derivative instruments not designated as hedges are being marked to
market with all market value adjustments being recorded in the consolidated statements of
operations. As of December 31, 2006, we had designated a portion of our derivative instruments as
qualifying cash flow hedges. Fair value changes for these hedges have been recorded in other
comprehensive income as a component of equity.
Product Exchanges
We enter into product exchange agreements with third parties whereby we agree to exchange NGLs
with third parties. We record the balance of NGLs due to other companies under these agreements at
quoted market product prices and the balance of NGLs due from other companies at the lower of cost
or market. Cost is determined using the first-in, first-out method.
In September 2005, the FASBs Emerging Issues Task Force (EITF) issued EITF No. 04-13,
Accounting for Purchases and Sales of Inventory with the Same Counterparty. This pronouncement
provides additional accounting guidance for situations involving inventory exchanges between
parties to that contained in APB Opinion No. 29, Accounting for Nonmonetary Transactions and SFAS
153, Exchanges of Nonmonetary Assets. The standard is effective for new arrangements entered into
in reporting periods beginning after March 15, 2006. The adoption did not have a material impact
on our financial statements.
- 49 -
Revenue Recognition
Revenue for our five operating segments is recognized as follows:
Terminalling and storage - Revenue is recognized for storage contracts based on the contracted
monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved
through our terminals at the contracted rate. When lubricants and drilling fluids are sold by
truck, revenue is recognized upon delivering product to the customers as title to the product
transfers when the customer physically receives the product.
Natural gas services - Natural gas gathering and processing revenues are recognized when title
passes or service is performed. LPG distribution revenue is recognized when product is delivered
by truck to our LPG customers, which occurs when the customer physically receives the product. When
product is sold in storage, or by pipeline, we recognize LPG distribution revenue when the customer
receives the product from either the storage facility or pipeline.
Marine transportation - Revenue is recognized for contracted trips upon completion of the
particular trip. For time charters, revenue is recognized based on a per day rate.
Sulfur and Fertilizer - Revenue is recognized when the customer takes title to the product,
either at our plant or the customer facility.
Equity Method Investments
We use the equity method of accounting for investments in unconsolidated entities where the
ability to exercise significant influence over such entities exists. Investments in unconsolidated
entities consist of capital contributions and advances plus our share of accumulated earnings as of
the entities latest fiscal year-ends, less capital withdrawals and distributions. Investments in
excess of the underlying net assets of equity method investees, specifically identifiable to
property, plant and equipment, are amortized over the useful life of the related assets. Excess
investment representing equity method goodwill is not amortized but is evaluated for impairment,
annually. Under the provisions of Statement of Financial Accounting Standards (SFAS) No. 142,
Goodwill and Other Intangible Assets, this goodwill is not subject to amortization and is accounted
for as a component of the investment. Equity method investments are subject to impairment under
the provisions of Accounting Principles Board (APB) Opinion No. 18, The Equity Method of
Accounting for Investments in Common Stock. No portion of the net income from these entities is
included in our operating income.
Prior to July 15, 2005, we used the equity method of accounting for our unconsolidated
non-controlling 49.5% limited partner interest in CF Martin Sulphur. On July 15, 2005, we acquired
the remaining interests in CF Martin Sulphur not previously owned by us. Subsequent to the
acquisition, CF Martin Sulphur is included in the consolidated financial presentation of our sulfur
segment
Following our acquisition of Prism Gas Systems I, L.P. (Prism Gas) in November 2005, we own
an unconsolidated 50% interest in Waskom Gas Processing Company (Waskom), the Matagorda Offshore
Gathering System (Matagorda), and Panther Interstate Pipeline Energy LLC (PIPE). As a result,
these assets are accounted for by the equity method and we do not include any portion of their net
income in operating income.
On June 30, 2006, we, through our Prism Gas subsidiary, acquired a 20% ownership interest in a
partnership which owns the lease rights to the assets of the Bosque County Pipeline (BCP). This
interest is accounted for by the equity method of accounting.
Goodwill
Goodwill is subject to a fair-value based impairment test on an annual basis. We are required
to identify our reporting units and determine the carrying value of each reporting unit by
assigning the assets and liabilities, including the existing goodwill and intangible assets. We are
required to determine the fair value of each reporting unit and compare it to the carrying amount
of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value
of the reporting unit, we would be required to perform the second step of the impairment test, as
this is an indication that the reporting unit goodwill may be impaired.
- 50 -
We have performed the annual impairment tests as of September 30, 2006, September 30, 2005 and
September 30, 2004, respectively. In performing such tests, we determined we had four reporting
units which contained goodwill. These reporting units were four of our reporting segments: natural
gas services, marine transportation, sulfur and fertilizer.
We determined fair value in each reporting unit based on a multiple of current annual cash
flows. We determined such multiple from our recent experience with actual acquisitions and
dispositions and valuing potential acquisitions and dispositions.
Environmental Liabilities
We have historically not experienced circumstances requiring us to account for environmental
remediation obligations. If such circumstances arise, we would estimate remediation obligations
utilizing a remediation feasibility study and any other related environmental studies that we may
elect to perform. We would record changes to our estimated environmental liability as circumstances
change or events occur, such as the issuance of revised orders by governmental bodies or court or
other judicial orders and our evaluation of the likelihood and amount of the related eventual
liability.
Allowance for Doubtful Accounts
In evaluating the collectibility of our accounts receivable, we assess a number of factors,
including a specific customers ability to meet its financial obligations to us, the length of time
the receivable has been past due and historical collection experience. Based on these assessments,
we record both specific and general reserves for bad debts to reduce the related receivable to the
amount we ultimately expect to collect from customers.
Asset Retirement Obligation
In accordance with SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS 143),
we recognize and measure our asset retirement obligations and the associated asset retirement cost
upon acquisition of the related asset. Subsequent measurement and accounting provisions are in
accordance with SFAS 143.
On March 31, 2005, the Financial Accounting Standards Board issued Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of SFAS
143. FIN 47, which was effective for fiscal years ending after December 15, 2005, clarifies that
the recognition and measurement provisions of SFAS 143 apply to asset retirement obligations in
which the timing or method of settlement may be conditional on a future event that may or may not
be within the control of the entity. We have recognized asset retirement obligations, where
appropriate.
Reclassifications
As previously reported in our Quarterly Report on Form 10-Q for the three months ended
September 30, 2005, which was filed with the SEC on November 9, 2005, we converted to a new
accounting system in August 2005. In connection with the system conversion, we closely examined
expense classifications under the new system. Upon review, it was determined that certain payroll,
property insurance and property tax expenses that were previously categorized as selling, general
and administrative expenses would be more appropriately classified as operating expenses or costs
of products sold. As a result, those expenses were set up in the new system with the new
classification. Accordingly, it is necessary for us to reclassify the related expense items for
fiscal years 2002, 2003 and 2004. Since the reclassifications, as indicated in the tables set
forth below, had no impact on the prior periods revenues, operating income, cash flows from
operations or net income, we have determined that the reclassifications are not material to our
audited financial statements for the prior periods. Nonetheless, we are effecting the
reclassifications for prior periods in order to provide comparative clarity and consistency among
the 2002-2004 annual periods when compared to our financial reporting for our current 2006 fiscal
year.
The following tables set forth the effects of the reclassifications on certain line items
within our previously reported consolidated statements of income for the years ended December 31,
2004, 2003, and 2002 (dollars in thousands), which statements of income and certain relevant
footnotes thereto as well as the relevant portions of Managements Discussion and Analysis of
Financial Condition and Results of Operations for those periods have been updated.
- 51 -
(In Thousands)
Year Ended December 31, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling |
|
|
|
|
|
|
|
|
|
|
|
|
and Storage |
|
NGL |
|
Marine |
|
Fertilizer |
|
Sulfur |
|
Total |
Cost of products sold (as previously
reported) |
|
$ |
6,775 |
|
|
$ |
197,859 |
|
|
$ |
|
|
|
$ |
25,207 |
|
|
$ |
|
|
|
$ |
229,841 |
|
Cost of products sold (as
reclassified) |
|
|
6,775 |
|
|
|
197,859 |
|
|
|
|
|
|
|
25,342 |
|
|
|
|
|
|
|
229,976 |
|
Operating expenses (as previously
reported) |
|
|
6,699 |
|
|
|
928 |
|
|
|
24,796 |
|
|
|
|
|
|
|
|
|
|
|
32,423 |
|
Operating expenses (as reclassified) |
|
|
8,494 |
|
|
|
1,185 |
|
|
|
24,796 |
|
|
|
|
|
|
|
|
|
|
|
34,475 |
|
Selling, general and administrative (as
previously reported) |
|
|
2,194 |
|
|
|
1,457 |
|
|
|
175 |
|
|
|
1,793 |
|
|
|
2,766 |
|
|
|
8,385 |
|
Selling, general and administrative (as
reclassified) |
|
|
399 |
|
|
|
1,200 |
|
|
|
175 |
|
|
|
1,658 |
|
|
|
2,766 |
|
|
|
6,198 |
|
Year Ended December 31, 2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling |
|
|
|
|
|
|
|
|
|
|
|
|
and Storage |
|
NGL |
|
Marine |
|
Fertilizer |
|
Sulfur |
|
Total |
Cost of products sold (as previously
reported) |
|
$ |
107 |
|
|
$ |
128,055 |
|
|
$ |
|
|
|
$ |
22,605 |
|
|
$ |
|
|
|
$ |
150,767 |
|
Cost of products sold (as
reclassified) |
|
|
107 |
|
|
|
128,055 |
|
|
|
|
|
|
|
22,730 |
|
|
|
|
|
|
|
150,892 |
|
Operating expenses (as previously
reported) |
|
|
1,413 |
|
|
|
1,052 |
|
|
|
18,135 |
|
|
|
|
|
|
|
|
|
|
|
20,600 |
|
Operating expenses (as reclassified) |
|
|
2,141 |
|
|
|
1,314 |
|
|
|
18,135 |
|
|
|
|
|
|
|
|
|
|
|
21,590 |
|
Selling, general and administrative (as
previously reported) |
|
|
1,180 |
|
|
|
1,362 |
|
|
|
305 |
|
|
|
1,566 |
|
|
|
1,688 |
|
|
|
6,101 |
|
Selling, general and administrative (as
reclassified) |
|
|
452 |
|
|
|
1,100 |
|
|
|
305 |
|
|
|
1,441 |
|
|
|
1,688 |
|
|
|
4,986 |
|
Year Ended December 31, 2002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidating |
|
|
|
|
and Storage |
|
NGL |
|
Marine |
|
Fertilizer |
|
Sulfur |
|
Reclassification |
|
Total |
Cost of products sold (as
previously reported) |
|
$ |
|
|
|
$ |
87,189 |
|
|
$ |
|
|
|
$ |
23,324 |
|
|
$ |
|
|
|
$ |
(5 |
) |
|
$ |
110,508 |
|
Cost of products sold (as
reclassified) |
|
|
|
|
|
|
87,189 |
|
|
|
|
|
|
|
23,762 |
|
|
|
|
|
|
|
(5 |
) |
|
|
110,946 |
|
Operating expenses (as
previously reported) |
|
|
1,181 |
|
|
|
1,307 |
|
|
|
17,201 |
|
|
|
|
|
|
|
|
|
|
|
21 |
|
|
|
19,710 |
|
Operating expenses (as
reclassified) |
|
|
1,724 |
|
|
|
1,632 |
|
|
|
17,201 |
|
|
|
|
|
|
|
|
|
|
|
21 |
|
|
|
20,578 |
|
Selling, general and
administrative (as
previously reported) |
|
|
1,266 |
|
|
|
1,365 |
|
|
|
524 |
|
|
|
2,474 |
|
|
|
1,011 |
|
|
|
(16 |
) |
|
|
6,624 |
|
Selling, general and
administrative (as
reclassified) |
|
|
723 |
|
|
|
1,040 |
|
|
|
524 |
|
|
|
2,036 |
|
|
|
1,011 |
|
|
|
(16 |
) |
|
|
5,318 |
|
Our Relationship with Martin Resource Management
Martin Resource Management directs our business operations through its ownership and control
of our general partner and under an omnibus agreement. Under the omnibus agreement, we are required
to reimburse Martin Resource Management for the provision of general and administrative services
under our partnership agreement, provided that the reimbursement amount with respect to indirect
general and administrative and corporate overhead expenses was capped at $2.0 million for the
period ending October 31, 2006. Subsequently, this amount may be increased by no more than the
percentage increase in the consumer price index. In addition, Martin Resource Management and us
can agree, subject to approval of the Conflicts Committee of our general partner, to adjust this
amount for expansions of our operations and acquisitions. As of March 5, 2007, we have not
increased this cap. This
- 52 -
limitation does not apply to the cost of any third party legal, accounting or advisory
services received, or the direct expenses of Martin Resource Management incurred, in connection
with acquisition or business development opportunities evaluated on our behalf. We are required to
reimburse Martin Resource Management for all direct and indirect expenses it incurs or payments it
makes on our behalf or in connection with the operation of our business. Martin Resource
Management also licenses certain of its trademarks and trade names to us under this omnibus
agreement.
We are both an important supplier to and customer of Martin Resource Management. Among other
things, we provide marine transportation and terminalling and storage services to Martin Resource
Management. We purchase land transportation services, underground storage services, sulfuric acid
and marine fuel from Martin Resource Management. Additionally, we have exclusive access to and use
of a truck loading and unloading terminal and pipeline distribution system owned by Martin Resource
Management at Mont Belvieu, Texas. All of these services and goods are purchased and sold pursuant
to the terms of a number of agreements between us and Martin Resource Management.
For a more comprehensive discussion concerning the omnibus agreement and the other agreements
that we have entered into with Martin Resource Management, please see Item 13. Certain
Relationships and Related Transactions Agreements.
Our Relationship with CF Martin Sulphur, L.P.
On July 15, 2005, we acquired all of the remaining limited partnership interests in CF Martin
Sulphur from CF Industries, Inc. and certain affiliates of Martin Resource Management. Prior to
this transaction, our unconsolidated non-controlling 49.5% limited partnership interest in CF
Martin Sulphur, was accounted for using the equity method of accounting. In addition, on July 15,
2005, we acquired all of the outstanding membership interests in CF Martin Sulphurs general
partner. Subsequent to the acquisition, CF Martin Sulphur was a wholly owned partnership which is
included in the consolidated financial presentation of our sulfur segment. Effective March 30,
2006, CF Martin Sulphur was merged into us.
Prior to July 15, 2005, we were both an important supplier to and customer of CF Martin
Sulphur. We chartered one of our offshore tug/barge tanker units to CF Martin Sulphur for a
guaranteed daily rate, subject to certain adjustments. This charter, which had an unlimited term,
was terminated on November 18, 2005. CF Martin Sulphur paid to have this tug/barge tanker unit
reconfigured to carry molten sulfur. In the event CF Martin Sulphur had terminated this charter
agreement, we would have been obligated to reimburse CF Martin Sulphur for a portion of such
reconfiguration costs. As a result of the July 15, 2005 acquisition of all the outstanding
interests in CF Martin Sulphur, this contingent obligation was terminated.
Results of Operations
The results of operations for the years ended December 31, 2006, 2005 and 2004 have been
derived from the consolidated financial statements of Martin Midstream Partners L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
24,182 |
|
|
$ |
23,081 |
|
|
$ |
17,919 |
|
Marine transportation |
|
|
47,835 |
|
|
|
35,451 |
|
|
|
34,780 |
|
Product sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas services |
|
|
389,735 |
|
|
|
301,676 |
|
|
|
203,427 |
|
Sulfur |
|
|
61,271 |
|
|
|
36,784 |
|
|
|
|
|
Fertilizer |
|
|
41,326 |
|
|
|
31,634 |
|
|
|
29,780 |
|
Terminalling and storage |
|
|
12,035 |
|
|
|
9,817 |
|
|
|
8,238 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
576,384 |
|
|
|
438,443 |
|
|
|
294,144 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas services |
|
|
374,218 |
|
|
|
291,109 |
|
|
|
197,859 |
|
- 53 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(In thousands) |
|
Sulfur |
|
|
38,898 |
|
|
|
25,657 |
|
|
|
|
|
Fertilizer |
|
|
36,267 |
|
|
|
26,975 |
|
|
|
25,342 |
|
Terminalling and storage |
|
|
9,787 |
|
|
|
8,079 |
|
|
|
6,775 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
459,170 |
|
|
|
351,820 |
|
|
|
229,976 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
65,387 |
|
|
|
46,888 |
|
|
|
34,475 |
|
Selling, general and administrative |
|
|
10,977 |
|
|
|
8,133 |
|
|
|
6,198 |
|
Depreciation and amortization |
|
|
17,597 |
|
|
|
12,642 |
|
|
|
8,766 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
553,131 |
|
|
|
419,483 |
|
|
|
279,415 |
|
|
|
|
|
|
|
|
|
|
|
Other operating income |
|
|
3,356 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
26,609 |
|
|
|
18,960 |
|
|
|
14,729 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated entities |
|
|
8,547 |
|
|
|
1,591 |
|
|
|
912 |
|
Interest expense |
|
|
(12,466 |
) |
|
|
(6,909 |
) |
|
|
(3,326 |
) |
Debt prepayment premium |
|
|
(1,160 |
) |
|
|
|
|
|
|
|
|
Other, net |
|
|
713 |
|
|
|
238 |
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense) |
|
|
(4,366 |
) |
|
|
(5,080 |
) |
|
|
(2,403 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
22,243 |
|
|
$ |
13,880 |
|
|
$ |
12,326 |
|
|
|
|
|
|
|
|
|
|
|
We evaluate segment performance on the basis of operating income, which is derived by
subtracting cost of products sold, operating expenses, selling, general and administrative
expenses, and depreciation and amortization expense from revenues. The following table sets forth
our operating income by segment, and equity in earnings of unconsolidated entities, for the years
ended December 31, 2006, 2005, and 2004.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(In thousands) |
|
Operating income: |
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
12,504 |
|
|
$ |
9,314 |
|
|
$ |
6,749 |
|
Natural gas services |
|
|
4,239 |
|
|
|
6,003 |
|
|
|
3,080 |
|
Marine transportation |
|
|
6,411 |
|
|
|
2,384 |
|
|
|
5,827 |
|
Sulfur |
|
|
4,864 |
|
|
|
2,937 |
|
|
|
|
|
Fertilizer |
|
|
1,844 |
|
|
|
1,785 |
|
|
|
1,839 |
|
Indirect selling, general, and administrative expenses |
|
|
(3,253 |
) |
|
|
(3,463 |
) |
|
|
(2,766 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
26,609 |
|
|
$ |
18,960 |
|
|
$ |
14,729 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated entities |
|
$ |
8,547 |
|
|
$ |
1,591 |
|
|
$ |
912 |
|
|
|
|
|
|
|
|
|
|
|
Our results of operations are discussed on a comparative basis below. We discuss items we do
not allocate on a segment basis, such as equity in earnings of unconsolidated entities, interest
expense, and indirect selling, general and administrative expenses, after the comparative
discussion of our results within each segment.
Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005
Our total revenues were $576.4 million for the year ended December 31, 2006 compared to $438.4
million for the year ended December 31, 2005, an increase of $138.0 million, or 31%. Our cost of
products sold was $459.2 million for the year ended December 31, 2006 compared to $351.8 million
for the year ended December 31, 2005, an increase of $107.4 million, or 31%. Our total operating
expenses were $65.4 million for the year ended December 31, 2006 compared to $46.9 million for the
year ended December 31, 2005, an increase of $18.5 million, or 39%.
Our total selling, general and administrative expenses were $11.0 million for the year ended
December 31, 2006 compared to $8.1 million for the year ended December 31, 2005, an increase of
$2.9 million, or 36%. Total depreciation and amortization was $17.6 million for the year ended
December 31, 2006 compared to $12.6 million for the year ended December 31, 2005, an increase of
$5.0 million, or 40%. Our other operating income for the year ended
- 54 -
December 31, 2006 was $3.4 million compared to zero for the year ended December 31, 2005. Our
total operating income was $26.6 million for the year ended December 31, 2006 compared to $19.0
million for the year ended December 31, 2005, an increase of $7.6 million, or 40%.
The results of operations are described in greater detail on a segment basis below.
Terminalling and Storage Segment
The following table summarizes our results of operations in our terminalling and storage
segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
Services |
|
$ |
24,182 |
|
|
$ |
23,081 |
|
Products |
|
|
12,035 |
|
|
|
9,817 |
|
|
|
|
|
|
|
|
Total Revenues |
|
|
36,217 |
|
|
|
32,898 |
|
Cost of products sold |
|
|
9,787 |
|
|
|
8,079 |
|
Operating expenses |
|
|
12,241 |
|
|
|
10,879 |
|
Selling, general and administrative expenses |
|
|
112 |
|
|
|
250 |
|
Depreciation and amortization |
|
|
4,700 |
|
|
|
4,376 |
|
|
|
|
|
|
|
|
|
|
|
9,377 |
|
|
|
9,314 |
|
|
|
|
|
|
|
|
Other operating income |
|
|
3,127 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
12,504 |
|
|
$ |
9,314 |
|
|
|
|
|
|
|
|
Revenues. Our terminalling and storage revenues increased $3.3 million, or 10%, for the year
ended December 31, 2006 compared to the year ended December 31, 2005. Service revenue accounted
for $1.1 million of this increase. The service revenue increase was primarily a result of
acquisitions of our Corpus Christi terminal, and two asphalt terminals. Product revenue increased
$2.2 million due to an 18% increase in product cost that was passed through to our customers, and a
5% increase in sales volume.
Cost of products sold. Our cost of products sold increased $1.7 million, or 21% for the year
ended December 31, 2006 compared to the year ended December 31, 2005. This increase was primarily
a result of a 18% increase in product cost, and a 5% increase in sales volumes.
Operating expenses. Operating expenses increased $1.4 million, or 13%, for the year ended
December 31, 2006 compared to the year ended December 31, 2005. The increase was result of our
recent acquisitions made in 2006, and also a result of increased operating activities and an
increase in costs of those activities at our terminals. This accounted for $1.9 million of
increased operating expenses, which was offset by a decrease in hurricane expenses of $0.5 million.
Selling, general and administrative expenses. Selling, general and administrative expenses
decreased $0.1 million, or 55%, for the year ended December 31, 2006 compared to the year ended
December 31, 2005.
Depreciation and amortization. Depreciation and amortization increased $0.3 million, or 7%,
for the year ended December 31, 2006 compared to the year ended December 31, 2005. This increase
was primarily a result of our recent acquisitions.
Other operating income. Other operating income for the year ended December 31, 2006
consisted primarily of a gain of $3.1 million related to an involuntary conversion of assets. This
gain resulted from insurance proceeds which were greater than the impairment of assets destroyed by
hurricanes Katrina and Rita.
In summary, terminalling and storage operating income increased $3.2 million, or 34%, for the
year ended December 31, 2006 compared to the year ended December 31, 2005.
Natural Gas Services Segment
The following table summarizes our results of operations in our natural gas services segment.
- 55 -
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
389,735 |
|
|
$ |
301,676 |
|
Cost of products sold |
|
|
374,218 |
|
|
|
291,109 |
|
Operating expenses |
|
|
5,240 |
|
|
|
2,455 |
|
Selling, general and administrative expenses |
|
|
4,373 |
|
|
|
1,753 |
|
Depreciation and amortization |
|
|
1,667 |
|
|
|
356 |
|
|
|
|
|
|
|
|
|
|
|
4,237 |
|
|
|
6,003 |
|
|
|
|
|
|
|
|
Other operating income |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
4,239 |
|
|
$ |
6,003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in Earnings of Unconsolidated Entities |
|
$ |
8,547 |
|
|
$ |
1,369 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL Volumes (gallons) |
|
|
322,904 |
|
|
|
270,524 |
|
Revenues. Our natural gas services revenues increased $88.1 million, or 29%, for the year
ended December 31, 2006 compared to the year ended December 31, 2005. Of the increase, $21.2
million is related to sales in our historical NGL distribution segment. The increase is primarily
due from a 10% increase in our average sales price per gallon in 2006 compared to 2005. This price
increase was due to general increase in the prices of NGLs. Our sales volume in this historical
NGL distribution segment was approximately the same for both years.
The remaining $66.9 million increase is related to our acquisition of Prism Gas, as we
experienced a full year of operations. These revenues are comprised of $54.2 million of NGL sales,
$10.5 million of natural gas sales and $1.6 million of gathering and processing fees. Also,
included in the revenue increase was $0.6 million of gains on derivative contracts.
Costs of product sold. Our cost of products increased $83.1 million, or 29%, for the year
ended December 31, 2006 compared to the year ended December 31, 2005. Of the increase, $21.9
million is related to costs in our historical NGL distribution segment. This increase was higher
than the increase in our historical NGL revenues, as our per gallon margin decreased by 5%. In
2005, our historical NGL distribution segment benefited from extraordinary market conditions due to
Gulf Coast hurricanes. This change in market conditions resulted in a rapid increase in NGL prices
allowing us to surpass our historical NGL margins of approximately $0.025 per gallon and experience
a margin of approximately $0.04 per gallon. For 2006, in our historical NGL segment, we
experienced margins of approximately $.03 per gallon. The balance of the increase of $61.2 million
relates to costs resulting from our Prism Gas acquisition, as we experienced a full year of
operations.
Operating expenses. Operating expenses increased $2.8 million, or 115%, for the year ended
December 31, 2006 compared to the year ended December 31, 2005. An increase of $1.9 million
resulted from the Prism Gas acquisition, and $0.9 million was a result of additional operating
expenses incurred from the East Texas Pipeline acquisition. Both of these acquisitions occurred in
2005.
Selling, general and administrative expenses. Selling, general and administrative expenses
increased $2.6 million, or 149%, for the year ended December 31, 2006 compared to the year ended
December 31, 2005. An increase of $2.3 million was a result of additional expenses incurred from
the Prism Gas acquisition, as we experienced a full year of operations. The remaining increase was
a result of increased selling, general, and administrative expenses in our historical NGL
distribution segment.
Depreciation and amortization. Depreciation and amortization increased $1.3 million, or 368%,
for the year ended December 31, 2006 compared to the year ended December 31, 2005. This increase
was primarily a result of the Prism Gas acquisition.
Other operating income. Other operating income for the year ended December 31, 2006
consisted of gains on the sale of property and equipment.
In summary, our natural gas services operating income decreased $1.8 million, or 29%, for the
year ended December 31, 2006 compared to the year ended December 31, 2005. This decrease is
primarily related to an increase
- 56 -
in selling, general and administrative expenses related to the Prism Gas acquisition. Prism
Gas, as operator of Waskom, is required, per the partnership agreement, to perform certain
services, including but not limited to accounting and engineering, for the Waskom partnership.
While Prism Gas does receive an operators fee based on a percentage of Waskoms operating costs,
generally the expenses incurred are recovered in equity in earnings of unconsolidated entities.
Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities
was $8.5 million for the year ended December 31, 2006 compared to $1.4 for the year ended December
31, 2005. In connection with the Prism Gas acquisition on November 10, 2005, we acquired an
unconsolidated 50% interest in Waskom Gas Processing Company and the Matagorda Offshore Gathering
System. We also acquired 50% interest in Panther Interstate Pipeline Energy LLC, the owner of the
Fishhook Gathering System. As a result, these interests are accounted for using the equity method
of accounting and we do not include any portion of their net income in our operating income.
Marine Transportation Segment
The following table summarizes our results of operations in our marine transportation segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
47,835 |
|
|
$ |
35,451 |
|
Operating expenses |
|
|
34,454 |
|
|
|
27,768 |
|
Selling, general and administrative expenses |
|
|
587 |
|
|
|
357 |
|
Depreciation and amortization |
|
|
6,609 |
|
|
|
4,942 |
|
|
|
|
|
|
|
|
|
|
|
6,185 |
|
|
|
2,384 |
|
|
|
|
|
|
|
|
Other operating income |
|
|
226 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
6,411 |
|
|
$ |
2,384 |
|
|
|
|
|
|
|
|
Revenues. Our marine transportation revenues increased $12.4 million, or 35%, for the year
ended December 31, 2006 compared to the year ended December 31, 2005. Our offshore revenues
increased $9.5 million primarily from the acquisition of two integrated tug barge units. Our
inland marine assets, coupled with leased inland marine assets, had increased revenues of $3.0
million from increased utilization of our fleet as a result of a geographical redistribution of our
assets on the Gulf Coast. We also had increased contract rates, and operated an additional number
of leased vessels.
For the year ended December 31, 2006, inter-segment sales to our sulfur, terminalling and
storage, and fertilizer segments of $2.3 million were eliminated from our marine transportation
segment reducing reported marine transportation revenue by this amount. Inter-segment sales of
$2.1 million were eliminated for the year ended December 31, 2005.
Operating expenses. Operating expenses increased $6.7 million, or 24%, for the year ended
December 31, 2006 compared to the year ended December 31, 2005. The increase was primarily a
result of associated costs from our offshore marine vessel acquisitions. We experienced increases
in other operating costs including fuel, salaries and wages, insurance premiums and repair and
maintenance expenses from increased shipyard costs.
Selling, general and administrative expenses. Selling, general & administrative expenses
increased $0.2 million, or 64%, for the year ended December 31, 2006 compared to the year ended
December 31, 2005.
Depreciation and amortization. Depreciation and amortization increased $1.7 million, or 34%,
for the year ended December 31, 2006 compared to the year ended December 31, 2005. This increase
was the result of capital expenditures made in the last 12 months.
Other operating income. Other operating income for the year ended December 31, 2006 consisted
of gains on the sale of property and equipment.
In summary, our marine transportation operating income increased $4.0 million, or 169%, for
the year ended December 31, 2006 compared to the year ended December 31, 2005.
- 57 -
Sulfur Segment
The following table summarizes our results of operations in our sulfur segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
61,271 |
|
|
$ |
36,784 |
|
Cost of products sold |
|
|
38,898 |
|
|
|
25,657 |
|
Operating expenses |
|
|
13,452 |
|
|
|
5,786 |
|
Selling, general and administrative expenses. |
|
|
1,060 |
|
|
|
614 |
|
Depreciation and amortization |
|
|
2,997 |
|
|
|
1,790 |
|
|
|
|
|
|
|
|
Operating income |
|
$ |
4,864 |
|
|
$ |
2,937 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in Earnings of Unconsolidated Entities |
|
$ |
|
|
|
$ |
222 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sulfur Volumes (long tons) |
|
|
836.3 |
|
|
|
533.5 |
|
|
|
|
|
|
|
|
Our sulfur operating segment began operations in April 2005 after acquiring a sulfur priller
and related assets located in Stockton, California in the Bay Sulfur acquisition. On January 2,
2006, we placed into service a newly constructed sulfur priller at our Neches terminal in Beaumont,
Texas. On July 15, 2005, we purchased the equity interests of CF Martin Sulphur not owned by us.
Since that date, the results of CF Martin Sulfur have been added to the results reported in the
above table. Prior to July 15, 2005, we owned an unconsolidated noncontrolling 49.5% limited
partnership interest in CF Martin Sulphur, which was accounted for using the equity method of
accounting. On July 15, 2005, CF Martin Sulphur became a wholly-owned subsidiary of the
Partnership and all intercompany transactions were eliminated in consolidation. As of March 30,
2006, CF Martin Sulphur merged into Martin Operating Partnership L.P. and continues to be reported
in our sulfur segment and operates the business as Martin Sulfur.
The results of operation for the twelve month period ending December 31, 2005, represents
operations at the Stockton, California priller facility from April 2005 through December 2005 and
CF Martin Sulphur from July 15, 2005 through December 2005.
Equity in earnings of unconsolidated entities. For the year ended December 31, 2005, equity in
earnings of unconsolidated entities relates to our unconsolidated non-controlling 49.5% limited
partner interest in CF Martin Sulphur prior to July 15, 2005.
Fertilizer Segment
The following table summarizes our results of operations in our fertilizer segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
41,326 |
|
|
$ |
31,634 |
|
Cost of products sold |
|
|
36,267 |
|
|
|
26,975 |
|
Selling, general and administrative expenses |
|
|
1,591 |
|
|
|
1,696 |
|
Depreciation and amortization |
|
|
1,624 |
|
|
|
1,178 |
|
|
|
|
|
|
|
|
Operating income |
|
$ |
1,844 |
|
|
$ |
1,785 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fertilizer Volumes (tons) |
|
|
211.6 |
|
|
|
138.1 |
|
|
|
|
|
|
|
|
Revenues. Our fertilizer revenues increased $9.7 million, or 31%, for the year ended December
31, 2006 compared to the year ended December 31, 2005. Our sales volume increased 53% due to
increased demand from our customers and new volume sales as a result of our A & A Fertilizer
acquisition, which closed in late December 2005. Offsetting this volume increase was a decrease in
our average sales price per ton of 15%. This decrease in of our sales price per ton was a result
of the A & A Fertilizer acquisition. Liquid sulfur product sales from this acquisition are at a
lower sales price per ton than our historical dry sulfur product sales.
- 58 -
Costs of products sold. Our cost of products sold increased $9.3 million, or 34%, for the
year ended December 31, 2006 compared to the year ended December 31, 2005. Although this increase
was less than our increase in sales, we experienced a decreased gross margin per ton. This was a
result of competitive pricing pressure and increased freight costs that we were unable to pass
through to our customers.
Selling, general and administrative expenses. Selling, general & administrative expenses
decreased $0.1 million, or 6%, for the year ended December 31, 2006 compared to the year ended
December 31, 2005.
Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 38%,
for the year ended December 31, 2006 compared to the year ended December 31, 2005 as a result of
the A & A Fertilizer acquisition.
Other operating income Other operating income for the year ended December 31, 2005 consisted
of losses on the sale of property and equipment.
In summary, our fertilizer operating income increased $0.1 million, or 3%, for the year ended
December 31, 2006 compared to the year ended December 31, 2005.
Statement of Operations Items as a Percentage of Revenues
In the aggregate, our cost of products sold, operating expenses, selling, general and
administrative expenses, and depreciation and amortization have remained relatively constant as a
percentage of revenues for the years ended December 31, 2006 and December 31, 2005. The following
table summarizes, on a comparative basis, these items of our statement of operations as a
percentage of our revenues.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2006 |
|
2005 |
|
|
(In thousands) |
Revenues |
|
|
100 |
% |
|
|
100 |
% |
Cost of products sold |
|
|
80 |
% |
|
|
80 |
% |
Operating expenses |
|
|
11 |
% |
|
|
11 |
% |
Selling, general and administrative expenses |
|
|
2 |
% |
|
|
2 |
% |
Depreciation and amortization |
|
|
3 |
% |
|
|
3 |
% |
Equity in Earnings of Unconsolidated Entities
For the years ended December 31, 2006 and 2005, equity in earnings of unconsolidated entities
relates to our unconsolidated non-controlling 49.5% limited partner interest in CF Martin Sulphur
prior to July 15, 2005, the unconsolidated interest in Bosque County Pipeline subsequent to its
acquisition on June 30, 2006 and the unconsolidated interests in Waskom Gas Processing Company, the
Matagorda Offshore Gathering System and Panther Interstate Pipeline Energy, L.L.C. owned by Prism
Gas since its acquisition on November 10, 2005.
Interest Expense
Our interest expense for all operations was $13.6 million for 2006 compared to $6.9 million
for 2005, an increase of $6.7 million, or 97%. This increase was primarily due to an increase in
average debt outstanding, an increase in interest rates throughout 2006 compared to 2005 and a debt
prepayment premium of $1.2 million paid in 2006.
Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses were $3.3 million for 2006 compared to
$3.5 million for 2005, a decrease of $0.2 million or 6%. This was primarily due to a of $0.5
million in costs relating to compliance with the requirements of the Sarbanes-Oxley Act of 2002.
This decrease was offset by an increase in overhead allocation of $0.3 million from Martin Resource
Management.
Martin Resource Management allocated to us a portion of its indirect selling, general and
administrative expenses for services such as accounting, treasury, clerical billing, information
technology, administration of insurance, engineering, general office expense and employee benefit
plans and other general corporate overhead functions we
- 59 -
share with Martin Resource Management retained businesses. This allocation is based on the
percentage of time spent by Martin Resource Management personnel that provide such centralized
services. Generally accepted accounting principles also permit other methods for allocation these
expenses, such as basing the allocation on the percentage of revenues contributed by a segment.
The allocation of these expenses between Martin Resource Management and us is subject to a number
of judgments and estimates, regardless of the method used. We can provide no assurances that our
method of allocation, in the past or in the future, is or will be the most accurate or appropriate
method of allocation these expenses. Other methods could result in a higher allocation of selling,
general and administrative expense to us, which would reduce our net income. Under the omnibus
agreement, the reimbursement amount with respect to indirect general and administrative and
corporate overhead expenses was capped at $2.0 million for the period ending October 31, 2006.
Subsequently, this amount may be increased by no more than the percentage increase in the consumer
price index. In addition, Martin Resource Management and us can agree, subject to approval of the
Conflicts Committee of our general partner, to adjust this amount for expansions of our operations
and acquisitions. Martin Resource Management allocated indirect selling, general and
administrative expenses of $1.5 million for the year ended December 31, 2006 compared to $1.3
million for the year ended December 31, 2005.
Year Ended December 31, 2005 Compared to the Year Ended December 31, 2004
Our total revenues were $438.4 million for the year ended December 31, 2005 compared to $294.1
million for the year ended December 31, 2004, an increase of $144.3 million, or 49%. Our cost of
products sold was $351.8 million for the year ended December 31, 2005 compared to $230.0 million
for the year ended December 31, 2004, an increase of $121.8 million, or 53%. Our total operating
expenses were $46.9 million for the year ended December 31, 2005 compared to $34.5 million for the
year ended December 31, 2004, an increase of $12.4 million, or 36%.
Our total selling, general and administrative expenses were $8.1 million for the year ended
December 31, 2005 compared to $6.2 million for the year ended December 31, 2004, an increase of
$1.9 million, or 31%. Total depreciation and amortization was $12.6 million for the year ended
December 31, 2005 compared to $8.8 million for the year ended December 31, 2004, an increase of
$3.8 million, or 43%. Our operating income was $19.0 million for the year ended December 31, 2005
compared to $14.7 million for the year ended December 31, 2004, an increase of $4.3 million, or
29%.
The results of operations are described in greater detail on a segment basis below.
Terminalling and Storage Segment
The following table summarizes our results of operations in our terminalling and storage
segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
Services |
|
$ |
23,081 |
|
|
$ |
17,919 |
|
Products |
|
|
9,817 |
|
|
|
8,238 |
|
|
|
|
|
|
|
|
Total Revenues |
|
|
32,898 |
|
|
|
26,157 |
|
Cost of products sold |
|
|
8,079 |
|
|
|
6,775 |
|
Operating expenses |
|
|
10,879 |
|
|
|
8,494 |
|
Selling, general and administrative expenses |
|
|
250 |
|
|
|
399 |
|
Depreciation and amortization |
|
|
4,376 |
|
|
|
3,740 |
|
|
|
|
|
|
|
|
Operating income |
|
$ |
9,314 |
|
|
$ |
6,749 |
|
|
|
|
|
|
|
|
Revenues. Our terminalling and storage revenues increased $6.7 million, or 26%, for the year
ended December 31, 2005 compared to the year ended December 31, 2004. Service revenue accounted
for $5.2 million of this increase. The service revenue increase was primarily a result of owning
the Neches and Freeport OOS terminals for the full year of 2005. This accounted for $3.2 million
of the service revenue increase. The balance of the service revenue increase was a result of
increased volumes and terminalling and storage rates at our Gulf Coast shore based terminals.
Product revenue increased $1.6 million due to a 16% increase in product cost that was passed
through to our customers, and a 1% increase in sales volume.
- 60 -
Cost of products sold. Our cost of products sold increased $1.3 million, or 19%, for the year
ended December 31, 2005 compared to the year ended December 31, 2004. This increase was primarily
a result of a 16% increase in product cost, and a 1% increase in sales volumes.
Operating expenses. Operating expenses increased $2.4 million, or 28%, for the year ended
December 31, 2005 compared to the year ended December 31, 2004. This increase was primarily a
result of additional operating expenses of $1.1 million from the Neches terminal acquisition.
These additional expenses were the result of owning this facility for the full year of 2005.
Hurricane expenses accounted for an additional $0.7 million and we also experienced an increase in
natural gas utilities cost of $0.4 million.
Selling, general and administrative expenses. Selling, general and administrative expenses
decreased $0.1 million, or 37%, for the year ended December 31, 2005 compared to the year ended
December 31, 2004. This decrease was primarily a result of a collection of a previously written
off bad debt.
Depreciation and amortization. Depreciation and amortization increased $0.6 million, or 17%,
for the year ended December 31, 2005 compared to the year ended December 31, 2004. This increase
was a result of the Neches terminal acquisition.
In summary, terminalling and storage operating income increased $2.6 million, or 38%, for the
year ended December 31, 2005 compared to the year ended December 31, 2004.
Natural Gas Services Segment
The following table summarizes our results of operations in our natural gas services segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
301,676 |
|
|
$ |
203,427 |
|
Cost of products sold |
|
|
291,109 |
|
|
|
197,859 |
|
Operating expenses |
|
|
2,455 |
|
|
|
1,185 |
|
Selling, general and administrative expenses |
|
|
1,753 |
|
|
|
1,200 |
|
Depreciation and amortization |
|
|
356 |
|
|
|
103 |
|
|
|
|
|
|
|
|
Operating income |
|
$ |
6,003 |
|
|
$ |
3,080 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in Earnings of Unconsolidated Entities |
|
$ |
1,369 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL Volumes (gallons) |
|
|
270,524 |
|
|
|
226,565 |
|
Revenues. Our natural gas services revenues increased $98.3 million, or 48%, for the year
ended December 31, 2005 compared to the year ended December 31, 2004. Of the increase, $85.5
million is related to our historical NGL distribution segment. Our average sales price per gallon
from our historical NGL distribution segment was 23% higher in 2005 compared to 2004. Also, our
sales volume from our historical NGL distribution segment increased 15% as a result of increased
demand from our retail propane customers as well as increased demand from our industrial customers.
The remaining $12.8 million increase is related to our acquisition of Prism Gas on November
10, 2005. These revenues are comprised of $8.8 million of NGL sales, $3.3 million of natural gas
sales and $0.2 million of gathering and processing fees. Also, included in revenue was $0.5
million of gains on derivative contracts.
Costs of product sold. Our cost of products increased $93.3 million, or 47%, for the year
ended December 31, 2005 compared to the year ended December 31, 2004. Of the increase, $81.8
million is related to our historical NGL distribution segment. This increase was less than the
corresponding increase in NGL revenues as we were able to increase our per gallon margins. Much of
this margin increase was the result of rapid NGL price increases that occurred in the third quarter
of 2005. These rapid price increases were the result of Hurricanes Katrina and Rita. The balance
of the increase of $11.5 million is a result of the Prism Gas acquisition.
- 61 -
Operating expenses. Operating expenses increased $1.3 million, or 107%, for the year ended
December 31, 2005 compared to the year ended December 31, 2004. An increase of $0.8 million was a
result of additional operating expenses incurred from the East Texas Pipeline acquisition, and $0.2
million resulted from the Prism Gas acquisition. The remaining increase was a result of increased
operating costs in our historical NGL distribution segment.
Selling, general and administrative expenses. Selling, general and administrative expenses
increased $0.6 million, or 46%, for the year ended December 31, 2005 compared to the year ended
December 31, 2004. This increase was primarily a result of the East Texas Pipeline and Prism Gas
acquisitions made in 2005.
Depreciation and amortization. Depreciation and amortization increased $0.3 million, or 246%,
for the year ended December 31, 2005 compared to the year ended December 31, 2004. This increase
was primarily a result of the East Texas Pipeline and Prism Gas acquisitions made in 2005.
In summary, our natural gas services operating income increased $2.9 million, or 95%, for the
year ended December 31, 2005 compared to the year ended December 31, 2004.
Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities
was $1.4 million for the year ended December 31, 2005. In connection with the Prism Gas
acquisition on November 10, 2005, we acquired an unconsolidated 50% interest in Waskom Gas
Processing Company and the Matagorda Offshore Gathering System. We also acquired 50% interest in
Panther Interstate Pipeline Energy LLC, the owner of the Fishhook Gathering System. As a result,
these interests are accounted for using the equity method of accounting and we do not include any
portion of their net income in our operating income.
Marine Transportation Segment
The following table summarizes our results of operations in our marine transportation segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
35,451 |
|
|
$ |
34,780 |
|
Operating expenses |
|
|
27,768 |
|
|
|
24,796 |
|
Selling, general and administrative expenses |
|
|
357 |
|
|
|
175 |
|
Depreciation and amortization |
|
|
4,942 |
|
|
|
3,982 |
|
|
|
|
|
|
|
|
Operating income |
|
$ |
2,384 |
|
|
$ |
5,827 |
|
|
|
|
|
|
|
|
Revenues. Our marine transportation revenues increased $0.7 million, or 2%, for the year
ended December 31, 2005 compared to the year ended December 31, 2004. Our inland marine assets,
coupled with leased inland marine assets generated an additional $3.7 million in revenue due to
stronger customer demand, higher equipment utilization, and charging our inland customers the
increase in our fuel costs. Partially offsetting these increases in inland revenue was a decrease
of $0.9 million in offshore revenues as a result of decreased utilization and downtime as upgrades
were performed to prepare to handle petroleum products. Because the majority of our inland
equipment is on time charter, the impact of Hurricanes Katrina and Rita was minor.
Intersegment sales of $2.1 million from our marine transportation segment to our sulfur
segment were eliminated, reducing reported marine transportation revenue by this amount. Our
sulfur segment accounted for this cost in operating expense. This intersegment charge has been
eliminated from our sulfur segments operating expenses. Prior to July 15, 2005, we owned an
unconsolidated, non-controlling 49.5% limited partnership interest in CF Martin Sulphur, which was
accounted for using the equity method of accounting. As of July 15, 2005, CF Martin is now one of
our wholly-owned subsidiaries. As a result, all intercompany transactions are eliminated in
consolidation.
Operating expenses. Operating expenses increased $3.0 million, or 12%, for the year ended
December 31, 2005 compared to the year ended December 31, 2004. The increase was a result of
increased operating costs, including leased operating equipment, outside towing, fuel expenses,
and wage costs.
Selling, general and administrative expenses. Selling, general & administrative expenses
increased $0.2 million, or 104%, for the year ended December 31, 2005 compared to the year ended
December 31, 2004.
- 62 -
Depreciation and amortization. Depreciation and amortization increased $1.0 million, or 24%,
for the year ended December 31, 2005 compared to the year ended December 31, 2004. This increase
was due primarily to maintenance capital expenditures made in the last 12 months.
In summary, our marine transportation operating income decreased $3.4 million, or 59%, for the
year ended December 31, 2005 compared to the year ended December 31, 2004. Without the new
intersegment revenue eliminations resulting from the establishment of our sulfur segment, operating
income would have only decreased $1.3 million, or 23%, for the year ended December 31, 2005
compared to the year ended December 31, 2004.
Sulfur Segment
The following table summarizes our results of operations in our sulfur segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
36,784 |
|
|
$ |
|
|
Cost of products sold |
|
|
25,657 |
|
|
|
|
|
Operating expenses |
|
|
5,786 |
|
|
|
|
|
Selling, general and administrative expenses |
|
|
614 |
|
|
|
|
|
Depreciation and amortization |
|
|
1,790 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
2,937 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in Earnings of Unconsolidated Entities |
|
$ |
222 |
|
|
$ |
912 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sulfur Volumes (long tons) |
|
|
533.5 |
|
|
|
|
|
|
|
|
|
|
|
|
Our sulfur operating segment was established in April 2005, as a result of the
acquisition of the Bay Sulfur assets and the beginning of construction of a sulfur priller at our
Neches terminal. On July 15, 2005, we purchased the equity interests of CF Martin Sulphur not
owned by us. Since that date, the results of CF Martin Sulfur have been added to the results
reported in the above table. Prior to July 15, 2005, we owned an unconsolidated noncontrolling
49.5% limited partnership interest in CF Martin Sulphur, which was accounted for using the equity
method of accounting. CF Martin Sulphur is now a wholly-owned subsidiary of the Partnership. As a
result, subsequent to July 15, 2005 all intercompany transactions were eliminated in consolidation.
Intersegment expense of $2.1 million, which is the charge from our marine transportation
segment to our sulfur segment for the charter of one offshore tug/barge tanker unit and certain
inland equipment which was eliminated from our sulfur segments operating expenses.
Equity in earnings of unconsolidated entities. For the years ended December 31, 2005 and 2004,
equity in earnings of unconsolidated entities relates to our unconsolidated non-controlling 49.5%
limited partner interest in CF Martin Sulphur prior to July 15, 2005. Equity in earnings of our
unconsolidated interest in CF Martin Sulphur for the period January 1, 2005 through July 15, 2005
was $0.2 million compared to $0.9 for the year ended December 31, 2004.
Fertilizer Segment
The following table summarizes our results of operations in our fertilizer segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
31,634 |
|
|
$ |
29,780 |
|
Cost of products sold |
|
|
26,975 |
|
|
|
25,342 |
|
Selling, general and administrative expenses |
|
|
1,696 |
|
|
|
1,658 |
|
Depreciation and amortization |
|
|
1,178 |
|
|
|
941 |
|
|
|
|
|
|
|
|
Operating income |
|
$ |
1,785 |
|
|
$ |
1,839 |
|
|
|
|
|
|
|
|
Fertilizer Volumes (tons) |
|
|
138.1 |
|
|
|
146.2 |
|
- 63 -
Revenues. Our fertilizer revenues increased $1.9 million, or 6%, for the year ended December
31, 2005 compared to the year ended December 31, 2004. We experienced a 12% increase in our
average sales prices, as we passed through increased raw materials costs to our customers. Our
sales volume decreased by 6% as a result of an abnormally dry year in certain of our market areas.
We also experienced a decrease in sales volume on some of our specialty products. Unfavorable
weather conditions in some of our marked areas contributed to this volume decrease.
Costs of products sold. Our cost of products sold increased $1.6 million, or 6%, for the year
ended December 31, 2005 compared to the year ended December 31, 2004. An increase of 9% in our
cost per ton of fertilizer products sold was a result of increased costs of raw materials. Our
sales volume decreased 6%, somewhat offsetting the increase in our cost per ton.
Selling, general and administrative expenses. Selling, general & administrative expenses were
approximately the same for both years.
Depreciation and amortization. Depreciation and amortization increased $0.2 million, or 25%,
for the year ended December 31, 2005 compared to the year ended December 31, 2004.
In summary, our fertilizer operating income was approximately the same for both years.
Statement of Operations Items as a Percentage of Revenues
In the aggregate, our cost of products sold, operating expenses, selling, general and
administrative expenses, and depreciation and amortization have remained relatively constant as a
percentage of revenues for the years ended December 31, 2005 and December 31, 2004. The following
table summarizes, on a comparative basis, these items of our statement of operations as a
percentage of our revenues.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2005 |
|
2004 |
|
|
(In thousands) |
Revenues |
|
|
100 |
% |
|
|
100 |
% |
Cost of products sold |
|
|
80 |
% |
|
|
78 |
% |
Operating expenses |
|
|
11 |
% |
|
|
12 |
% |
Selling, general and administrative expenses |
|
|
2 |
% |
|
|
2 |
% |
Depreciation and amortization |
|
|
3 |
% |
|
|
3 |
% |
Equity in Earnings of Unconsolidated Entities
For the years ended December 31, 2005 and 2004, equity in earnings of unconsolidated entities
relates to our unconsolidated non-controlling 49.5% limited partner interest in CF Martin Sulphur
prior to July 15, 2005 and the unconsolidated interests in Waskom Gas Processing Company, the
Matagorda Offshore Gathering System and Panther Interstate Pipeline Energy, L.L.C. owned by Prism
Gas since its acquisition on November 10, 2005.
Interest Expense
Our interest expense for all operations was $6.9 million for 2005 compared to $3.3 million for
2004, an increase of $3.6 million, or 109%. This increase was primarily due to an increase in
average debt outstanding and an increase in interest rates in 2005 compared to 2004. Additionally,
interest expense was offset by a decrease in amortization of deferred debt costs of $0.3 million
for 2005 compared to 2004.
Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses were $3.5 million for 2005 compared to
$2.8 million for 2004, an increase of $0.7 million or 25%. This increase was due to increased
overhead allocation of $0.2 million from
- 64 -
Martin Resource Management, increased costs related to complying with the requirements of the
Sarbanes-Oxley Act of 2002 of $0.2 million, and increased costs for legal, audit, consulting and
professional fees of $0.3 million.
Martin Resource Management allocated to us a portion of its indirect selling, general and
administrative expenses for services such as accounting, treasury, clerical billing, information
technology, administration of insurance, engineering, general office expense and employee benefit
plans and other general corporate overhead functions we share with Martin Resource Management
retained businesses. This allocation is based on the percentage of time spent by Martin Resource
Management personnel that provide such centralized services. Generally accepted accounting
principles also permit other methods for allocation these expenses, such as basing the allocation
on the percentage of revenues contributed by a segment. The allocation of these expenses between
Martin Resource Management and us is subject to a number of judgments and estimates, regardless of
the method used. We can provide no assurances that our method of allocation, in the past or in the
future, is or will be the most accurate or appropriate method of allocation these expenses. Other
methods could result in a higher allocation of selling, general and administrative expense to us,
which would reduce our net income. Under the omnibus agreement, the reimbursement amount with
respect to indirect general and administrative and corporate overhead expenses was capped at $2.0
million for the period ending October 31, 2006. Subsequently, this amount may be increased by no
more than the percentage increase in the consumer price index. In addition, Martin Resource
Management and us can agree, subject to approval of the Conflicts Committee of our general partner,
to adjust this amount for expansions of our operations and acquisitions. Martin Resource
Management allocated indirect selling, general and administrative expenses of $1.3 million for the
year ended December 31, 2005 compared to $1.1 million for the year ended December 31, 2004.
Liquidity and Capital Resources
Cash Flows and Capital Expenditures
In 2006, cash decreased $2.8 million as a result of $39.3 million provided by operating
activities, $95.1 million used in investing activities and $53.0 million provided by financing
activities. In 2005, cash increased $3.3 million as a result of $32.3 million provided by
operating activities, $138.7 million used in investing activities and $109.7 million provided by
financing activities. In 2004, cash increased $0.9 million as a result of $12.8 million provided
by operating activities, $34.3 million used in investing activities and $22.4 million provided by
financing activities.
For the periods presented, our investing activities consisted primarily of acquisitions,
investments in unconsolidated entities and capital expenditures. Generally, our capital
expenditure requirements have consisted, and we expect that our capital requirements will continue
to consist, of:
|
|
|
maintenance capital expenditures, which are capital expenditures made to
replace assets to maintain our existing operations and to extend the useful lives of
our assets; and |
|
|
|
|
expansion capital expenditures, which are capital expenditures made to grow
our business, to expand and upgrade our existing marine transportation, terminalling,
storage and manufacturing facilities, and to construct new plants, storage facilities,
terminalling facilities and new marine transportation assets. |
In 2006, our investing activities consisted primarily of payments for acquisitions of $24.3
million, payments for property plant and equipment of $66.4 million, investments in partnerships of
$11.5 million and receipt of insurance proceeds on involuntary conversion of property, plant and
equipment of $4.8 million.
In 2005, our investing activities consisted primarily of payments for acquisitions of $114.2
million and payments for property plant and equipment of $24.8 million, investments in partnerships
of $0.8 million, cash distributions received from partnerships of $0.7 million and proceeds from
sale of property, plant and equipment of $0.1 million.
In 2004, our investing activities consisted primarily of cash paid for acquisitions of $31.2
million and payments for property, plant and equipment of $5.2 million.
For 2006, 2005 and 2004 our capital expenditures for property and equipment were $90.7
million, $79.2 million and $35.4 million, respectively.
- 65 -
As to each period:
|
|
|
In 2006, we spent $78.3 million for expansion and $12.4 million for
maintenance. Our expansion capital expenditures were made in connection with our
marine vessel purchases, acquiring assets relating to the South Houston and Prime
Asphalt terminal acquisitions, the Corpus Christi barge terminal, the sulfur priller
construction project at our Neches facility in Beaumont, Texas, and the sulfuric acid
plant construction project at our facility in Plainview, Texas. Our maintenance
capital expenditures were primarily made in our marine transportation segment for
routine dry dockings of our vessels pursuant to the United States Coast Guard
requirements and in our terminal segment for terminal facilities where $4.7 million in
maintenance capital expenditures was spent in connection with restoration of assets
destroyed in Hurricanes Rita and Katrina. |
|
|
|
|
In 2005, we spent $74.1 million for expansion and $5.1 million for
maintenance. Our expansion capital expenditures were primarily made in connection with
the Prism Gas and CF Martin acquisitions, the Bay sulfur priller acquisition in
Stockton, California, and the sulfur priller construction project at our Neches
facility in Beaumont, Texas. Also, we are constructing a sulfuric acid plant at our
facility in Plainview, Texas and we acquired A & A Fertilizer located in Beaumont,
Texas. Our maintenance capital expenditures were primarily made in our marine
transportation segment for routine dockings of our vessels pursuant to the United
States Coast Guard requirements and in our terminal segment for terminal facilities. |
|
|
|
|
In 2004, we spent $30.2 million for expansion and $5.2 million for
maintenance. Our expansion capital expenditures were primarily made in connection with
the Neches and Freeport terminal acquisitions. Our maintenance capital expenditures
were primarily made in our marine transportation business for routine dockings of our
vessels pursuant to United States Coast Guard requirements and terminal and fertilizer
facilities. |
In 2006, our financing activities consisted of cash distributions paid to common and
subordinated unitholders of $32.1 million, net proceeds from a follow-on public equity offering of
$95.4 million, net proceeds from the issuance of common units of $15.0 million, contributions of
$2.4 million from our general partner to maintain its 2% general partner interest, payments of
long-term debt under our current and predecessor credit facilities of $163.0 million and borrowings
of long-term debt under our current and predecessor credit facilities of $135.8 million and
payments of debt issuance costs of $0.4 million.
In 2005, our financing activities consisted of cash distributions paid to common and
subordinated unitholders of $19.0 million, payments of long-term debt under our current and
predecessor credit facilities of $134.1 million and borrowings of long-term debt under our current
and predecessor credit facilities of $250.9 million and payments of debt issuance costs of $3.7
million. In November, 2005, we issued 756,480 common units in connection with acquisition of Prism
Gas. Our general partner contributed $0.5 million in cash to us in conjunction with the issuance
in order to maintain its 2% general partner interest in us.
In 2004, our financing activities consisted of net proceeds from a public offering and related
transactions of $34.8 million, cash distributions paid to common and subordinated unitholders of
$17.5 million, payments of long-term debt under our credit facility of $43.2 million, borrowings of
long-term debt under our predecessor credit facility of $49.2 million and payments of debt issuance
costs of $0.9 million. In February 2004, we issued 1,322,500 common units in a public offering,
resulting in proceeds of $34.0 million, net of underwriters discounts, commissions and offering
expenses. Our general partner contributed $0.8 million in cash to us in conjunction with the
issuance in order to maintain its 2% general partner interest in us. The net proceeds were used to
pay down revolving debt under our credit facility.
Capital Resources
Historically, we have generally satisfied our working capital requirements and funded our
capital expenditures with cash generated from operations and borrowings. We expect our primary
sources of funds for short-term liquidity needs will be cash flows from operations and borrowings
under our credit facility.
As of December 31, 2006, we had $174.1 million of outstanding indebtedness, consisting of
outstanding borrowings of $44.0 million under our revolving credit facility and $130.0 million
under our term loan facility and $0.1 of other secured debt.
- 66 -
In November 2005, we borrowed approximately $63.1 million under our credit facility to pay a
portion of the purchase price for the Prism Gas acquisition. The remainder of the purchase price
was funded by $5.0 million previously escrowed by us, $15.5 million of new equity capital provided
by Martin Resource Management in exchange for newly issued common units, approximately $9.6 million
of newly issued common units issued to a certain number of the sellers and approximately $0.8
million in capital provided by Martin Resource Management for acquisition costs and to maintain its
2% general partnership interest in us. The common units were priced at $32.54 per common unit,
based on the average closing price of our common units on the NASDAQ during the ten trading days
immediately preceding and immediately following the date of the execution of the definitive
purchase agreement.
In January 2006, we completed a follow-on public offering of 3,450,000 common units, resulting
in proceeds of $95.4 million, after payment of underwriters discounts, commissions and offering
expenses. Our general partner contributed $2.1 million in cash to us in conjunction with the
offering in order to maintain its 2% general partner interest in us. Of the net proceeds, $62.0
million was used to pay then current balances under our revolving credit facility and $7.5 million
was used to fund a portion of the redemption price for our U.S. Government Guaranteed Ship
Financing Bonds. The remainder of the net proceeds has been or will be used to fund future organic
growth projects.
Under our prior acquisition subfacility, we borrowed $3.5 million in connection with the
acquisition of the East Texas Pipeline in January 2005, $5.0 million in connection with the
acquisition of the operating assets of Bay Sulfur Company in April 2005, and $19.4 million in
connection with the acquisition of the partnership interests in CF Martin Sulphur not owned by us
in July 2005. In connection with the CF Martin Sulphur acquisition, we assumed $11.5 million of
indebtedness owed by CF Martin Sulphur and promptly repaid $2.4 million of such indebtedness. The
remaining indebtedness relates to certain financing of CF Martin Sulphur under its U.S. Government
Guaranteed Ship Financing Bonds. These bonds were paid on March 6, 2006 with available cash and
borrowings from our revolving credit facility. At such time, we also paid the related $1.2 million
pre-payment premium.
In December 2006, we issued 470,484 common units to Martin Product Sales LLC, an affiliate of
Martin Resource Management, for approximately $15.3 million, including a capital contribution of
approximately $0.3 million made by our general partner in order to maintain its 2% general partner
interest in us. These funds were used to reduce the revolving line of credit.
We believe that cash generated from operations, and our borrowing capacity under our credit
facility, will be sufficient to meet our working capital requirements, anticipated capital
expenditures and scheduled debt payments in 2007. However, our ability to satisfy our working
capital requirements, to fund planned capital expenditures and to satisfy our debt service
obligations will depend upon our future operating performance, which is subject to certain risks.
Please read Item 1A. Risk Factors Risks Related to Our Business for a discussion of such
risks.
Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of
December 31, 2006 is as follows: (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment due by period |
|
|
|
Total |
|
|
Less than |
|
|
1-3 |
|
|
3-5 |
|
|
Due |
|
Type of Obligation |
|
Obligation |
|
|
One Year |
|
|
Years |
|
|
Years |
|
|
Thereafter |
|
Long-Term Debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving credit facility |
|
$ |
44,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
44,000 |
|
|
$ |
|
|
Term loan facility |
|
|
130,000 |
|
|
|
|
|
|
|
|
|
|
|
130,000 |
|
|
|
|
|
Other |
|
|
95 |
|
|
|
74 |
|
|
|
21 |
|
|
|
|
|
|
|
|
|
Non-competition agreements |
|
|
1,000 |
|
|
|
250 |
|
|
|
500 |
|
|
|
100 |
|
|
|
150 |
|
Operating leases |
|
|
14,988 |
|
|
|
2,488 |
|
|
|
5,097 |
|
|
|
3,211 |
|
|
|
4,192 |
|
Interest expense(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving Credit Facility |
|
|
11,988 |
|
|
|
3,098 |
|
|
|
6,196 |
|
|
|
2,694 |
|
|
|
|
|
Term loan facility |
|
|
36,929 |
|
|
|
9,544 |
|
|
|
19,088 |
|
|
|
8,297 |
|
|
|
|
|
Other |
|
|
5 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations |
|
$ |
239,005 |
|
|
$ |
15,459 |
|
|
$ |
30,902 |
|
|
$ |
188,302 |
|
|
$ |
4,342 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Interest commitments are estimated using our current interest rates for the respective credit
agreements over their remaining terms. |
- 67 -
Letter of Credit At December 31, 2006, we had an outstanding irrevocable letter of credit in
the amount of $0.1 million which was issued under our revolving credit facility. This letter of
credit was issued to the Texas Commission on Environmental Quality to provide financial assurance
for our used oil handling program.
Off Balance Sheet Arrangements. We do not have any off-balance sheet financing arrangements.
Description of Our Credit Facility
On November 10, 2005, we entered into a new $225.0 million multi-bank credit facility
comprised of a $130.0 million term loan facility and a $95.0 million revolving credit facility,
which includes a $20.0 million letter of credit sub-limit. Our credit facility also includes
procedures for additional financial institutions to become revolving lenders, or for any existing
revolving lender to increase its revolving commitment, subject to a maximum of $100.0 million for
all such increases in revolving commitments of new or existing revolving lenders. Effective June
30, 2006, we increased our revolving credit facility $25.0 million resulting in a committed $120.0
million revolving credit facility. The revolving credit facility is used for ongoing working
capital needs and general partnership purposes, and to finance permitted investments, acquisitions
and capital expenditures. Under the amended and restated credit facility, as of December 31, 2006,
we had $44.0 million outstanding under the revolving credit facility and $130.0 million outstanding
under the term loan facility. As of December 31, 2006, we had $75.9 million available under our
revolving credit facility.
On July 14, 2005, we issued a $0.1 million irrevocable letter of credit to the Texas
Commission on Environmental Quality to provide financial assurance for its used oil handling
program.
Draws made under our credit facility are normally made to fund acquisitions and for working
capital requirements. During the current fiscal year, draws on our credit facilities have ranged
from a low of $130.0 million to a high of $197.7 million.
Our obligations under the credit facility are secured by substantially all of our assets,
including, without limitation, inventory, accounts receivable, marine vessels, equipment, fixed
assets and the interests in our operating subsidiaries and equity method investees. We may prepay
all amounts outstanding under this facility at any time without penalty.
Indebtedness under the credit facility bears interest at either LIBOR plus an applicable
margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans
that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that
are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are
LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime
rate loans ranges from 1.00% to 2.00%. The applicable margin for existing borrowings is 2.00%. As
a result of our leverage ratio test, effective January 1, 2007, the applicable margin for existing
borrowings will increase to 2.50%. Effective April 1, 2007, the applicable margin for existing
borrowings will decrease to 2.00%. We incur a commitment fee on the unused portions of the credit
facility.
Effective April 13, 2006, we entered into a cash flow hedge that swaps $75.0 million of
floating rate to fixed rate. The fixed rate cost is 5.25% plus our applicable LIBOR borrowing
spread. The cash flow hedge matures in November, 2010.
Effective December 13, 2006, we entered into a cash flow hedge that swaps $40.0 million of
floating rate to fixed rate. The fixed rate cost is 4.82% plus our applicable LIBOR borrowing
spread. The cash flow hedge matures in December, 2009.
Effective December 13, 2006, we entered into an interest rate swap that swaps $30.0 million of
floating rate to fixed rate. The fixed rate cost is 4.765% plus our applicable LIBOR borrowing
spread. This interest rate swap, which matures in March, 2010, is not accounted for as a cash flow
hedge.
In addition, the credit facility contains various covenants, which, among other things, limit
our ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless
we are the survivor; (iv) sell all or substantially all of our assets; (v) make certain
acquisitions; (vi) make certain investments; (vii) make certain capital expenditures; (viii) make
distributions other than from available cash; (ix) create obligations for some lease payments;
- 68 -
(x) engage in transactions with affiliates; (xi) engage in other types of business; and (xii)
our joint ventures to incur indebtedness or grant certain liens.
The credit facility also contains covenants, which, among other things, require us to maintain
specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75.0 million
plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in
the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal
quarter; (iii) total funded debt to EBITDA of not more than (x) 5.5 to 1.0 for the fiscal quarter
ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through
September 30, 2006, and (z) 4.75 to 1.00 for each fiscal quarter thereafter; and (iv) total secured
funded debt to EBITDA of not more than (x) 5.50 to 1.00 for the fiscal quarter ended September 30,
2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 20, 2006,
and (z) 4.00 to 1.00 for each fiscal quarter thereafter. We were in compliance with the debt
covenants contained in the credit facility for the years ended December 31, 2006 and 2005.
On November 10 of each year, commencing with November 10, 2006, we must prepay the term loans
under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless
its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. No prepayments under the term
loan were required to be made in 2006. If we receive greater than $15.0 million from the incurrence
of indebtedness other than under the credit facility, we must prepay indebtedness under the credit
facility with all such proceeds in excess of $15.0 million. Any such prepayments are first applied
to the term loans under the credit facility. We must prepay revolving loans under the credit
facility with the net cash proceeds from any issuance of its equity. We must also prepay
indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than
these mandatory prepayments, the credit facility requires interest only payments on a quarterly
basis until maturity. All outstanding principal and unpaid interest must be paid by November 10,
2010. The credit facility contains customary events of default, including, without limitation,
payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults,
change of control defaults and litigation-related defaults.
As
of March 2, 2007, our outstanding indebtedness includes $194 million under our credit
facility.
Seasonality
A substantial portion of our revenues are dependent on sales prices of products, particularly
NGLs and fertilizers, which fluctuate in part based on winter and spring weather conditions. The
demand for NGLs is strongest during the winter heating season. The demand for fertilizers is
strongest during the early spring planting season. However, our terminalling and storage and
marine transportation businesses and the molten sulfur business are typically not impacted by
seasonal fluctuations. We expect to derive approximately half of our net income from our
terminalling and storage, marine transportation, natural gas and sulfur businesses. Therefore, we
do not expect that our overall net income will be impacted by seasonality factors. However,
extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact
our terminalling and storage and marine transportation businesses. For example, Hurricanes Katrina
and Rita in the third quarter of 2005 adversely impacted our operating expenses and the four
hurricanes that impacted the Gulf of Mexico and Florida in the third quarter of 2004 adversely
impacted our terminalling and storage and marine transportation businesss revenues.
Impact of Inflation
Inflation in the United States has been relatively low in recent years and did not have a
material impact on our results of operations in 2006, 2005 and 2004. However, inflation remains a
factor in the United States economy and could increase our cost to acquire or replace property,
plant and equipment as well as our labor and supply costs. We cannot assure our unitholders that
we will be able to pass along increased costs to our customers.
Increasing energy prices could adversely affect our results of operations. Diesel fuel,
natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price
of these products would increase our operating expenses which could adversely affect net income.
We cannot assure our unitholders that we will be able to pass along increased operating expenses to
our customers.
- 69 -
Environmental Matters
Our operations are subject to environmental laws and regulations adopted by various
governmental authorities in the jurisdictions in which these operations are conducted. We incurred
no significant environmental costs, liabilities or expenditures to mitigate or eliminate
environmental contamination during 2002, 2003, 2004, 2005 or 2006. Under the omnibus agreement,
Martin Resource Management will indemnify us for five years after the closing of our initial public
offering, which closed on November 6, 2002, against:
|
|
|
certain potential environmental liabilities associated with the assets it
contributed to us relating to events or conditions that occurred or existed before
the closing of our initial public offering, and |
|
|
|
|
any payments we are required to make, as a successor in interest to affiliates
of Martin Resource Management, under environmental indemnity provisions contained
in the contribution agreement associated with the contribution of assets by Martin
Resource Management to CF Martin Sulphur, L.P. in November 2000. |
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. We
are exposed to market risks associated with commodity prices, counterparty credit and interest
rates. Historically, we have not engaged in commodity contract trading or hedging activities.
However, in connection with our acquisition of Prism Gas, we have established a hedging policy.
For the period ended December 31, 2006, changes in the fair value of our derivative contracts were
recorded both in earnings and comprehensive income since we have designated a portion of our
derivative instruments as hedges as of December 31, 2006.
Commodity Price Risk
We are exposed to market risks associated with commodity prices, counterparty credit and
interest rates. Historically, we have not engaged in commodity contract trading or hedging
activities. Under our hedging policy, we monitor and manage the commodity market risk associated
with the commodity risk exposure of Prism Gas. In addition, we are focusing on utilizing
counterparties for these transactions whose financial condition is appropriate for the credit risk
involved in each specific transaction.
We use derivatives to manage the risk of commodity price fluctuations. Our counterparties to
the commodity derivative contracts include Coral Energy Holding LP, Morgan Stanley Capital Group
Inc. and Wachovia Bank.
On all transactions where we are exposed to counterparty risk, we analyze the counterpartys
financial condition prior to entering into an agreement, and have established a maximum credit
limit threshold pursuant to our hedging policy and monitor the appropriateness of these limits on
an ongoing basis.
As a result of the Prism Gas acquisition, we are exposed to the impact of market fluctuations
in the prices of natural gas, NGLs and condensate as a result of gathering, processing and sales
activities. Prism Gas gathering and processing revenues are earned under various contractual
arrangements with gas producers. Gathering revenues are generated through a combination of
fixed-fee and index-related arrangements. Processing revenues are generated primarily through
contracts which provide for processing on percent-of-liquids (POL) and percent-of-proceeds (POP)
basis. Prism Gas has entered into hedging transactions through 2009 to protect a portion of its
commodity exposure from these contracts. These hedging arrangements are in the form of swaps for
crude oil, natural gas and ethane.
Based on estimated volumes, as of December 31, 2006, Prism Gas had hedged approximately 60%,
45%, and 14% of its commodity risk by volume for 2007, 2008, and 2009, respectively. As of
December 31, 2006, commodity derivative assets of $882 were included in other current assets and
$221 were included in non-current assets on the balance sheet. Commodity derivative liabilities of
$74 were included in long-term liabilities on the balance sheet. We estimate entering into
additional commodity derivatives on an ongoing basis to manage risk associated with these market
fluctuations, and will consider using various commodity derivatives, including forward contracts,
swaps, collars, futures and options, although there is no assurance that we will be able to do so
or that the terms thereof will be similar to the Partnerships existing hedging arrangements. In
addition, we will consider
- 70 -
derivative arrangements that include the specific NGL products as well as natural gas and
crude oil.
Hedging Arrangements in Place
|
|
|
|
|
|
|
|
|
Year |
|
Commodity Hedged |
|
Volume |
|
Type of Derivative |
|
Basis Reference |
2007
|
|
Condensate & Natural Gasoline
|
|
5,000 BBL/Month
|
|
Crude Oil Swap ($65.95)
|
|
NYMEX |
2007
|
|
Natural Gas
|
|
20,000 MMBTU/Month
|
|
Natural Gas Swap ($9.14)
|
|
Henry Hub |
2007
|
|
Natural Gas
|
|
20,000 MMBTU/Month
|
|
Natural Gas Basis Swap
(-$0.60)
|
|
Henry Hub to
Centerpoint East |
2007
|
|
Ethane
|
|
8,000 BBL/Month
|
|
Ethane Swap ($28.04)
|
|
Mt. Belvieu |
2008
|
|
Condensate & Natural Gasoline
|
|
5,000 BBL/Month
|
|
Crude Oil Swap ($66.20)
|
|
NYMEX |
2008
|
|
Natural Gas
|
|
30,000 MMBTU/Month
|
|
Natural Gas Swap ($8.12)
|
|
Houston Ship Channel |
2009
|
|
Condensate & Natural Gasoline
|
|
3,000 BBL/Month
|
|
Crude Oil Swap ($69.08)
|
|
NYMEX |
Our principal customers with respect to Prism Gas natural gas gathering and processing
services are large, natural gas marketing services, oil and gas producers and industrial end-users.
In addition, substantially all of our natural gas and NGL sales are made at market-based prices.
Our standard gas and NGL sales contracts contain adequate assurance provisions which allows for the
suspension of deliveries, cancellation of agreements or continuance of deliveries to the buyer
after the buyer provides security for payment in a form satisfactory to us. For additional
information regarding our hedging activities, please see Note 15 Commodity Cash Flow Hedges in
our Notes to Consolidated Financial Statements contained herein.
Interest Rate Risk
We are exposed to changes in interest rates as a result of our credit facility, which had a
weighted-average interest rate of 7.26% as of December 31, 2006. We had a total of $174.1 million
of indebtedness outstanding under our credit facility as of the date hereof of which $29.0 million
was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on
December 31, 2006, the impact of a 1% increase in interest rates on this amount of debt would
result in an increase in interest expense and a corresponding decrease in net income of
approximately $0.3 million annually.
As
of March 2, 2007, we had a total of $194 million of indebtedness outstanding under our
credit facility. The impact of a 1% increase in interest rates on this amount of unhedged floating
rate debt would result in an increase in interest expense, and a corresponding decrease in net
income of approximately $0.5 million annually.
- 71 -
Item 8. Financial Statements and Supplementary Data
The following financial statements of Martin Midstream Partners L.P. (Partnership):
|
|
|
|
|
|
|
Page |
|
|
|
73 |
|
|
|
|
|
|
|
|
|
74 |
|
|
|
|
|
|
|
|
|
75 |
|
|
|
|
|
|
|
|
|
76 |
|
|
|
|
|
|
|
|
|
77 |
|
|
|
|
|
|
|
|
|
78 |
|
|
|
|
|
|
|
|
|
79 |
|
|
|
|
|
|
|
|
|
80 |
|
- 72 -
Report of Independent Registered Public Accounting Firm
The Board of Directors
Martin Midstream GP LLC:
We have audited the accompanying consolidated balance sheets of Martin Midstream Partners L.P.
and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of
operations, changes in capital, comprehensive income, and cash flows for each of the years in the three-year period ended
December 31, 2006. These financial statements are the responsibility of Martin Midstreams
management. Our responsibility is to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with the standards of the Public Company 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 financial statements referred to above present fairly, in all material
respects, the consolidated financial position of Martin Midstream Partners L.P. and subsidiaries
and the results of their operations and their cash flows for each of the years in the three-year
period ended December 31, 2006, in conformity with accounting principles generally accepted in the
United States of America.
We also have audited, in accordance with the standards of the Public Accounting Oversight
Board (United States), the effectiveness of Martin Midstream Partners L.P. and subsidiaries
internal control over financial reporting as of December 31, 2006, based on criteria established in
Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated March 5, 2007 expressed an unqualified opinion on
managements assessment of, and the effective operation of, internal control over financial
reporting.
KPMG LLP
/s/ KPMG LLP
Shreveport, Louisiana
March 5, 2007
- 73 -
Report of Independent Registered Public Accounting Firm
The Board of Directors
Martin Midstream GP LLC:
We have audited managements assessment, included in the accompanying Managements Report on
Internal Control over Financial Reporting, that Martin Midstream Partners L.P. and subsidiaries
maintained effective internal control over financial reporting as of December 31, 2006, based on
criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Martin Midstreams 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 managements assessment and an opinion on the effectiveness of Martin Midstreams
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 managements 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 companys 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 U.S. generally accepted accounting
principles. A companys 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 U.S. 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 companys 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, managements assessment that Martin Midstream Partners L.P. and subsidiaries
maintained effective internal control over financial reporting as of December 31, 2006, is fairly
stated, in all material respects, based on criteria established in Internal ControlIntegrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Also, in our opinion, Martin Midstream Partners L.P. and subsidiaries maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2006, based on
criteria established in Internal ControlIntegrated 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 Martin Midstream Partners L.P.
and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of
operations, capital/equity, and cash flows for each of the three years ended December 31, 2006 and
our report dated March 5, 2007 expressed an unqualified opinion on those consolidated financial
statements.
/s/ KPMG LLP
KPMG LLP
Shreveport, Louisiana
March 5, 2007
- 74 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
|
(Dollars in thousands) |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash |
|
$ |
3,675 |
|
|
$ |
6,465 |
|
Accounts and other receivables, less
allowance for doubtful accounts of
$394 and $140 |
|
|
56,712 |
|
|
|
72,162 |
|
Product exchange receivables |
|
|
7,076 |
|
|
|
2,141 |
|
Inventories |
|
|
33,019 |
|
|
|
33,909 |
|
Due from affiliates |
|
|
1,330 |
|
|
|
1,475 |
|
Other current assets |
|
|
2,041 |
|
|
|
1,420 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
103,853 |
|
|
|
117,572 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant, and equipment, at cost |
|
|
323,967 |
|
|
|
235,218 |
|
Accumulated depreciation |
|
|
(76,122 |
) |
|
|
(59,505 |
) |
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
247,845 |
|
|
|
175,713 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill |
|
|
27,600 |
|
|
|
27,600 |
|
Investment in unconsolidated entities |
|
|
70,651 |
|
|
|
59,879 |
|
Other assets, net |
|
|
7,512 |
|
|
|
8,280 |
|
|
|
|
|
|
|
|
|
|
$ |
457,461 |
|
|
$ |
389,044 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Capital |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current installments of long-term debt |
|
$ |
74 |
|
|
$ |
9,104 |
|
Trade and other accounts payable |
|
|
53,450 |
|
|
|
67,387 |
|
Product exchange payables |
|
|
14,737 |
|
|
|
9,624 |
|
Due to affiliates |
|
|
10,474 |
|
|
|
3,492 |
|
Income taxes payable |
|
|
86 |
|
|
|
6,345 |
|
Other accrued liabilities |
|
|
3,876 |
|
|
|
3,617 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
82,697 |
|
|
|
99,569 |
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
174,021 |
|
|
|
192,200 |
|
Other long-term obligations |
|
|
2,218 |
|
|
|
1,710 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
258,936 |
|
|
|
293,479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners capital |
|
|
198,403 |
|
|
|
95,565 |
|
Accumulated other comprehensive income |
|
|
122 |
|
|
|
|
|
|
|
|
|
|
|
|
Total partners capital |
|
|
198,525 |
|
|
|
95,565 |
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
$ |
457,461 |
|
|
$ |
389,044 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
- 75 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(Dollars in thousands, except per unit amounts) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
24,182 |
|
|
$ |
23,081 |
|
|
$ |
17,919 |
|
Marine transportation |
|
|
47,835 |
|
|
|
35,451 |
|
|
|
34,780 |
|
Product sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas services |
|
|
389,735 |
|
|
|
301,676 |
|
|
|
203,427 |
|
Sulfur |
|
|
61,271 |
|
|
|
36,784 |
|
|
|
|
|
Fertilizer |
|
|
41,326 |
|
|
|
31,634 |
|
|
|
29,780 |
|
Terminalling and storage |
|
|
12,035 |
|
|
|
9,817 |
|
|
|
8,238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
504,367 |
|
|
|
379,911 |
|
|
|
241,445 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
576,384 |
|
|
|
438,443 |
|
|
|
294,144 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas services |
|
|
374,218 |
|
|
|
291,109 |
|
|
|
197,859 |
|
Sulfur |
|
|
38,898 |
|
|
|
25,657 |
|
|
|
|
|
Fertilizer |
|
|
36,267 |
|
|
|
26,975 |
|
|
|
25,342 |
|
Terminalling and storage |
|
|
9,787 |
|
|
|
8,079 |
|
|
|
6,775 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
459,170 |
|
|
|
351,820 |
|
|
|
229,976 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
65,387 |
|
|
|
46,888 |
|
|
|
34,475 |
|
Selling, general and administrative |
|
|
10,977 |
|
|
|
8,133 |
|
|
|
6,198 |
|
Depreciation and amortization |
|
|
17,597 |
|
|
|
12,642 |
|
|
|
8,766 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
553,131 |
|
|
|
419,483 |
|
|
|
279,415 |
|
|
|
|
|
|
|
|
|
|
|
Other operating income |
|
|
3,356 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
26,609 |
|
|
|
18,960 |
|
|
|
14,729 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated entities |
|
|
8,547 |
|
|
|
1,591 |
|
|
|
912 |
|
Interest expense |
|
|
(12,466 |
) |
|
|
(6,909 |
) |
|
|
(3,326 |
) |
Debt prepayment premium |
|
|
(1,160 |
) |
|
|
|
|
|
|
|
|
Other, net |
|
|
713 |
|
|
|
238 |
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense) |
|
|
(4,366 |
) |
|
|
(5,080 |
) |
|
|
(2,403 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
22,243 |
|
|
$ |
13,880 |
|
|
$ |
12,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income |
|
$ |
1,001 |
|
|
$ |
278 |
|
|
$ |
247 |
|
Limited partners interest in net income |
|
$ |
21,242 |
|
|
$ |
13,602 |
|
|
$ |
12,079 |
|
Net income per limited partner unit basic and diluted |
|
$ |
1.69 |
|
|
$ |
1.58 |
|
|
$ |
1.45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partner units basic |
|
|
12,602,000 |
|
|
|
8,583,634 |
|
|
|
8,349,551 |
|
Weighted average limited partner units diluted |
|
|
12,604,425 |
|
|
|
8,583,634 |
|
|
|
8,349,551 |
|
See accompanying notes to consolidated financial statements.
- 76 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL
For the years ended December 31, 2006, 2005 and 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners Capital |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General |
|
|
Accumulated |
|
|
|
|
|
|
Limited Partners |
|
|
Partner |
|
|
Comprehensive |
|
|
|
|
|
|
Common |
|
|
Subordinated |
|
|
|
|
|
|
Income |
|
|
|
|
|
|
Units |
|
|
Amount |
|
|
Units |
|
|
Amount |
|
|
Amount |
|
|
Amount |
|
|
Total |
|
|
|
(Dollars in thousands) |
|
Balances December 31, 2003 |
|
|
2,900,000 |
|
|
$ |
47,914 |
|
|
|
4,253,362 |
|
|
$ |
(1,996 |
) |
|
$ |
(26 |
) |
|
|
|
|
|
$ |
45,892 |
|
Net income |
|
|
|
|
|
|
5,923 |
|
|
|
|
|
|
|
6,156 |
|
|
|
247 |
|
|
|
|
|
|
|
12,326 |
|
Follow-on public offering |
|
|
1,322,500 |
|
|
|
34,016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34,016 |
|
General partner contribution |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
754 |
|
|
|
|
|
|
|
754 |
|
Cash distributions ($2.10 per unit) |
|
|
|
|
|
|
(8,173 |
) |
|
|
|
|
|
|
(8,932 |
) |
|
|
(349 |
) |
|
|
|
|
|
|
(17,454 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances December 31, 2004 |
|
|
4,222,500 |
|
|
|
79,680 |
|
|
|
4,253,362 |
|
|
|
(4,772 |
) |
|
|
626 |
|
|
|
|
|
|
|
75,534 |
|
Net income |
|
|
|
|
|
|
6,756 |
|
|
|
|
|
|
|
6,846 |
|
|
|
278 |
|
|
|
|
|
|
|
13,880 |
|
Units issued in connection with Prism Gas
acquisition |
|
|
756,480 |
|
|
|
24,616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24,616 |
|
Conversion of subordinated units to common units |
|
|
850,672 |
|
|
|
(1,599 |
) |
|
|
(850,672 |
) |
|
|
1,599 |
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner contribution |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
502 |
|
|
|
|
|
|
|
502 |
|
Cash distributions ($2.19 per unit) |
|
|
|
|
|
|
(9,247 |
) |
|
|
|
|
|
|
(9,315 |
) |
|
|
(405 |
) |
|
|
|
|
|
|
(18,967 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances December 31, 2005 |
|
|
5,829,652 |
|
|
|
100,206 |
|
|
|
3,402,690 |
|
|
|
(5,642 |
) |
|
|
1,001 |
|
|
|
|
|
|
|
95,565 |
|
Net income |
|
|
|
|
|
|
16,030 |
|
|
|
|
|
|
|
5,212 |
|
|
|
1,001 |
|
|
|
|
|
|
|
22,243 |
|
Follow-on public offering |
|
|
3,450,000 |
|
|
|
95,272 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
95,272 |
|
Issuance of common units |
|
|
470,484 |
|
|
|
15,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,000 |
|
General partner contribution |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,358 |
|
|
|
|
|
|
|
2,358 |
|
Conversion of subordinated units to common units |
|
|
850,672 |
|
|
|
(2,495 |
) |
|
|
(850,672 |
) |
|
|
2,495 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit-based compensation |
|
|
3,000 |
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24 |
|
Cash distributions ($2.44 per unit) |
|
|
|
|
|
|
(22,650 |
) |
|
|
|
|
|
|
(8,302 |
) |
|
|
(1,107 |
) |
|
|
|
|
|
|
(32,059 |
) |
Commodity hedging gains reclassified to earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2 |
|
Adjustment in fair value of derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
120 |
|
|
|
120 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances December 31, 2006 |
|
|
10,603,808 |
|
|
$ |
201,387 |
|
|
|
2,552,018 |
|
|
$ |
(6,237 |
) |
|
$ |
3,253 |
|
|
$ |
122 |
|
|
$ |
198,525 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
- 77 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(Dollars in thousands) |
|
Net income |
|
$ |
22,243 |
|
|
$ |
13,880 |
|
|
$ |
12,326 |
|
Changes in fair values of commodity cash flow hedges |
|
|
370 |
|
|
|
|
|
|
|
|
|
Commodity hedging gains reclassified to earnings |
|
|
2 |
|
|
|
|
|
|
|
|
|
Changes in fair value of interest rate cash flow hedges |
|
|
(250 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
22,365 |
|
|
$ |
13,880 |
|
|
$ |
12,326 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
- 78 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(Dollars in thousands) |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
22,243 |
|
|
$ |
13,880 |
|
|
$ |
12,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
17,597 |
|
|
|
12,642 |
|
|
|
8,766 |
|
Amortization of deferred debt issue costs |
|
|
1,040 |
|
|
|
600 |
|
|
|
886 |
|
(Gain) loss on disposition or sale of property, plant, and equipment |
|
|
(231 |
) |
|
|
(37 |
) |
|
|
48 |
|
(Gain) loss on involuntary conversion of property, plant, and equipment |
|
|
(3,125 |
) |
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated entities |
|
|
(8,547 |
) |
|
|
(1,591 |
) |
|
|
(912 |
) |
Distributions from unconsolidated entities |
|
|
541 |
|
|
|
231 |
|
|
|
|
|
Distribution in-kind from equity investments |
|
|
8,311 |
|
|
|
1,115 |
|
|
|
|
|
Non-cash mark-to-market on derivatives |
|
|
(389 |
) |
|
|
(555 |
) |
|
|
|
|
Other |
|
|
24 |
|
|
|
|
|
|
|
|
|
Change in current assets and liabilities, excluding effects of
acquisitions and dispositions: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts and other receivables |
|
|
13,763 |
|
|
|
(10,565 |
) |
|
|
(16,499 |
) |
Product exchange receivables |
|
|
(4,935 |
) |
|
|
(1,974 |
) |
|
|
1,733 |
|
Inventories |
|
|
890 |
|
|
|
(4,474 |
) |
|
|
(3,502 |
) |
Due from affiliates |
|
|
145 |
|
|
|
417 |
|
|
|
(1,730 |
) |
Other current assets |
|
|
115 |
|
|
|
36 |
|
|
|
32 |
|
Trade and other accounts payable |
|
|
(13,937 |
) |
|
|
27,669 |
|
|
|
9,171 |
|
Product exchange payables |
|
|
5,113 |
|
|
|
(8,238 |
) |
|
|
1,859 |
|
Due to affiliates |
|
|
6,982 |
|
|
|
3,063 |
|
|
|
(131 |
) |
Other accrued liabilities |
|
|
(5,912 |
) |
|
|
(496 |
) |
|
|
765 |
|
Change in other non-current assets and liabilities, net |
|
|
(371 |
) |
|
|
611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
39,317 |
|
|
|
32,334 |
|
|
|
12,812 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Payments for property, plant, and equipment |
|
|
(66,352 |
) |
|
|
(24,814 |
) |
|
|
(5,182 |
) |
Acquisitions, net of cash acquired |
|
|
(24,306 |
) |
|
|
(114,167 |
) |
|
|
(31,234 |
) |
Proceeds from sale of property, plant, and equipment |
|
|
1,825 |
|
|
|
95 |
|
|
|
114 |
|
Insurance proceeds from involuntary conversion of property, plant and equipment |
|
|
4,812 |
|
|
|
|
|
|
|
|
|
Return of investments from unconsolidated entities |
|
|
433 |
|
|
|
466 |
|
|
|
1,980 |
|
Investments in unconsolidated entities |
|
|
(11,510 |
) |
|
|
(322 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(95,098 |
) |
|
|
(138,742 |
) |
|
|
(34,322 |
) |
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Payments of long-term debt |
|
|
(163,010 |
) |
|
|
(134,091 |
) |
|
|
(43,215 |
) |
Net proceeds from follow on public offering |
|
|
95,272 |
|
|
|
|
|
|
|
34,016 |
|
General partner contribution |
|
|
2,358 |
|
|
|
502 |
|
|
|
754 |
|
Proceeds from long-term debt |
|
|
135,801 |
|
|
|
250,900 |
|
|
|
49,215 |
|
Payments of debt issuance costs |
|
|
(371 |
) |
|
|
(3,655 |
) |
|
|
(892 |
) |
Cash distributions paid |
|
|
(32,059 |
) |
|
|
(18,967 |
) |
|
|
(17,454 |
) |
Proceeds from issuance of common units |
|
|
15,000 |
|
|
|
15,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
52,991 |
|
|
|
109,689 |
|
|
|
22,424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
(2,790 |
) |
|
|
3,281 |
|
|
|
914 |
|
Cash at beginning of period |
|
|
6,465 |
|
|
|
3,184 |
|
|
|
2,270 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash at end of period |
|
$ |
3,675 |
|
|
$ |
6,465 |
|
|
$ |
3,184 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash: |
|
|
|
|
|
|
|
|
|
|
|
|
Financed portion of non-compete agreement |
|
$ |
|
|
|
$ |
690 |
|
|
$ |
398 |
|
|
|
|
|
|
|
|
|
|
|
Common units issued for acquisitions |
|
$ |
|
|
|
$ |
9,616 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
- 79 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(1) ORGANIZATION AND DESCRIPTION OF BUSINESS
Martin Midstream Partners L.P. (the Partnership) is a publicly traded limited partnership
which provides terminalling and storage services for petroleum products and by-products, natural
gas gathering, processing and NGL distribution, marine transportation services for petroleum
products and by-products, sulfur gathering, processing and distribution and fertilizer
manufacturing and marketing.
On November 10, 2005, the Partnership acquired Prism Gas Systems I, L.P. (Prism Gas) which
is engaged in the gathering, processing and marketing of natural gas and natural gas liquids,
predominantly in Texas and northwest Louisiana. Through the acquisition of Prism Gas, the
Partnership also acquired 50% ownership interest in Waskom Gas Processing Company (Waskom), the
Matagorda Offshore Gathering System (Matagorda), and the Panther Interstate Pipeline Energy LLC
(PIPE) each accounted for under the equity method of accounting.
In April 2005, the Partnership began another primary line of business for sulfur marketing and
distribution through the acquisition of the operating assets of Bay Sulfur Company, including a
sulfur priller in Stockton, California. In January, 2006, an additional sulfur priller began
production at the Partnerships Neches facility in Beaumont, Texas. On July 15, 2005 the
Partnership acquired all of the outstanding partnership interests of CF Martin Sulphur, L.P. (CF
Martin Sulfur) not owned by the Partnership. As a result, CF Martin Sulphur has been consolidated
in the Partnerships consolidated financial statements and in the Partnerships sulfur segment.
Prior to the acquisition, the Partnership owned an unconsolidated non-controlling 49.5% limited
partnership interest in CF Martin Sulphur. The sulfur segment will include the marketing,
transportation, terminalling and storage, processing and distribution of molten and pelletized
sulfur.
The petroleum products and by-products the Partnership collects, transports, stores and
distributes are produced primarily by major and independent oil and gas companies who often turn to
third parties, such as the Partnership, for the transportation and disposition of these products.
In addition to these major and independent oil and gas companies, our primary customers include
independent refiners, large chemical companies, fertilizer manufacturers and other wholesale
purchasers of these products. The Partnership operates primarily in the Gulf Coast region of the
United States, which is a major hub for petroleum refining, natural gas gathering and processing
and support services for the exploration and production industry.
(2) SIGNIFICANT ACCOUNTING POLICIES
(a) Principles of Presentation and Consolidation
The consolidated financial statements include the financial statements of the Partnership and
its wholly-owned subsidiaries and equity method investees. In the opinion of the management of the
Partnerships general partner, all adjustments and elimination of significant intercompany balances
necessary for a fair presentation of the Partnerships results of operations, financial position
and cash flows for the periods shown have been made. All such adjustments are of a normal
recurring nature. In addition, the Partnership evaluates its relationships with other entities to
identify whether they are variable interest entities as defined by FASB Interpretation No 46(R)
Consolidation of Variable Interest Entities (FIN 46R) and to assess whether it is the primary
beneficiary of such entities. If the determination is made that the Partnership is the primary
beneficiary, then that entity is included in the consolidated financial statements in accordance
with FIN 46(R). No such variable interest entities exist as of December 31, 2006 or 2005.
(b) Product Exchanges
The Partnership enters into product exchange agreements with third parties whereby the
Partnership agrees to exchange NGLs and sulfur with third parties. The Partnership records the
balance of NGLs due to other companies under these agreements at quoted market product prices and
the balance of NGLs and sulfur due from other companies at the lower of cost or market. Cost is
determined using the first-in, first-out (FIFO) method.
- 80 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(c) Inventories
Inventories are stated at the lower of cost or market. Cost is determined by using the FIFO
method for all inventories.
(d) Revenue Recognition
Terminalling and storage - Revenue is recognized for storage contracts based on the contracted
monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved
through the Partnerships terminals at the contracted rate. When lubricants and drilling fluids
are sold by truck, revenue is recognized upon delivering product to the customers as title to the
product transfers when the customer physically receives the product.
Natural gas services - Natural gas gathering and processing revenues are recognized when title
passes or service is performed. NGL distribution revenue is recognized when product is delivered
by truck to the Partnerships NGL customers, which occurs when the customer physically receives the
product. When product is sold in storage, or by pipeline, the Partnership recognizes NGL
distribution revenue when the customer receives the product from either the storage facility or
pipeline.
Marine transportation - Revenue is recognized for contracted trips upon completion of the
particular trip. For time charters, revenue is recognized based on a per day rate.
Sulfur and Fertilizer - Revenue is recognized when the customer takes title to the product,
either at the Partnerships plant or the customer facility.
(e) Equity Method Investments
The Partnership uses the equity method of accounting for investments in unconsolidated
entities where the ability to exercise significant influence over such entities exists.
Investments in unconsolidated entities consist of capital contributions and advances plus the
Partnerships share of accumulated earnings as of the entities latest fiscal year-ends, less
capital withdrawals and distributions. Investments in excess of the underlying net assets of
equity method investees, specifically identifiable to property, plant and equipment, are amortized
over the useful life of the related assets. Excess investment representing equity method goodwill
is not amortized but is evaluated for impairment, annually. Under the provisions of Statement of
Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets, this
goodwill is not subject to amortization and is accounted for as a component of the investment.
Equity method investments are subject to impairment under the provisions of Accounting Principles
Board (APB) Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. No
portion of the net income from these entities is included in the Partnerships operating income.
Prior to July 15, 2005, the Partnership used the equity method of accounting for its
unconsolidated non-controlling 49.5% limited partner interest in CF Martin Sulphur. On July 15,
2005, the Partnership acquired the remaining interests in CF Martin Sulphur not previously owned by
it. Subsequent to the acquisition, CF Martin Sulphur is included in the consolidated financial
presentation of the Partnerships sulfur segment
Following the Partnerships acquisition of Prism Gas Systems I, L.P. (Prism Gas) in November
2005, the Partnership owns an unconsolidated 50% interest in Waskom Gas Processing Company
(Waskom), the Matagorda Offshore Gathering System (Matagorda), and Panther Interstate Pipeline
Energy LLC (PIPE). As a result, these assets are accounted for by the equity method and the
Partnership does not include any portion of their net income in operating income.
On June 30, 2006, the Partnership, through the Partnerships Prism Gas subsidiary, acquired a
20% ownership interest in a partnership which owns the lease rights to the assets of the Bosque
County Pipeline (BCP). This interest is accounted for by the equity method of accounting.
- 81 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(f) Property, Plant, and Equipment
Owned property, plant, and equipment is stated at cost, less accumulated depreciation. Owned
buildings and equipment are depreciated using straight-line method over the estimated lives of the
respective assets.
Routine maintenance and repairs are charged to operating expense while costs of betterments
and renewals are capitalized. When an asset is retired or sold, its cost and related accumulated
depreciation are removed from the accounts and the difference between net book value of the asset
and proceeds from disposition is recognized as gain or loss.
(g) Goodwill and Other Intangible Assets
Goodwill represents the excess of costs over fair value of assets of businesses acquired.
Goodwill and intangible assets acquired in a purchase business combination and determined to have
an indefinite useful life are not amortized, but instead tested for impairment at least annually in
accordance with the provisions of SFAS No. 142, Goodwill and Other Intangible Assets. Intangible
assets with estimated useful lives are amortized over their respective estimated useful lives to
their estimated residual values, and reviewed for impairment in accordance with FASB Statement No.
144 (SFAS No. 144), Accounting for Impairment or Disposal of Long-Lived Assets. Other intangible assets
primarily consists of covenants not-to-compete obtained through business combinations and are being
amortized over the life of the respective agreements.
(h) Debt Issuance Costs
In connection with the Partnerships multi-bank credit facility, on November 10, 2005, it
incurred debt issuance costs of $3,258. In connection with the amendment and expansion of the
Partnerships multi-bank credit facility on June 30, 2006, it incurred debt issuance costs of $372.
These debt issuance costs, along with the remaining unamortized deferred issuance costs relating
to the line of credit facility as of November 10, 2005 which remain deferred, are amortized over
the 60 month term of the new debt arrangement.
Amortization of debt issuance cost, which are included in interest expense for the years ended
December 31, 2006, 2005 and 2004, totaled $1,040, $600, and $886, respectively, and accumulated
amortization amounted to $3,091 and $2,050 at December 31, 2006 and 2005, respectively. The
unamortized balance of debt issuance costs, classified as other assets amounted to $4,169 and
$4,838 at December 31, 2006 and 2005, respectively.
(i) Impairment of Long-Lived Assets
In accordance with SFAS No. 144, long-lived assets, such as property, plant and equipment, are
reviewed for impairment whenever events or changes in circumstances indicate that the carrying
amount of an asset may not be recoverable. Recoverability of assets to be held and used is
measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash
flows expected to be generated by the asset. If the carrying amount of an asset exceeds its
estimated future cash flows, an impairment charge is recognized by the amount by which the carrying
amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be
separately presented in the balance sheet and reported at the lower of the carrying amount or fair
value less costs to sell, and are no longer depreciated. The assets and liabilities of a disposed
group classified as held for sale would be presented separately in the appropriate asset and
liability sections of the balance sheet. Goodwill is tested annually for impairment, and is tested
for impairment more frequently if events and circumstances indicate that the asset might be
impaired. An impairment loss is recognized to the extent that the carrying amount exceeds the
assets fair value. This determination is made at the reporting unit level and consists of two
steps. First, the Partnership determines the fair value of a reporting unit and compares it to its
carrying amount. Second, if the carrying amount of a reporting unit exceeds its fair value, an
impairment loss is recognized for any excess of the carrying amount of the reporting units
goodwill over the implied fair value of that goodwill. The implied fair value of goodwill is
determined by allocating the fair value of the reporting unit in a manner similar to a purchase
price allocation, in accordance with FASB Statement No. 141, Business Combinations. The residual
fair value after this allocation is the implied fair value of the reporting unit goodwill.
- 82 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
The Partnership performed its annual tests in the third quarters of 2004, 2005 and 2006, with
no indication of impairment.
(j) Asset Retirement Obligation
Under SFAS No. 143, Accounting for Asset Retirement Obligations (Statement No. 143) which
provides accounting requirements for costs associated with legal obligations to retire tangible,
long-lived assets, the Partnership records an Asset Retirement Obligation (ARO) at fair value in
the period in which it is incurred by increasing the carrying amount of the related long-lived
asset. In each subsequent period, the liability is accreted over time towards the ultimate
obligation amount and the capitalized costs are depreciated over the useful life of the related
asset.
On March 31, 2005, the Financial Accounting Standards Board issued Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of SFAS
143. FIN 47, which was effective for fiscal years ending after December 15, 2005, clarifies that
the recognition and measurement provisions of SFAS 143 apply to asset retirement obligations in
which the timing or method of settlement may be conditional on a future event that may or may not
be within the control of the entity. The Partnerships fixed assets include land, buildings,
transportation equipment, storage equipment, marine vessels and operating equipment.
The transportation equipment includes pipelines system. The Partnership transports NGLs
through the pipeline system and gathering system. The Partnership also gathers natural gas from
wells owned by producers and deliver natural gas and NGLs on the Partnerships pipeline systems,
primarily in Texas and Louisiana to the fractionation facility of the Partnerships 50% owned joint
venture. The Partnership is obligated by contractual or regulatory requirements to remove certain
facilities or perform other remediation upon retirement of the Partnerships assets. However, the
Partnership is not able to reasonably determine the fair value of the asset retirement obligations
for the Partnerships trunk and gathering pipelines and the Partnerships surface facilities, since
future dismantlement and removal dates are indeterminate. In order to determine a removal date of
the Partnerships gathering lines and related surface assets, reserve information regarding the
production life of the specific field is required. As a transporter and gatherer of natural gas,
the Partnership is not a producer of the field reserves, and the Partnership therefore does not
have access to adequate forecasts that predict the timing of expected production for existing
reserves on those fields in which the Partnership gathers natural gas. In the absence of such
information, the Partnership is not able to make a reasonable estimate of when future dismantlement
and removal dates of the Partnerships gathering assets will occur. With regard to the
Partnerships trunk pipelines and their related surface assets, it is impossible to predict when
demand for transportation of the related products will cease. The Partnerships right-of-way
agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, the
Partnership can evaluate the Partnerships trunk pipelines for alternative uses, which can be and
have been found. The Partnership will record such asset retirement obligations in the period in
which more information becomes available for us to reasonably estimate the settlement dates of the
retirement obligations.
(k) Derivative Instruments and Hedging Activities
In accordance with Statement of Financial Accounting Standards No. 133 (SFAS No. 133),
Accounting for Derivative Instruments and Hedging Activities, all derivatives and hedging
instruments are included on the balance sheet as an asset or liability measured at fair value and
changes in fair value are recognized currently in earnings unless specific hedge accounting
criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be
offset against the change in the fair value of the hedged item through earnings or recognized in
other comprehensive income until such time as the hedged item is recognized in earnings. In early
2006, the Partnership adopted a hedging policy that allows it to use hedge accounting for financial
transactions that are designated as hedges.
Derivative instruments not designated as hedges are being marked to market with all market
value adjustments being recorded in the consolidated statements of operations. As of December 31,
2006, the Partnership has designated a portion of its derivative instruments as qualifying cash
flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income
as a component of equity.
- 83 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(l) Comprehensive Income
Comprehensive income includes net income and other comprehensive income. Other comprehensive
income for the partnership includes unrealized gains and losses on derivative financial
instruments. In accordance with SFAS No. 133, the partnership records deferred hedge gains and
losses on its derivative financial instruments that qualify as cash flow hedges as other
comprehensive income.
(m) Unit Grants
In January 2006, the Partnership issued 1,000 restricted units to each of its three
independent, non-employee directors under its long-term incentive plan. These units vest in 25%
increments on the anniversary of the grant date each year and will be fully vested in January 2010.
The Partnership accounts for the transaction under Emerging Issues Task Force 96-18 Accounting
for Equity Instruments That are Issued to other than Employees For Acquiring, or in Conjunction
with Selling, Goods or Services. The cost resulting from the share-based payment transactions was
$24 for the year ended December 31, 2006. The Partnerships general partner contributed $2 in cash
to the Partnership in conjunction with the issuance of these restricted units in order to maintain
its 2% general partner interest in the Partnership.
(n) Incentive Distribution Rights
The Partnerships general partner, Martin Midstream GP LLC, holds a 2% general partner
interest and certain incentive distribution rights in the Partnership. Incentive distribution
rights represent the right to receive an increasing percentage of cash distributions after the
minimum quarterly distribution, any cumulative arrearages on common units, and certain target
distribution levels have been achieved. The Partnership is required to distribute all of its
available cash from operating surplus, as defined in the partnership agreement. The target
distribution levels entitle the general partner to receive 15% of quarterly cash distributions in
excess of $0.55 per unit until all unit holders have received $0.625 per unit, 25% of quarterly
cash distributions in excess of $0.625 per unit until all unit holders have received $0.75 per
unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the years ended
December 31, 2006, 2005 and 2004, the general partner received $537, $0 and $0 in incentive
distributions.
(o) Net Income per Unit
Except as discussed in the following paragraph, basic and diluted net income per limited
partner unit is determined by dividing net income after deducting the amount allocated to the
general partner interest (including its incentive distribution in excess of its 2% interest) by the
weighted average number of outstanding limited partner units during the period. Subject to
applicability of Emerging Issues Task Force Issue No. 03-06 (EITF 03-06), Participating
Securities and the Two-Class Method under FASB Statement No. 128, as discussed below, Partnership
income is first allocated to the general partner based on the amount of incentive distributions.
The remainder is then allocated between the limited partners and general partner based on
percentage ownership in the Partnership.
EITF 03-06 addresses the computation of earnings per share by entities that have issued
securities other than common stock that contractually entitle the holder to participate in
dividends and earnings of the entity when, and if, it declares dividends on its common stock.
Essentially, EITF 03-06 provides that in any accounting period where the Partnerships aggregate
net income exceeds the Partnerships aggregate distribution for such period, the Partnership is
required to present earnings per unit as if all of the earnings for the periods were distributed,
regardless of the pro forma nature of this allocation and whether those earnings would actually be
distributed during a particular period from an economic or practical perspective. EITF 03-06 does
not impact the Partnerships overall net income or other financial results; however, for periods in
which aggregate net income exceeds the Partnerships aggregate distributions for such period, it
will have the impact of reducing the earnings per limited partner unit. This result occurs as a
larger portion of the Partnerships aggregate earnings is allocated to the incentive distribution
rights held by the Partnerships general partner, as if distributed, even though the Partnership
makes cash distributions on the basis of cash available for distributions, not earnings, in any
given accounting period. In
- 84 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
accounting periods where aggregate net income does not exceed the
Partnerships aggregate distributions for such period, EITF 03-06 does not have any impact on the
Partnerships earnings per unit calculation.
The weighted average units outstanding for basic net income per unit were 12,602,000,
8,583,634 and 8,349,551 for years ended December 31, 2006, 2005 and 2004, respectively. For
diluted net income per unit, the weighted average units outstanding were increased by 2,425 for the
year ended December 31, 2006 due to the dilutive effect of restricted units granted under the
Partnerships long-term incentive plan.
(p) Reclassifications
The Partnership converted to a new accounting system in August 2005. In connection with its
system conversion, the Partnership closely examined expense classifications for the new system.
Upon review, it was determined that certain payroll, property insurance and property tax expenses
that were previously categorized as selling, general and administrative expenses would be more
appropriately classified as operating expenses. As a result, those expenses were set up in the new
system with the new classification. Accordingly, it was necessary for the Partnership to
reclassify the prior period to conform to the current presentation.
These reclassifications, as detailed below, had no impact on the prior years operating income
or net income. The following table sets forth the effects of the reclassification on certain line
items within the Partnerships previously reported consolidated statements of income for year ended
December 31, 2004.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling |
|
|
|
|
|
|
|
|
|
|
|
|
and Storage |
|
NGL |
|
Marine |
|
Fertilizer |
|
SG&A |
|
Total |
Year Ended December 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (as previously
reported) |
|
$ |
6,775 |
|
|
$ |
197,859 |
|
|
$ |
|
|
|
$ |
25,207 |
|
|
$ |
|
|
|
$ |
229,841 |
|
Cost of products sold (as
Reclassified) |
|
|
6,775 |
|
|
|
197,859 |
|
|
|
|
|
|
|
25,342 |
|
|
|
|
|
|
|
229,976 |
|
Operating expenses (as previously
reported) |
|
|
6,699 |
|
|
|
928 |
|
|
|
24,796 |
|
|
|
|
|
|
|
|
|
|
|
32,423 |
|
Operating expenses (as reclassified) |
|
|
8,494 |
|
|
|
1,185 |
|
|
|
24,796 |
|
|
|
|
|
|
|
|
|
|
|
34,475 |
|
Selling, general and administrative (as
previously reported) |
|
|
2,194 |
|
|
|
1,457 |
|
|
|
175 |
|
|
|
1,793 |
|
|
|
2,766 |
|
|
|
8,385 |
|
Selling, general and administrative (as
Reclassified) |
|
|
399 |
|
|
|
1,200 |
|
|
|
175 |
|
|
|
1,658 |
|
|
|
2,766 |
|
|
|
6,198 |
|
(q) Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses are incurred by Martin Resource
Management Corporation (Martin Resource Management) and allocated to the Partnership to cover
costs of centralized corporate functions such as accounting, treasury, engineering, information
technology, risk management and other corporate services. Such expenses are based on the
percentage of time spent by Martin Resource Managements personnel that provide such centralized
services. Subsequent to November 1, 2002, under an omnibus agreement between the Partnership and
Martin Resource Management, the amount the Partnership is required to reimburse Martin Resource
Management for indirect general and administrative expenses and corporate overhead allocated to the
Partnership was capped at $1,000 during the first year of the agreement. For the year ending
October 31, 2004, the cap was increased to $2,000. Subsequently, the capped amount may be
increased by no more than the percentage increase in the consumer price index for the applicable
year. In addition, the Partnerships general partner has the right to agree to further increases
in connection with expansions of the Partnerships operations through the acquisition or
construction of new assets or businesses.
(r) Environmental Liabilities
The Partnerships policy is to accrue for losses associated with environmental remediation
obligations when such losses are probable and reasonably estimable. Accruals for estimated losses
from environmental remediation obligations generally are recognized no later than completion of the
remedial feasibility study. Such accruals are adjusted as further information develops or
circumstances change. Costs of future expenditures for environmental remediation obligations are
not discounted to their present value.
- 85 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(s) Allowance for Doubtful Accounts.
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The
allowance for doubtful accounts is the Partnerships best estimate of the amount of probable credit
losses in the Partnerships existing accounts receivable.
(t) Use of Estimates
Management has made a number of estimates and assumptions relating to the reporting of assets
and liabilities and the disclosure of contingent assets and liabilities to prepare these
consolidated financial statements in conformity with accounting principles generally accepted in
the United States of America. Actual results could differ from those estimates.
(u) Income Taxes
The
operations of the Partnership are not subject to income taxes, except
for the Texas margin tax as described in the following paragraph, and as a result, the
Partnerships income is taxed directly to its owners. As a result of its acquisition of Prism Gas,
the Partnership assumed a current tax liability of $6.3 million as a result of a tax event
triggered by the transfer of the ownership of the assets of Prism Gas in 2005 from a corporate to a
partnership structure through the partial liquidation of the corporation. This liability was paid
in 2006.
On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which
restructures the state business tax by replacing the taxable capital and earned surplus components
of the current franchise tax with a new taxable margin component. Since the tax base on the
Texas margin tax is derived from an income-based measure, the margin tax is construed as an income
tax and, therefore, the provisions of SFAS 109 regarding the recognition of deferred taxes apply to
the new margin tax. In accordance with SFAS 109, the effect on deferred tax assets of a change in
tax law should be included in tax expense attributable to continuing operations in the period that
includes the enactment date. Therefore, the Partnership has calculated its deferred tax assets
and liabilities for Texas based on the new margin tax. The cumulative effect of the change was
immaterial. The impact of the change in deferred tax assets does not have a material impact on tax
expense. There was no income tax expense recorded for the year ended December 31, 2006.
Beginning 2007, the Partnership anticipates it will incur tax expense related to this new Texas
margin tax.
(3) IMPACT OF RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In September 2006, the FASB issued FAS 157, which will become effective for the Partnership on
January 1, 2008. This standard defines fair value, establishes a framework for measuring fair
value and expands disclosures about fair value measurements. The Statement does not require any
new fair value measurements but would apply to assets and liabilities that are required to be
recorded at fair value under other accounting standards. The impact, if any, to the Partnership
from the adoption of FAS 157 in 2008 will depend on the Partnerships assets and liabilities at
that time that are required to be measured at fair value.
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No.
108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current
Year Financial Statements, (SAB 108). SAB 108 addresses how the effects of prior year uncorrected
misstatements should be considered when quantifying misstatements in current year financial
statements. SAB 108 requires companies to quantify misstatements using a balance sheet approach
and income statement approach and to evaluate whether either approach results in quantifying an
error that is material in light of the relevant quantitative and qualitative factors. SAB 108 is
effective for fiscal years ending on or after November 15, 2006.
SAB 108 did not have an effect on the Partnerships consolidated financial statements.
- 86 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
In September 2005, the FASBs Emerging Issues Task Force (EITF) issued EITF No. 04-13,
Accounting for Purchases and Sales of Inventory with the Same Counterparty. This pronouncement
provides additional accounting guidance for situations involving inventory exchanges between
parties to that contained in APB Opinion no. 29, Accounting for Nonmonetary Transactions and SFAS
153, Exchanges of Nonmonetary Assets. The standard
is effective for new arrangements entered into in reporting periods beginning after March 15,
2006. The adoption did not have a material impact on the Partnerships consolidated financial
statements.
In May 2005, the FASB, as part of an effort to conform to international accounting standards,
issued SFAS No. 154, Accounting Changes and Error Corrections, or SFAS No. 154, which was
effective for the Partnership beginning on January 1, 2006. SFAS No. 154 requires that all
voluntary changes in accounting principles be retrospectively applied to prior financial statements
as if that principle had always been used, unless it is impracticable to do so. When it is
impracticable to calculate the effects on all prior periods, SFAS No. 154 requires that the new
principle be applied to the earliest period practicable. The adoption of SFAS No. 154 did not have
a material effect on the Partnerships consolidated financial statements.
(4) ACQUISITIONS
(a) Asphalt Terminals. In August 2006 and October 2006, respectively, the Partnership
acquired the assets of Gulf States Asphalt Company LP and Prime Materials and Supply Corporation
(Prime), for $4,842 of which $4,679 was allocated to property, plant and equipment and $163 to a
non-compete agreements. The assets are located in Houston, Texas and Port Neches, Texas. The
Partnership entered into an agreement with Martin Resource Management, which Martin Resource
Management will operate the facilities through a terminalling service agreement based upon
throughput rates and will assume all additional expenses to operate the facility.
(b) Corpus Christi Barge Terminal. In July 2006, the Partnership acquired a marine terminal
located near Corpus Christi, Texas and associated assets from Koch Pipeline Company, LP for $6,200
which was all allocated to property, plant and equipment. The terminal is located on approximately
25 acres of land, and includes three tanks with a combined shell capacity of approximately 240,000
barrels, pump and piping infrastructure for truck unloading and product delivery to two oil docks,
and there are several pumps, controls, and an office building on site for administrative use.
(c) Marine Vessels. In November 2006, the Partnership acquired the La Force, an offshore tug,
for $6,001 from a third party. This vessel is a 5,100 horse power offshore tug that was rebuilt in
1999 with new engines installed in 2005.
In January 2006, the Partnership acquired the Texan, an offshore tug, and the Ponciana, an
offshore NGL barge, for $5,850 from Martin Resource Management. The acquisition price was based on
a third-party appraisal. In March 2006, these vessels went into service under a long term charter
with a third party. In February 2006, the Partnership acquired the M450, an offshore barge, for
$1,551 from a third party. In March 2006, this vessel went into service under a one-year charter
with an affiliate of Martin Resource Management.
(d) A & A Fertilizer, Ltd. In December 2005, the Partnership completed the purchase of the
net operating assets of A & A Fertilizer for $5,667. A & A Fertilizer is a manufacturer and
distributor of liquid sulfur based fertilizer products to the continental United States. The A & A
Fertilizer manufacturing facility is located at the Partnerships Port Neches deep-water marine
terminal near Beaumont, Texas. This acquisition is reported in the Partnerships fertilizer
segment.
The purchase price of $5,667, including non-competition agreements in other assets of $691,
was allocated as follows:
- 87 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
|
|
|
|
|
Current assets |
|
$ |
955 |
|
Property, plant and equipment, net |
|
|
5,448 |
|
Other assets |
|
|
691 |
|
Current liabilities |
|
|
(891 |
) |
Other liabilities |
|
|
(536 |
) |
|
|
|
|
Total |
|
$ |
5,667 |
|
|
|
|
|
(e) Prism Gas Acquisition. In November 2005 the Partnership acquired Prism Gas. As of
November 2005, Prism Gas had ownership interests in over 330 miles of natural gas gathering
pipelines located in the natural gas producing regions of East Texas, Northwest Louisiana, the
Texas Gulf Coast and offshore Texas and federal waters in the Gulf of Mexico as well as a 150 MMcfd
capacity natural gas processing plant located in East Texas. The fair market value of the assets
acquired were appraised at $93,938. The excess of the fair value over the carrying value of the
assets was allocated to all identifiable assets. After recording all identifiable assets at their
fair values, the remaining $20,145 was recorded as goodwill. The goodwill was a result of Prism
Gas strategically located assets combined with the Partnerships access to capital and existing
infrastructure. This will enhance the Partnerships ability to offer additional gathering and
processing services to customers through internal growth projects including natural gas processing,
fractionation and pipeline expansions as well as new pipeline construction. In accordance with FAS
142, the goodwill will not be amortized but tested for impairment.
The selling parties in this transaction were Natural Gas Partners V, L.P. and certain members
of the Prism Gas management team. The final purchase price was $93,938. The purchase price was
funded by $63,052 in borrowings under the Partnerships credit facility, $5,000 in a previously
funded escrow account, $15,502 in new equity capital provided by Martin Resource Management, $9,616
in seller financing, and $768 in capital provided by Martin Resource Management for acquisition
costs and to maintain its 2% general partner interest in the Partnership.
The purchase price of $93,938, including two-year non-competition agreements included in other
assets of $600, was allocated as follows:
|
|
|
|
|
Current assets |
|
$ |
4,449 |
|
Other current assets |
|
|
10,772 |
|
Property, plant and equipment, net |
|
|
17,810 |
|
Investment in unconsolidated entities |
|
|
60,000 |
|
Other assets |
|
|
942 |
|
Goodwill |
|
|
20,145 |
|
Current liabilities |
|
|
(19,901 |
) |
Other liabilities |
|
|
(279 |
) |
|
|
|
|
Total |
|
$ |
93,938 |
|
|
|
|
|
The following table presents unaudited pro forma financial information incorporating the
historical (pre-acquisition) financial results of Prism Gas. This information has been prepared as
if the acquisition of Prism Gas had been completed on January 1 of the respective periods presented
as opposed to the actual date that the acquisition occurred. The pro forma information is based
upon data currently available and certain estimates and assumptions made by management. As a
result, this information is not necessarily indicative of the financial results had the
transactions actually occurred on these dates. Likewise, the unaudited pro forma information is
not necessarily indicative of future financial results.
- 88 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
Total revenues |
|
$ |
512,970 |
|
|
$ |
356,393 |
|
Cost of products sold |
|
|
422,624 |
|
|
|
288,973 |
|
Operating expenses |
|
|
48,218 |
|
|
|
36,333 |
|
Selling, general and administrative |
|
|
13,953 |
|
|
|
9,022 |
|
Depreciation and amortization |
|
|
13,843 |
|
|
|
10,334 |
|
Operating income |
|
|
14,332 |
|
|
|
11,731 |
|
Net income before taxes |
|
|
13,615 |
|
|
|
14,821 |
|
Net income |
|
|
13,615 |
|
|
|
14,821 |
|
Net income per limited partner unit |
|
$ |
1.22 |
|
|
$ |
1.32 |
|
The operations related to the Prism Gas acquisition have been included in the Partnerships
results of operations only since the date of acquisition.
In connection with the purchase of Prism Gas, a portion of the purchase price was funded by
the issuance of 460,971 common units of the Partnership to Martin Resource Management, the owner of
the Partnerships general partner, which provided $15,000 of new equity capital. Martin Midstream
GP LLC contributed $502 to maintain its 2% general partner interest in the partnership. In
addition, 295,509 common units of the Partnership, representing approximately $9,616 of the
purchase price, was issued to the sellers.
(f) CF Martin Sulfur. In July 2005, the Partnership acquired all of the outstanding
partnership interests in CF Martin Sulphur not owned by the Partnership from CF Industries, Inc.
and certain subsidiaries of Martin Resource Management for $18,900. In connection with the
acquisition the Partnership also assumed the indebtedness described below. Prior to this
transaction, the Partnership owned an unconsolidated non-controlling 49.5% limited partnership
interest in CF Martin Sulphur, which was accounted for using the equity method of accounting.
Subsequent to the acquisition, CF Martin Sulphur is a wholly-owned subsidiary included in the
Partnerships consolidated financial statements and in the Partnerships sulfur segment.
In connection with the acquisition, the Partnership assumed $11,500 of indebtedness owed by CF
Martin Sulphur and promptly repaid $2,400 of such indebtedness. The Partnership also pledged its
equity interests in CF Martin Sulphur to the Partnerships lenders under its credit facility. As
part of this transaction, CF Industries, Inc. entered into a five-year sulfur supply contract with
the Partnership that is based on Tampa market pricing.
The purchase price paid to CF Industries, Inc. and certain subsidiaries of Martin Resource
Management was allocated as follows:
|
|
|
|
|
Current assets |
|
$ |
11,283 |
|
Property, plant and equipment, net |
|
|
26,735 |
|
Other assets |
|
|
921 |
|
Current liabilities |
|
|
(8,573 |
) |
Debt |
|
|
(11,495 |
) |
|
|
|
|
Total use of proceeds |
|
$ |
18,871 |
|
|
|
|
|
(g) Bay Sulfur Asset Acquisition. In April 2005, the Partnership completed the acquisition of
the operating assets and sulfur inventories of Bay Sulfur Company located at the Port of Stockton,
California for $5,900 which includes $4,000 allocated to goodwill. Goodwill was recognized as a
result of the total price paid for the business, and is supported by its historical cash flows.
The remaining $1,900 was allocated to property, plant and equipment ($1,400), a covenant not to
compete ($100) and inventory and other current assets ($400). The assets acquired are used to
process molten sulfur into pellets. This acquisition is reported in the Partnerships new sulfur
segment. The acquisition was financed through the Partnerships credit facility (see Note 11).
(h) Natural Gas Liquids Pipeline Purchase. In January 2005, the Partnership acquired a
natural gas liquids (NGL) pipeline located in East Texas from an unrelated third party for
$3,800. The purchase price included
- 89 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
the value of the natural gas liquids in the pipeline which is considered pipeline fill. The
pipeline, which is used by the Partnership to transport NGL for third parties as well as its own
account, spans approximately 200 miles, running from Kilgore to Beaumont in Texas. The acquisition
was financed through the Partnerships credit facility (see Note 11).
(i) Freeport Terminal Acquisition. In September 2004, the Partnership completed the
acquisition of a marine terminal located near Freeport, Texas and associated assets from Offshore
Oil Services, Inc. (OOS) for $2,400. The terminal is located on approximately 18 acres of land
and includes two warehouses and an office building. The terminal is a full-service terminal used
to distribute and market lubricants and provide shore bases for companies that are operating in the
offshore exploration and production industry.
(j) Neches Industrial Park, Inc. Acquisition. In June 2004, the Partnership completed the
acquisition of a deep water marine terminal located near Beaumont, Texas from Neches Industrial
Park, Inc. for $26,500 (which includes an initial $1,000 payable under a related non-competition
agreement). The remaining $25,500 was allocated to property, plant and equipment. The terminal is
located on 50 acres of land on the Neches River and includes two dock structures, nine storage
tanks with a total capacity of approximately 480,000 barrels, four rail spurs with service provided
by three major rail companies, a bulk warehouse and associated pipelines, pipe racks, compressors
and related equipment. The terminal provides handling and storage for ammonia, sulfuric acid,
asphalt, fuel oil and fertilizer through fee based contracts.
(5) PUBLIC OFFERINGS
In January 2006, the Partnership completed a public offering of 3,450,000 common units at a
price of $29.12 per common unit, before the payment of underwriters discounts, commissions and
offering expenses (per unit value is in dollars, not thousands). Following this offering, the
common units represented a 61.6% limited partnership interest in the Partnership. Total proceeds
from the sale of the 3,450,000 common units, net of underwriters discounts, commissions and
offering expenses were $95,272. The Partnerships general partner contributed $2,050 in cash to
the Partnership in conjunction with the issuance in order to maintain its 2% general partner
interest in the Partnership. The net proceeds were used to pay down revolving debt under the
Partnerships credit facility and provide working capital.
A summary of the proceeds received from these transactions and the use of the proceeds
received therefrom is as follows (all amounts are in thousands):
|
|
|
|
|
Proceeds received: |
|
|
|
|
Sale of common units |
|
$ |
100,464 |
|
General partner contribution |
|
|
2,050 |
|
|
|
|
|
|
|
|
|
|
Total proceeds received |
|
$ |
102,514 |
|
|
|
|
|
|
|
|
|
|
Use of Proceeds: |
|
|
|
|
Underwriters fees |
|
$ |
4,521 |
|
Professional fees and other costs |
|
|
671 |
|
Repayment of debt under revolving credit facility |
|
|
62,000 |
|
Working capital |
|
|
35,322 |
|
|
|
|
|
|
|
|
|
|
Total use of proceeds |
|
$ |
102,514 |
|
|
|
|
|
In February 2004, the Partnership completed a public offering of 1,322,500 common units at a
price of $27.94 per common unit, before the payment of underwriters discounts, commissions and
offering expenses (per unit value is in dollars, not thousands). Following this offering, the
common units represented a 47.8% limited partnership interest in the Partnership. Total proceeds
from the sale of the 1,322,500 common units, net of underwriters discounts, commissions and
offering expenses were $34,016. The Partnerships general partner contributed $754 in cash to the
Partnership in conjunction with the issuance in order to maintain its 2% general partner interest
in the Partnership. The net proceeds were used to pay down revolving debt under the Partnerships
credit facility.
- 90 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
A summary of the proceeds received from these transactions and the use of the proceeds
received therefrom is as follows (all amounts are in thousands):
|
|
|
|
|
Proceeds received: |
|
|
|
|
Sale of common units |
|
$ |
36,951 |
|
General partner contribution |
|
|
754 |
|
|
|
|
|
|
|
|
|
|
Total proceeds received |
|
$ |
37,705 |
|
|
|
|
|
|
|
|
|
|
Use of Proceeds: |
|
|
|
|
Underwriters fees |
|
$ |
1,940 |
|
Professional fees and other costs |
|
|
995 |
|
Repayment of debt under revolving credit facility |
|
|
30,000 |
|
Working capital |
|
|
4,770 |
|
|
|
|
|
|
|
|
|
|
Total use of proceeds |
|
$ |
37,705 |
|
|
|
|
|
(6) INVENTORIES
Components of inventories at December 31, 2006 and 2005 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Natural gas liquids |
|
$ |
17,061 |
|
|
$ |
18,405 |
|
Sulfur |
|
|
4,397 |
|
|
|
3,485 |
|
Fertilizer raw materials and packaging |
|
|
2,412 |
|
|
|
2,617 |
|
Fertilizer finished goods |
|
|
4,807 |
|
|
|
5,803 |
|
Lubricants |
|
|
2,592 |
|
|
|
2,035 |
|
Other |
|
|
1,750 |
|
|
|
1,564 |
|
|
|
|
|
|
|
|
|
|
$ |
33,019 |
|
|
$ |
33,909 |
|
|
|
|
|
|
|
|
(7) PROPERTY, PLANT AND EQUIPMENT
At December 31, 2006 and 2005, property, plant, and equipment consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciable Lives |
|
|
2006 |
|
|
2005 |
|
Land |
|
|
|
|
|
$ |
12,559 |
|
|
$ |
9,163 |
|
Improvements to land and buildings |
|
10-39 years |
|
|
26,868 |
|
|
|
17,596 |
|
Transportation equipment |
|
3- 7 years |
|
|
531 |
|
|
|
432 |
|
Storage equipment |
|
5-20 years |
|
|
22,343 |
|
|
|
16,759 |
|
Marine vessels |
|
4-30 years |
|
|
124,323 |
|
|
|
94,051 |
|
Operating equipment |
|
3-30 years |
|
|
103,929 |
|
|
|
76,517 |
|
Furniture, fixtures and other equipment |
|
3-20 years |
|
|
1,450 |
|
|
|
1,116 |
|
Construction in progress |
|
|
|
|
|
|
31,964 |
|
|
|
19,584 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
323,967 |
|
|
$ |
235,218 |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation expense for the year ended December 31, 2006, 2005 and 2004 was $16,932, $12,062 and
$8,626, respectively.
(8) GOODWILL AND OTHER INTANGIBLE ASSETS
The following information relates to goodwill balances as of the periods presented:
- 91 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Carrying amount of goodwill: |
|
|
|
|
|
|
|
|
Marine transportation |
|
$ |
2,026 |
|
|
$ |
2,026 |
|
Natural gas services |
|
|
20,225 |
|
|
|
20,225 |
|
Sulfur |
|
|
4,533 |
|
|
|
4,533 |
|
Fertilizer |
|
|
816 |
|
|
|
816 |
|
|
|
|
|
|
|
|
|
|
$ |
27,600 |
|
|
$ |
27,600 |
|
|
|
|
|
|
|
|
The following information relates to covenants not-to-compete as of the periods presented:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Covenants not-to-compete: |
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
1,561 |
|
|
$ |
1,398 |
|
Natural gas services |
|
|
600 |
|
|
|
600 |
|
Sulfur |
|
|
100 |
|
|
|
100 |
|
Fertilizer |
|
|
690 |
|
|
|
690 |
|
|
|
|
|
|
|
|
|
|
|
2,951 |
|
|
|
2,788 |
|
Less accumulated amortization |
|
|
877 |
|
|
|
235 |
|
|
|
|
|
|
|
|
|
|
$ |
2,074 |
|
|
$ |
2,553 |
|
|
|
|
|
|
|
|
The covenants not-to-compete are in the consolidated balance sheets as other assets, net.
Aggregate amortization expense for amortizing intangible assets was $642, $153 and $82 for the
years ended December 31, 2006, 2005, and 2004, respectively. Estimated amortization expenses for
the years subsequent to December 31, 2006 are as follows: 2007 $665; 2008 $365; 2009 $365;
2010 $179; 2011 $163; subsequent years -$338.
(9) LEASES
The Partnership has numerous non-cancelable operating leases primarily for transportation and
other equipment. The leases generally provide that all expenses related to the equipment are to be
paid by the lessee. Management expects to renew or enter into similar leasing arrangements for
similar equipment upon the expiration of the current lease agreements. The Partnership also has
cancelable operating lease land rentals and outside marine vessel charters.
The future minimum lease payments under non-cancelable operating leases for years subsequent
to December 31, 2006 are as follows: 2007 $2,488; 2008 $1,950; 2009 $1,648; 2010 $1,505;
2011 $1,455 subsequent years -$5,949.
Rent expense for operating leases for the years ended December 31, 2006, 2005 and 2004 was
$8,407, $6,993 and $4,340, respectively.
(10) INVESTMENT IN UNCONSOLIDATED ENTITIES AND JOINT VENTURES
In July 2005, the Partnership acquired all of the outstanding partnership interests in CF
Martin Sulphur not owned by the Partnership from CF Industries, Inc. and certain subsidiaries of
Martin Resource Management. Prior to this transaction, the Partnership owned an unconsolidated
non-controlling 49.5% limited partnership interest in CF Martin Sulphur, which was accounted for
using the equity method of accounting. Equity in earnings of CF Martin Sulphur were $222 and $912
in 2005 and 2004, respectively. Subsequent to the acquisition, CF Martin Sulphur was a
wholly-owned subsidiary included in the Partnerships consolidated financial statements and in the
Partnerships sulfur segment. Effective March 30, 2006, CF Martin Sulphur was merged into the
Partnership.
- 92 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
On November 10, 2005, the Partnership acquired Prism Gas which is engaged in the gathering,
processing and marketing of natural gas and natural gas liquids, predominantly in Texas and
northwest Louisiana. Through the acquisition of Prism Gas, the Partnership also acquired 50%
ownership interests in Waskom, Matagorda and PIPE. Each of the interests referenced above are
accounted for under the equity method of accounting.
On June 30, 2006, the Partnership, through its Prism Gas subsidiary, acquired a 20% ownership
interest in a partnership for approximately $196, which owns the lease rights to the assets of the
Bosque County Pipeline (BCP). BCP is an approximate 67 mile pipeline located in the Barnett
Shale extension. The pipeline traverses four counties with the most concentrated drilling
occurring in Bosque County. BCP is operated by Panther Pipeline Ltd. who is the 42.5% interest
owner. This interest is accounted for under the equity method of accounting.
In accounting for the acquisition of the interests in Waskom, Matagorda and Fishhook, the
carrying amount of these investments exceeded the underlying net assets by approximately $46,176.
The difference was attributable to property and equipment of $11,872 and equity method goodwill of
$34,304. The excess investment relating to property and equipment is being amortized over an
average life of 20 years, which approximates the useful life of the underlying assets. Such
amortization amounted to $594 for the year ended December 31, 2006 and has been recorded as a
reduction of equity in earnings of unconsolidated equity method investees. The remaining
unamortized excess investment relating to property and equipment was $11,279 at December 31, 2006.
The equity-method goodwill is not amortized in accordance with SFAS 142; however, it is analyzed
for impairment annually. No impairment was recognized in 2005 or 2006.
As a partner in Waskom, the Partnership receives distributions in kind of natural gas liquids
that are retained according to Waskoms contracts with certain producers. The natural gas liquids
are valued at prevailing market prices. In addition, cash distributions are received and cash
contributions are made to fund operating and capital requirements of Waskom.
Activity related to these investment accounts is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Waskom |
|
|
PIPE |
|
|
Matagorda |
|
|
BCP |
|
|
Total |
|
Investment in unconsolidated entities, December 31, 2004 |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of interests |
|
|
54,100 |
|
|
|
1,700 |
|
|
|
4,200 |
|
|
|
|
|
|
|
60,000 |
|
Distributions in kind |
|
|
(1,115 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,115 |
) |
Cash contributions |
|
|
322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
322 |
|
Cash distributions |
|
|
(495 |
) |
|
|
|
|
|
|
(202 |
) |
|
|
|
|
|
|
(697 |
) |
Equity in earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings from operations |
|
|
1,275 |
|
|
|
23 |
|
|
|
71 |
|
|
|
|
|
|
|
1,369 |
|
Amortization of excess investment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in unconsolidated entities, December 31, 2005 |
|
|
54,087 |
|
|
|
1,723 |
|
|
|
4,069 |
|
|
|
|
|
|
|
59,879 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
196 |
|
|
|
196 |
|
Distributions in kind |
|
|
(8,311 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,311 |
) |
Cash contributions |
|
|
11,238 |
|
|
|
|
|
|
|
|
|
|
|
76 |
|
|
|
11,314 |
|
Cash distributions |
|
|
(150 |
) |
|
|
(214 |
) |
|
|
(610 |
) |
|
|
|
|
|
|
(974 |
) |
Equity in earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings from operations |
|
|
8,623 |
|
|
|
224 |
|
|
|
356 |
|
|
|
(62 |
) |
|
|
9,141 |
|
Amortization of excess investment |
|
|
(550 |
) |
|
|
(15 |
) |
|
|
(29 |
) |
|
|
|
|
|
|
(594 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in unconsolidated entities, December 31, 2006 |
|
$ |
64,937 |
|
|
$ |
1,718 |
|
|
$ |
3,786 |
|
|
$ |
210 |
|
|
$ |
70,651 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 93 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Select financial information for significant unconsolidated equity method investees is as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
Long- |
|
|
Partners |
|
|
|
|
|
|
Net Income |
|
|
|
Assets |
|
|
Term Debt |
|
|
Capital |
|
|
Revenues |
|
|
(Loss) |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Waskom |
|
$ |
53,260 |
|
|
$ |
|
|
|
$ |
45,450 |
|
|
$ |
65,600 |
|
|
$ |
17,246 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Waskom (November 10 December 31) |
|
$ |
28,369 |
|
|
$ |
|
|
|
$ |
22,650 |
|
|
$ |
9,165 |
|
|
$ |
2,559 |
|
CF Martin (January 1 July 15) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33,900 |
|
|
|
(120 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
28,369 |
|
|
$ |
|
|
|
$ |
22,650 |
|
|
$ |
43,065 |
|
|
$ |
2,439 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CF Martin |
|
$ |
48,921 |
|
|
$ |
10,179 |
|
|
$ |
26,769 |
|
|
$ |
64,719 |
|
|
$ |
783 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2006, the Partnership's interest in cash of the unconsolidated equity method investees is $767.
(11) LONG-TERM DEBT
At December 31, 2006 and December 31, 2005, long-term debt consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
*$120,000 Revolving loan facility at variable interest
rate (7.04%* weighted average at December 31, 2006), due
November 2010 secured by substantially all of the
Partnerships assets, including, without limitation,
inventory, accounts receivable, vessels, equipment, fixed
assets and the interests in its operating subsidiaries |
|
$ |
44,000 |
|
|
$ |
62,200 |
|
|
**$130,000 Term loan facility at variable interest rate
(7.34%* at December 31, 2006), due November 2010, secured
by substantially all of the Partnerships assets,
including, without limitation, inventory, accounts
receivable, vessels, equipment, fixed assets and the
interests in its operating subsidiaries |
|
|
130,000 |
|
|
|
130,000 |
|
|
***United States Government Guaranteed Ship Financing Bonds |
|
|
|
|
|
|
9,104 |
|
Other secured debt maturing in 2008, 7.25% |
|
|
95 |
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
|
174,095 |
|
|
|
201,304 |
|
Less current installments |
|
|
74 |
|
|
|
9,104 |
|
|
|
|
|
|
|
|
Long-term debt, net of current installments |
|
$ |
174,021 |
|
|
$ |
192,200 |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each
advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility
bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable
margin. The applicable margin is based on a debt leverage ratio requirement which changes
quarterly. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to
3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from
0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to
3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to
2.00%. The applicable margin for existing borrowings through December 31, 2006 was 2.00%.
Effective January 1, 2007, the applicable margin for existing borrowings increased to 2.5%.
Effective April 1, 2007, the applicable margin for existing borrowings will decrease to 2.0%. The
Partnership incurs a commitment fee on the unused portions of the credit facility. |
- 94 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
|
|
|
* |
|
Effective December 13, 2006, the Partnership entered into a cash flow hedge that swaps $40,000 of
floating rate to fixed rate. The fixed rate cost is 4.82% plus the Partnerships applicable LIBOR
borrowing spread. The cash flow hedge matures in December, 2009. |
|
* |
|
Effective December 13, 2006, the Partnership entered into an interest rate swap that swaps
$30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Partnerships
applicable LIBOR borrowing spread. This interest rate swap, which matures in March, 2010, is not
accounted for as a cash flow hedge. |
|
** |
|
Effective April 13, 2006, the Partnership entered into a cash flow hedge that swaps $75,000 of
floating rate to fixed rate. The fixed rate cost is 5.25% plus the Partnerships applicable LIBOR
borrowing spread. The cash flow hedge matures in November, 2010. |
|
*** |
|
The Partnerships credit facility required it to redeem the U.S. Government Guaranteed Ship
Financing Bonds by March 31, 2006. The Partnership redeemed these bonds on March 6, 2006 with
available cash and borrowings from its credit facility. |
On August 18, 2006, the Partnership purchased certain terminalling asphalt assets in Houston,
Texas from Gulf States Asphalt Company LP and assumed associated long term debt of $113 with a
fixed interest rate of 7.25%.
On November 10, 2005, the Partnership entered into a new $225,000 multi-bank credit facility
comprised of a $130,000 term loan facility and a $95,000 revolving credit facility, which includes
a $20,000 letter of credit sub-limit. This credit facility also includes procedures for additional
financial institutions to become revolving lenders, or for any existing revolving lender to
increase its revolving commitment, subject to a maximum of $100,000 for all such increases in
revolving commitments of new or existing revolving lenders. Effective June 30, 2006, the
Partnership increased its revolving credit facility $25,000 resulting in a committed $120,000
revolving credit facility. The revolving credit facility is used for ongoing working capital needs
and general partnership purposes, and to finance permitted investments, acquisitions and capital
expenditures. Under the amended and restated credit facility, as of December 31, 2006, the
Partnership had $44,000 outstanding under the revolving credit facility and $130,000 outstanding
under the term loan facility. As of December 31, 2006, the Partnership had $75,900 available under
the revolving credit facility.
On July 14, 2005, the Partnership issued a $120 irrevocable letter of credit to the Texas
Commission on Environmental Quality to provide financial assurance for its used oil handling
program.
Indebtedness under the credit facility bears interest at either LIBOR plus an applicable
margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans
that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that
are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are
LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime
rate loans ranges from 1.00% to 2.00%. The applicable margin for existing borrowings is 2.00%. As
a result of the Partnerships leverage ratio test, effective January 1, 2007, the applicable margin
for existing borrowings will increase to 2.50%. Effective April 1, 2007, the applicable margin for
existing borrowings will decrease to 2.00%. The Partnership incurs a commitment fee on the unused
portions of the credit facility.
The Partnerships obligations under the credit facility are secured by substantially all of
the Partnerships assets, including, without limitation, inventory, accounts receivable, vessels,
equipment, fixed assets and the interests in its operating subsidiaries. The Partnership may prepay
all amounts outstanding under this facility at any time without penalty.
In addition, the credit facility contains various covenants, which, among other things, limit
the Partnerships ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or
consolidate unless it is the survivor; (iv) sell all or substantially all of its assets; (v) make
certain acquisitions; (vi) make certain investments; (vii) make certain capital expenditures;
(viii) make distributions other than from available cash; (ix) create obligations for some lease
payments; (x) engage in transactions with affiliates; (xi) engage in other types of business; and
(xii) its joint ventures to incur indebtedness or grant certain liens.
- 95 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
The credit facility also contains covenants, which, among other things, require the
Partnership to maintain specified ratios of: (i) minimum net worth (as defined in the credit
facility) of $75,000 plus 50% of net proceeds from equity issuances after November 10, 2005; (ii)
EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the
end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than (x) 5.5 to 1.0 for
the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending
December 31, 2005 through September 30, 2006, and (z) 4.75 to 1.00 for each fiscal quarter
thereafter; and (iv) total secured funded debt to EBITDA of not more than (x) 5.50 to 1.00 for the
fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December
31, 2005 through September 20, 2006, and (z) 4.00 to 1.00 for each fiscal quarter thereafter. The
Partnership was in compliance with the debt covenants contained in credit facility for the years
ended December 31, 2006 and 2005.
On November 10 of each year, commencing with November 10, 2006, the Partnership must prepay
the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit
facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. This ratio
was below 3.00 for all periods in 2006 and no prepayments were required under the term loan in
2006. If the Partnership receives greater than $15,000 from the incurrence of indebtedness other
than under the credit facility, it must prepay indebtedness under the credit facility with all such
proceeds in excess of $15,000. Any such prepayments are first applied to the term loans under the
credit facility. The Partnership must prepay revolving loans under the credit facility with the net
cash proceeds from any issuance of its equity. The Partnership must also prepay indebtedness under
the credit facility with the proceeds of certain asset dispositions. Other than these mandatory
prepayments, the credit facility requires interest only payments on a quarterly basis until
maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The
credit facility contains customary events of default, including, without limitation, payment
defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of
control defaults and litigation-related defaults.
Draws made under the Partnerships credit facility are normally made to fund acquisitions and
for working capital requirements. During the current fiscal year, draws on the Partnerships credit
facility have ranged from a low of $130,000 to a high of $197,700. As of December 31, 2006, the
Partnership had $75,900 available for working capital, internal expansion and acquisition
activities under the Partnerships credit facility.
On July 15, 2005, the Partnership assumed $9,400 of U.S. Government Guaranteed Ship Financing
Bonds, maturing in 2021, relating to the acquisition of CF Martin Sulphur. The outstanding balance
as of December 31, 2005 was $9,104. These bonds are payable in equal semi-annual installments of
$291, and are secured by certain marine vessels owned by CF Martin Sulphur. Pursuant to the terms
of an amendment to the Partnerships credit facility that it entered into in connection with the
acquisition of CF Martin Sulphur, the Partnership was obligated to repay these bonds by March 31,
2006. The Partnership redeemed these bonds on March 6, 2006 with available cash and borrowings from
its credit facility. In addition, a pre-payment premium was paid in the amount of $1,160.
The Partnership paid cash interest in the amount of $12,426, $5,278 and $2,018 for the years
ended December 31, 2006, 2005, 2004 respectively. Capitalized interest related primarily to the
construction of the sulfur priller in Beaumont, Texas and the sulfuric acid plant in Plainview,
Texas for the years ended December 31, 2006, 2005, 2004 was $1,546, $237 and $0, respectively.
(12) INTEREST RATE CASH FLOW HEDGES
In
April, 2006, the Partnership entered into a cash flow hedge agreement with a notional amount
of $75,000 to hedge its exposure to increases in the benchmark interest rate underlying its
variable rate term loan credit facility. This interest rate swap matures in November 2010. The
Partnership designated this swap agreement as a cash flow hedge. Under the swap agreement, the
Partnership pays a fixed rate of interest of 5.25% and receive a floating rate based on a
three-month U.S. Dollar LIBOR rate. Because this is designated as a cash flow hedge, the changes
in fair value, to the extent the swap is effective, are recognized in other comprehensive income
until the hedged interest costs are recognized in earnings. At the inception of the hedge, the
swap was identical to the hypothetical swap as of the trade date, and will continue to be identical
as long as the accrual periods and rate resetting dates for the debt and the swap remain equal.
This condition results in a 100% effective swap.
- 96 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
In December 2006, the Partnership entered into a cash flow hedge agreement with a notional
amount of $40,000 to hedge its exposure to increases in the benchmark interest rate underlying its
variable rate revolving credit facility. This interest rate swap matures in December 2009. The
Partnership designated this swap agreement as a cash flow hedge. Under the swap agreement, the
Partnership pays a fixed rate of interest of 4.82% and receives a floating rate based on a
three-month U.S. Dollar LIBOR rate. Because this is designated as a cash flow hedge, the changes
in fair value, to the extent the swap is effective, are recognized in other comprehensive income
until the hedged interest costs are recognized in earnings. At the inception of the hedge, the
swap was identical to the hypothetical swap as of the trade date, and will continue to be identical
as long as the accrual periods and rate resetting dates for the debt and the swap remain equal.
This condition results in a 100% effective swap.
In December 2006, the Partnership entered into an interest rate swap that swaps $30,000 of
floating rate to fixed rate. The fixed rate cost is 4.765% plus the Partnerships applicable LIBOR
borrowing spread. This interest rate swap matures in March 2010. The underlying debt related to
this swap was paid prior to December 31, 2006, therefore; therefore, hedge accounting was not
utilized. The swap has been recorded at fair value at December 31, 2006 with an offset to current
operations.
During the year ended December 31, 2006, the Partnership recognized increases in interest
expense of less than $100 related to the difference between the fixed rate and the floating rate of
interest on the interest rate swaps. The total fair value of the interest rate swaps agreement was
a liability of approximately $83 at December 31, 2006.
The fair value of derivative assets and liabilities are as follows:
|
|
|
|
|
|
|
December 31, |
|
|
|
2006 |
|
Fair value of derivative assets current |
|
$ |
377 |
|
Fair value of derivative assets long-term |
|
|
112 |
|
Fair value of derivative liabilities long term |
|
|
(572 |
) |
|
|
|
|
Net fair value of derivatives |
|
$ |
(83 |
) |
|
|
|
|
(13) RELATED PARTY TRANSACTIONS
Included in the consolidated financial statements are various related party transactions and
balances primarily with 1) Martin Resource Management and affiliates, 2) CF Martin Sulphur (through
July 15, 2005) and 3) Waskom since November 10, 2005.
Related party transactions include sales and purchases of products and services between the
Partnership and these related entities as well as payroll and associated costs and allocation of
overhead.
The impact of these related party transactions is reflected in the consolidated financial
statement as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
8,926 |
|
|
$ |
8,938 |
|
|
$ |
5,739 |
|
Marine transportation |
|
|
15,319 |
|
|
|
11,606 |
|
|
|
14,326 |
|
Product sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas services |
|
|
1,303 |
|
|
|
44 |
|
|
|
345 |
|
Sulfur |
|
|
|
|
|
|
|
|
|
|
|
|
Fertilizer |
|
|
24 |
|
|
|
229 |
|
|
|
1,654 |
|
Terminalling and storage |
|
|
59 |
|
|
|
5 |
|
|
|
124 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,386 |
|
|
|
278 |
|
|
|
2,123 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
25,631 |
|
|
$ |
20,822 |
|
|
$ |
22,188 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas services |
|
$ |
52,030 |
|
|
$ |
15,827 |
|
|
$ |
7,101 |
|
- 97 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Sulfur |
|
|
5,253 |
|
|
|
2,110 |
|
|
|
|
|
Fertilizer |
|
|
6,660 |
|
|
|
7,733 |
|
|
|
6,378 |
|
Terminalling and storage |
|
|
1 |
|
|
|
31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
63,944 |
|
|
$ |
25,701 |
|
|
$ |
13,479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Marine Transportation |
|
$ |
20,051 |
|
|
$ |
15,746 |
|
|
$ |
11,733 |
|
Natural gas services |
|
|
1,560 |
|
|
|
1,236 |
|
|
|
917 |
|
Sulfur |
|
|
800 |
|
|
|
263 |
|
|
|
|
|
Fertilizer |
|
|
128 |
|
|
|
32 |
|
|
|
|
|
Terminalling and storage |
|
|
3,931 |
|
|
|
3,485 |
|
|
$ |
2,825 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,470 |
|
|
$ |
20,762 |
|
|
$ |
15,475 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selling, general and administrative: |
|
|
|
|
|
|
|
|
|
|
|
|
Marine Transportation |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Natural gas services |
|
|
773 |
|
|
|
833 |
|
|
|
748 |
|
Sulfur |
|
|
494 |
|
|
|
212 |
|
|
|
|
|
Fertilizer |
|
|
1,220 |
|
|
|
1,232 |
|
|
|
1,104 |
|
Terminalling and storage |
|
|
74 |
|
|
|
76 |
|
|
|
76 |
|
Indirect overhead allocation, net of reimbursement |
|
|
1,305 |
|
|
|
1,120 |
|
|
|
736 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,866 |
|
|
$ |
3,473 |
|
|
$ |
2,664 |
|
|
|
|
|
|
|
|
|
|
|
The Partnership is a party to an omnibus agreement with Martin Resource Management. The
omnibus agreement requires the Partnership to reimburse Martin Resource Management for all direct
and indirect expenses it incurs or payments it makes on the Partnerships behalf or in connection
with the operation of the Partnerships business. The Partnership reimbursed Martin Resource
Management direct costs and expenses of $49,093, $42,068, and $31,386 for the years ended December
31, 2006, 2005, and 2004, respectively. There is no monetary limitation on the amount the
Partnership is required to reimburse Martin Resource Management for direct expenses. Under the
omnibus agreement, the reimbursement amount with respect to indirect general and administrative and
corporate overhead expenses was capped at $2,000 for the twelve month period ending October 31,
2004. Subsequently, this amount may be increased by no more than the percentage increase in the
consumer price index and is also subject to adjustment for expansions of the Partnerships
operations and acquisitions. The Partnership reimbursed Martin Resource Management indirect cost
and expenses of $1,493, $1,348, and $1,058 for the years ended December 31, 2006, 2005, and 2004,
respectively. These indirect expenses cover all of the centralized corporate functions Martin
Resource Management provides for the Partnership, such as accounting, treasury, clerical billing,
information technology, administration of insurance, general office expenses and employee benefit
plans and other general corporate overhead functions the Partnership shares with Martin Resource
Management retained businesses. The omnibus agreement also contains significant non-compete
provisions and indemnity obligations.
(14) FINANCIAL INSTRUMENTS
Statement of Financial Accounting Standards No. 107, Disclosures about Fair Value of Financial
Instruments, requires that the Partnership disclose estimated fair values for its financial
instruments. Fair value estimates are set forth below for the Partnerships financial instruments.
The following methods and assumptions were used to estimate the fair value of each class of
financial instrument:
|
|
|
Accounts and other receivables, trade and other accounts payable, other
accrued liabilities, income taxes payable and due from/to affiliates The carrying
amounts approximate fair value because of the short maturity of these instruments. |
|
|
|
|
Long-term debt including current installments The carrying amount of the
revolving and term loan facilities approximates fair value due to the debt having a
variable interest rate. |
(15) COMMODITY CASH FLOW HEDGES
The Partnership is exposed to market risks associated with commodity prices, counterparty
credit and interest rates. Historically, the Partnership has not engaged in commodity contract
trading or hedging activities.
- 98 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
However, in connection with the acquisition of Prism Gas, the Partnership has established a
hedging policy and monitors and manages the commodity market risk associated with the commodity
risk exposure of the Prism Gas acquisition. In addition, the Partnership is focusing on utilizing
counterparties for these transactions whose financial condition is appropriate for the credit risk
involved in each specific transaction.
The Partnership uses derivatives to manage the risk of commodity price fluctuations.
Additionally, the Partnership manages interest rate exposure by targeting a ratio of fixed and
floating interest rates it deems prudent and using hedges to attain that ratio.
In accordance with Statement of Financial Accounting Standards No. 133 (SFAS No. 133),
Accounting for Derivative Instruments and Hedging Activities, all derivatives and hedging
instruments are included on the balance sheet as an asset or a liability measured at fair value and
changes in fair value are recognized currently in earnings unless specific hedge accounting
criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be
offset against the change in the fair value of the hedged item through earnings or recognized in
other comprehensive income until such time as the hedged item is recognized in earnings. In early
2006, the Partnership adopted a hedging policy that allows it to use hedge accounting for financial
transactions that are designated as hedges.
Derivative instruments not designated as hedges are being marked to market with all market
value adjustments being recorded in the consolidated statements of operations. As of December 31,
2006, the Partnership has designated a portion of its derivative instruments as qualifying cash
flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income
as a component of equity.
The components of gain/loss on derivatives qualifying for hedge accounting and those that do
not are included in the revenue of the hedged item in the Consolidated Statements of Operations and
for the year ended December 31, 2006 they are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Change in fair value of derivatives that do not qualify for hedge accounting |
|
$ |
1,117 |
|
|
$ |
512 |
|
Ineffective portion of derivatives qualifying for hedge accounting |
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivatives in the Consolidated Statement of Operations |
|
$ |
1,115 |
|
|
$ |
512 |
|
|
|
|
|
|
|
|
The fair value of derivative assets and liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Fair value of derivative assets current |
|
$ |
882 |
|
|
$ |
523 |
|
Fair value of derivative assets long term |
|
|
221 |
|
|
|
|
|
Fair value of derivative liabilities current |
|
|
|
|
|
|
(88 |
) |
Fair value of derivative liabilities long term |
|
|
(74 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net fair value of derivatives |
|
$ |
1,029 |
|
|
$ |
435 |
|
|
|
|
|
|
|
|
Set forth below is the summarized notional amount and terms of all instruments held for price
risk management purposes at December 31, 2006 (all gas quantities are expressed in British Thermal
Units, crude oil and natural gas liquids are expressed in barrels). As of December 31, 2006, the
remaining term of the contracts extend no later than December 2009, with no single contract longer
than one year. The Partnerships counterparties to the derivative contracts include Coral Energy
Holding LP, Morgan Stanley Capital Group Inc. and Wachovia Bank. For the period ended December 31,
2006, changes in the fair value of the Partnerships derivative contracts were recorded in both
earnings and in other comprehensive income as a component of equity since the Partnership has
designated a portion of its derivative instruments as hedges as of December 31, 2006.
- 99 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
|
Total |
|
|
|
|
|
|
|
|
Volume |
|
|
|
Remaining Terms |
|
|
Transaction Type |
|
Per Month |
|
Pricing Terms |
|
of Contracts |
|
Fair Value |
Mark to Market Derivatives:: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil swap
|
|
5,000 BBL
|
|
Fixed price of
$65.95 settled
against WTI NYMEX
average monthly
closings
|
|
January 2007 to
December 2007
|
|
|
103 |
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas swap
and Natural Gas
basis swap
|
|
20,000 MMBTU
|
|
Combined fixed
price of $8.54
settled against IF
Centerpoint Energy
Gas Transmission
Co.
|
|
January 2007 to
December 2007
|
|
|
556 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total swaps not
designated as cash flow hedges |
|
$ |
659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ethane Swap
|
|
8,000 BBL
|
|
Fixed price of
$28.04 settled
against Mt. Belvieu
Purity Ethane
average monthly
postings
|
|
January 2007 to
December 2007
|
|
|
223 |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Swap
|
|
5,000 BBL
|
|
Fixed price of
$66.20 settled
against WTI NYMEX
average monthly
closings
|
|
January 2008 to
December 2008
|
|
|
(74 |
) |
|
|
|
|
|
|
|
|
|
|
|
Natural Gas swap
|
|
30,000 MMBTU
|
|
Fixed price of
$8.12 settled
against IF Houston
Ship Channel first
of the month
|
|
January 2008 to
December 2008
|
|
|
155 |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Swap
|
|
3,000 BBL
|
|
Fixed price of
$69.08 settled
against WTI NYMEX
average monthly
closings
|
|
January 2009 to
December 2009
|
|
|
66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total swaps designated as cash flow hedges |
|
$ |
370 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net fair value of derivatives |
|
$ |
1,029 |
|
|
|
|
|
|
|
|
|
|
|
|
On all transactions where the Partnership is exposed to counterparty risk, the
Partnership analyzes the counterpartys financial condition prior to entering into an agreement,
and has established a maximum credit limit threshold pursuant to its hedging policy, and monitors
the appropriateness of these limits on an ongoing basis. The Partnership has incurred no losses
associated with the counterparty non-performance on derivative contracts.
As a result of the Prism Gas acquisition, the Partnership is exposed to the impact of market
fluctuations in the prices of natural gas, natural gas liquids (NGLs) and condensate as a result
of gathering, processing and sales activities. Prism Gas gathering and processing revenues are
earned under various contractual arrangements with gas producers. Gathering revenues are generated
through a combination of fixed-fee and index-related arrangements. Processing revenues are
generated primarily through contracts which provide for processing on percent-of-liquids (POL) and
percent-of-proceeds (POP) basis. Prism Gas has entered into hedging transactions through 2009 to
protect a portion of its commodity exposure from these contracts. These hedging arrangements are in
the form of swaps for crude oil, natural gas and ethane.
Based on estimated volumes, as of December 31, 2006, Prism Gas had hedged approximately 60%,
45%, and 14% of its commodity risk by volume for 2007, 2008, and 2009, respectively. The
Partnership anticipates entering into additional commodity derivatives on an ongoing basis to
manage its risks associated with these market fluctuations, and will consider using various
commodity derivatives, including forward contracts, swaps, collars, futures and options, although
there is no assurance that the Partnership will be able to do so or that the terms thereof will be
similar to the Partnerships existing hedging arrangements. In addition, the Partnership will
consider
derivative arrangements that include the specific NGL products as well as natural gas and
crude oil.
- 100 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Hedging Arrangements in Place
|
|
|
|
|
|
|
|
|
Year |
|
Commodity Hedged |
|
Volume |
|
Type of Derivative |
|
Basis Reference |
2007
|
|
Condensate & Natural Gasoline
|
|
5,000 BBL/Month
|
|
Crude Oil Swap ($65.95)
|
|
NYMEX |
2007
|
|
Natural Gas
|
|
20,000 MMBTU/Month
|
|
Natural Gas Swap ($9.14)
|
|
Henry Hub |
2007
|
|
Natural Gas
|
|
20,000 MMBTU/Month
|
|
Natural Gas Basis Swap
(-$0.60)
|
|
Henry Hub to
Centerpoint East |
2007
|
|
Ethane
|
|
8,000 BBL/Month
|
|
Ethane Swap ($28.04)
|
|
Mt. Belvieu |
2008
|
|
Condensate & Natural Gasoline
|
|
5,000 BBL/Month
|
|
Crude Oil Swap ($66.20)
|
|
NYMEX |
2008
|
|
Natural Gas
|
|
30,000 MMBTU/Month
|
|
Natural Gas Swap ($8.12)
|
|
Houston Ship Channel |
2009
|
|
Condensate & Natural Gasoline
|
|
3,000 BBL/Month
|
|
Crude Oil Swap ($69.08)
|
|
NYMEX |
The Partnerships principal customers with respect to Prism Gas natural gas gathering
and processing are large, natural gas marketing services, oil and gas producers and industrial
end-users. In addition, substantially all of the Partnerships natural gas and NGL sales are made
at market-based prices. The Partnerships standard gas and NGL sales contracts contain adequate
assurance provisions which allows for the suspension of deliveries, cancellation of agreements or
continuance of deliveries to the buyer unless the buyer provides security for payment in a form
satisfactory to the Partnership.
Impact of Cash Flow Hedges
Crude Oil
For the years ended December 31, 2006 and 2005, net gains and losses on swap hedge contracts
increased crude revenue by $76 and decreased crude revenue by $38, respectively. As of December
31, 2006 an unrealized derivative fair value loss of $8, related to cash flow hedges of crude oil
price risk, was recorded in other comprehensive income (loss). A fair value loss of $74 is
expected to be reclassified into earnings in 2008. A fair value gain of $66 is expected to be
reclassified into earnings in 2009. The actual reclassification to earnings will be based on
mark-to-market prices at the contract settlement date, along with the realization of the gain or
loss on the related physical volume, which amount is not reflected above.
Natural Gas
For the years ended December 31, 2006 and 2005, net gains on swap hedge contracts increased
gas revenue by $1,097 and $369, respectively. As of December 31, 2006, an unrealized derivative
fair value gain of $155 related to cash flow hedges of natural gas price risk was recorded in other
comprehensive income. This fair value gain is expected to be reclassified to earnings in 2008.
The actual reclassification to earnings will be based on mark-to-market prices at the contract
settlement date, along with the realization of the gain or loss on the related physical volume,
which amount is not reflected above.
Natural Gas Liquids
For the years ended December 31, 2006 and 2005, net gains and losses on swap hedge contracts
decreased and increased liquids revenue by $58 and $181, respectively. As of December 31, 2006, an
unrealized derivative fair value gain of $223 related to cash flow hedges of ethane price risk was
recorded in other comprehensive income (loss). This fair value gain is expected to be reclassified
into earnings in 2007. The actual reclassification to earnings will be based on mark-to-market
prices at the contract settlement date, along with the realization of the gain or loss on the
related physical volume, which amount is not reflected above.
(16) PARTNERS CAPITAL
As of December 31, 2006, partners capital consists of 10,603,808 common limited partner
units, representing a 79.0% limited partnership interest, 2,552,018 subordinated limited partner
units, representing a 19.0%
partnership interest and a 2% general partner interest. Martin Resource Management and its
subsidiaries, in the aggregate, owned an approximate 38.6% limited partnership interest consisting
of 2,632,799 common limited partner units and 2,552,018 subordinated limited partner units and a 2%
general partner interest.
- 101 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
The Partnership Agreement contains specific provisions for the allocation of net income and
losses to each of the partners for purposes of maintaining their respective partner capital
accounts
Distributions of Available Cash
The Partnership distributes all of its Available Cash (as defined in the Partnership
Agreement) within 45 days after the end of each quarter to unitholders of record and to the general
partner. Available Cash is generally defined as all cash and cash equivalents of the Partnership
on hand at the end of each quarter less the amount of cash reserves its general partner determines
in its reasonable discretion is necessary or appropriate to: (i) provide for the proper conduct of
the Partnerships business; (ii) comply with applicable law, any debt instruments or other
agreements; or (iii) provide funds for distributions to unitholders and the general partner for any
one or more of the next four quarters, plus all cash on the date of determination of available cash
for the quarter resulting from working capital borrowings made after the end of the quarter.
Subordination Period
During the subordination period (defined in the Partnership Agreement), the common units have
the right to receive distributions of available cash in an amount equal to the minimum quarterly
distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly
distribution on the common units from prior quarters, before any distributions of available cash
from operating surplus may be made on the subordinated units.
The subordination period ends on the first day of any quarter beginning after September 30,
2009, when certain financial tests (defined in the Partnership Agreement) are met. Additionally, a
portion of the subordinated units may convert earlier into common units on a one-for-one basis if
additional financial tests (defined in the Partnership Agreement) are met.
The partnership agreement provides that before the end of the subordination period, a portion
of the subordinated units may convert into common units on a one-for-one basis immediately after
the distribution of available cash to the partners in respect of any quarter ending on or after:
|
|
|
September 30, 2005 with respect to 20% of the subordinated units; |
|
|
|
|
September 30, 2006 with respect to 20% of the subordinated units; |
|
|
|
|
September 30, 2007 with respect to 20% of the subordinated units; |
|
|
|
|
September 30, 2008 with respect to 20% of the subordinated units; |
As a result of achieving the defined financial test, 850,672 subordinated units representing
20% of the total originally issued subordinated units were converted into common units on both
November 10, 2006 and 2005. A total of 1,701,244 subordinated units representing 40% of the total
originally issued subordinated units have been converted into common units as of December 31, 2006.
When the subordination period ends, any remaining subordinated units will convert into common
units on a one-for-one basis and the common units will no longer be entitled to arrearages.
(17) GAIN ON INVOLUNTARY CONVERSION OF ASSETS
During the third quarter of 2005, several of the Partnerships facilities in the Gulf of
Mexico were in the path of two major storms, Hurricane Katrina and Hurricane Rita. Physical damage
to the Partnerships assets caused by the hurricanes, as well as the related removal and recovery
costs, are covered by insurance subject to a deductible. Losses incurred as a result of a single
hurricane (an occurrence) are limited to a maximum aggregate deductible of $100 for flood damage
and the greater of $100 or 2% of total insured value at each location for wind damage. The
Partnerships total flood coverage is $5,000 and total wind coverage is $40,000.
The most significant damage to the Partnerships assets was sustained at the Cameron East
location. Property damage also occurred at the Partnerships Sabine Pass, Venice, Intracoastal
City, Port Fourchon, Galveston, Cameron West, Neches and Stanolind locations. Based on an analysis
of the damage as performed by the Partnership and its
- 102 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
insurance underwriters, the Partnership had
estimated its non-cash impairment charge as $1,200 for all the locations which is equal to the
net-book value of the damaged assets. A receivable was established for the expected insurance
recovery equal to the impairment charge.
The Partnership recognized a $700 estimated loss during the last half of 2005, which
approximates the Partnerships hurricane deductibles under its applicable insurance policies,
incurred as a result of Hurricanes Katrina and Rita. The loss is included in operating expenses
in the consolidated statement of operations for the year ended December 31, 2005.
Insurance proceeds received as a result of the aforementioned claims exceeded net book value
of the Partnerships assets determined to be impaired. During 2006, the Partnership received
insurance proceeds of $4,812 for this involuntary conversion of assets, which resulted in a gain of
$3,125 which is reported in other operating income.
(18) COMMITMENTS AND CONTINGENCIES
From time to time, the Partnership is subject to various claims and legal actions arising in
the ordinary course of business. In the opinion of management, the ultimate disposition of these
matters will not have a material adverse effect on the Partnership.
(19) BUSINESS SEGMENTS
The Partnership has five reportable segments: terminalling and storage, natural gas services,
marine transportation, sulfur which was added in 2005, and fertilizer. The Partnerships
reportable segments are strategic business units that offer different products and services. The
operating income of these segments is reviewed by the chief operating decision maker to assess
performance and make business decisions.
The accounting policies of the operating segments are the same as those described in Note 2 of
the notes to consolidated financial statements. The Partnership evaluates the performance of its
reportable segments based on operating income. There is no allocation of administrative expenses or
interest expense.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
Depreciation |
|
|
Operating |
|
|
|
|
|
|
Operating |
|
|
Intersegment |
|
|
After |
|
|
and |
|
|
Income |
|
|
Capital |
|
|
|
Revenues |
|
|
Eliminations |
|
|
Eliminations |
|
|
Amortization |
|
|
(Loss) |
|
|
Expenditures |
|
Year ended December 31, 2006: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
36,606 |
|
|
$ |
(389 |
) |
|
$ |
36,217 |
|
|
$ |
4,700 |
|
|
$ |
12,504 |
|
|
$ |
13,371 |
|
Natural gas services |
|
|
389,735 |
|
|
|
|
|
|
|
389,735 |
|
|
|
1,667 |
|
|
|
4,239 |
|
|
|
5,552 |
|
Marine transportation |
|
|
50,174 |
|
|
|
(2,339 |
) |
|
|
47,835 |
|
|
|
6,609 |
|
|
|
6,411 |
|
|
|
18,840 |
|
Sulfur |
|
|
62,467 |
|
|
|
(1,196 |
) |
|
|
61,271 |
|
|
|
2,997 |
|
|
|
4,864 |
|
|
|
12,582 |
|
Fertilizer |
|
|
41,842 |
|
|
|
(516 |
) |
|
|
41,326 |
|
|
|
1,624 |
|
|
|
1,844 |
|
|
|
16,007 |
|
- 103 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
Depreciation |
|
|
Operating |
|
|
|
|
|
|
Operating |
|
|
Intersegment |
|
|
After |
|
|
and |
|
|
Income |
|
|
Capital |
|
|
|
Revenues |
|
|
Eliminations |
|
|
Eliminations |
|
|
Amortization |
|
|
(Loss) |
|
|
Expenditures |
|
Indirect selling,
general, and
administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,253 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
580,824 |
|
|
$ |
(4,440 |
) |
|
$ |
576,384 |
|
|
$ |
17,597 |
|
|
$ |
26,609 |
|
|
$ |
66,352 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
32,962 |
|
|
$ |
(64 |
) |
|
$ |
32,898 |
|
|
$ |
4,376 |
|
|
$ |
9,314 |
|
|
$ |
4,708 |
|
Natural gas services |
|
|
301,676 |
|
|
|
|
|
|
|
301,676 |
|
|
|
356 |
|
|
|
6,003 |
|
|
|
1,669 |
|
Marine transportation |
|
|
37,724 |
|
|
|
(2,273 |
) |
|
|
35,451 |
|
|
|
4,942 |
|
|
|
2,384 |
|
|
|
6,020 |
|
Sulfur |
|
|
37,472 |
|
|
|
(688 |
) |
|
|
36,784 |
|
|
|
1,790 |
|
|
|
2,937 |
|
|
|
9,514 |
|
Fertilizer |
|
|
31,838 |
|
|
|
(204 |
) |
|
|
31,634 |
|
|
|
1,178 |
|
|
|
1,785 |
|
|
|
2,903 |
|
Indirect selling,
general, and
administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,463 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
441,672 |
|
|
$ |
(3,229 |
) |
|
$ |
438,443 |
|
|
$ |
|