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
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For the fiscal year ended
December 31, 2009
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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.) |
4200 Stone Road Kilgore, Texas 75662
(Address of principal executive offices) (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 whether the Registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the Registrant was required to submit and post such files).
Yes o 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, a non-accelerated filer, or a smaller reporting company. See definition of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large accelerated filer o
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Accelerated filer þ
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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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, 2009, 13,688,152 common units were outstanding. The aggregate market value
of the common units held by non-affiliates of the registrant as of such date approximated
$190,489,698 based on the closing sale price on that date. There were 17,707,832 of the
registrants common units and 889,444 of the registrants subordinated units outstanding as of
March 4, 2010.
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 four 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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Sulfur and sulfur-based products processing, manufacturing, marketing and
distribution; and |
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Marine transportation services for petroleum products and by-products. |
The petroleum products and by-products we gather, process, 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
generate the majority of our cash flow from fee-based contracts with these customers. Our location
in the Gulf Coast region of the United States provides us strategic access to 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. As of March 4, 2010, Martin Resource Management
owns an approximate 40.0% 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.
The historical operation of our business segments by Martin Resource Management provides us
with several decades of experience and a demonstrated track record of customer service across our
operations. Our current lines of business have been developed and systematically integrated over
this period of more than 50 years, including natural gas services (1950s); sulfur (1960s); marine
transportation (late 1980s) and terminalling and storage (early 1990s). This development of a
diversified and integrated set of assets and operations has produced a complementary portfolio of
midstream services that facilitates the maintenance of long-term customer relationships and
encourages the development of new customer relationships.
Primary Business Segments
Our primary business segments can be generally described as follows:
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Terminalling and Storage. We own or operate 12 marine shore based terminal
facilities and 11 specialty terminal facilities located in the United States Gulf
Coast region that provide storage, processing and handling services for producers
and suppliers of petroleum products and by-products, lubricants and other liquids,
including the refining of various grades and quantities of naphthenic lubricants
and related products. Our facilities and resources provide us with the ability to
handle various products that require specialized treatment, such as molten sulfur
and asphalt. We also provide land rental to oil and gas companies along with
storage and handling services for lubricants and fuel oil. We provide these
terminalling and storage services on a fee basis primarily under long-term contracts. A significant portion of the contracts in this segment
provide for minimum fee arrangements that are not based on the volumes handled. |
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Natural Gas Services. Through our acquisitions of Prism Gas Systems I, L.P.
(Prism Gas) and Woodlawn Pipeline Co., Inc. (Woodlawn), we have ownership
interests in over 615 miles of gathering and transmission 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 285
MMcfd capacity natural gas processing plant located in East Texas. In |
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addition to our 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 and storage facilities for wholesale deliveries to propane
retailers, refineries and industrial NGL users in Texas and the Southeastern United
States. We own an NGL pipeline which spans approximately 200 miles running from
Kilgore to Beaumont, Texas. We own three NGL supply and storage facilities with an
aggregate above-ground storage capacity of approximately 3,000 barrels and we lease
approximately 2.2 million barrels of underground storage capacity for NGLs. We
believe we have a natural gas processing competitive advantage in East Texas with
the only full fractionation facilities serving this area. The recent acquisition of
natural gas gathering and processing assets from Crosstex Energy, L.P. and Crosstex
Energy, Inc. by our Waskom Gas Processing Company (a joint venture in which we
participate with Center Point Energy Gas Processing Company, an indirect,
wholly-owned subsidiary of CenterPoint Energy, Inc.) further strengthens our East
Texas infrastructure. |
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Sulfur Services. We have developed an integrated system of
transportation assets and facilities relating to sulfur services over the last 30
years. We process and distribute sulfur predominantly produced by oil refineries
primarily located in the United States Gulf Coast region. We handle molten sulfur
on contracts that are tied to sulfur indices and tend to provide stable margins. We
process molten sulfur into prilled or pelletized sulfur on take or pay fee
contracts at our facilities in Port of Stockton, California and Beaumont, Texas.
The sulfur we process and handle is primarily used in the production of fertilizers
and industrial chemicals. We own and operate six sulfur-based 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. In October 2007, we completed
the construction of a sulfuric acid production plant in Plainview, Texas which
processes molten sulfur into sulfuric acid. Demand for our sulfur products exists
in both the domestic and foreign markets, and we believe our asset base provides us
with additional opportunities to handle increases in U.S. supply and access to
foreign demand. |
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Marine Transportation. We own a fleet of 40 inland marine tank barges, 17
inland push boats and four offshore tug barge units that transport petroleum
products and by-products largely in the United States Gulf Coast region. We provide
these transportation services on a fee basis primarily under annual contracts and
many of our customers have long standing contractual relationships with us. Over
the past several years, we have focused on modernizing our fleet. As a result, the
average age of our vessels has decreased from 33 years in 2006 to 22 years as of
March 4, 2010 and we anticipate that the average age will be 19 years at the end of
2010. This modernized asset base is attractive both to our existing customers as
well as potential new customers. In addition, our fleet contains several vessels that
reflect our focus on specialty products. For example, we are one of a very limited
number of companies that can transport molten sulfur. |
2009 Developments and Subsequent Events
Recent Acquisitions
Acquisition of Cross Assets. On November 25, 2009, we closed a transaction with Martin
Resource Management and Cross Refining & Marketing, Inc. (Cross), a wholly owned subsidiary of
Martin Resource Management, in which we acquired certain specialty lubricants processing assets (Assets)
from Cross for total consideration of $44.9 million (the Contribution). As consideration for the
Contribution, we issued 804,721 of our common units and 889,444 subordinated units to Martin
Resource Management at a price of $27.96 and $25.16 per limited partner unit, respectively. The
common units will be entitled to receive distributions beginning in February 2010, while the
subordinated units will have no distribution rights until the second anniversary of closing of the
Contribution. At the end of such second anniversary, the subordinated units will automatically
convert to common units, having the same distribution rights as existing common units. In
connection with the Contribution, our general partner made a capital contribution of $0.9 million
to us in order to maintain its 2% general partner interest in us.
In connection with the closing of the Contribution, we and Martin Resource Management entered
into a long-term, fee for services-based Tolling Agreement whereby Martin Resource Management
agreed to pay us for the processing of its crude oil into finished products, including naphthenic
lubricants, distillates, asphalt and other intermediate cuts. Under the Tolling Agreement, Martin
Resource Management generally agreed to refine a minimum of 6,500 barrels per day of crude oil at
the refinery at a price of $4.00 per barrel. Any additional barrels will be refined at a price of
$4.28 per barrel. In addition, Martin Resource Management agreed to pay a monthly reservation fee
of $1.3 million and a periodic fuel surcharge fee based on certain parameters specified in the
Tolling Agreement. All of these fees (other than the fuel surcharge) are subject to escalation
annually based upon the greater of 3% or the increase in the
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Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward
adjustment in the fees subject to their mutual agreement. The Tolling Agreement has a 12-year term,
subject to certain termination rights specified therein. Martin Resource Management will continue
to market and distribute all finished products under the Cross brand name. In addition, Martin
Resource Management will continue to own and operate the Cross packaging business.
The acquisition of the Cross assets was considered a transfer of net assets between entities
under common control. Accordingly, we are required to revise our financial statements to include
activities of the Cross assets as of the date of common control. Our historical financial
statements have been recast to reflect the results attributable to the Cross assets as if we owned
the Cross assets for all periods presented.
Acquisition of the East Harrison Pipeline System. In December 2009, we acquired, through
Prism Gas, from Woodward Partners, Ltd., 6.45 miles of gathering pipeline referred to as the East
Harrison Pipeline System for approximately $0.3 million. The system currently transports
approximately 500 Mcfd of natural gas under various transport contracts which provide for a minimum
monthly fee.
Other Developments
Fourth Amendment to Credit Agreement. On December 21, 2009, we entered into a Fourth
Amendment (the Fourth Amendment) to the Second Amended and Restated Credit Agreement (the Credit
Agreement), among Martin Operating Partnership L.P., a wholly-owned subsidiary of ours (the
Operating Partnership), as borrower, the Partnership and certain of our subsidiaries, as
guarantors, the financial institutions parties thereto, as lenders, Royal Bank of Canada, as
administrative agent and collateral agent, and the various other agents and parties thereto. The
Fourth Amendment modified our existing Credit Agreement to, among other things, (1) increase the
total commitments of the lenders thereunder from $325.0 million to approximately $335.7 million,
(2) provide that the term loans thereunder will automatically convert to revolving loans on
November 10, 2010, such that after giving effect to such conversion the aggregate revolving loan
commitments will be approximately $335.7 million, (3) extend the maturity date of amounts
outstanding under the Credit Agreement from November 10, 2010 to November 9, 2012, (4) increase the
applicable interest rate margin and fees payable to the lenders under the Credit Agreement, (5)
amend the financial covenants and certain other covenants under the Credit Agreement, (6) include
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 $375.0 million for
all term loan and revolving loan commitments under the Credit Agreement, (7) eliminate the
requirement that we make annual prepayments of the term loans outstanding under the Credit
Agreement with excess cash flow, (8) eliminate the swing line facility under the Credit Agreement
and (9) limit asset dispositions to $25 million per fiscal year.
Conversion of Subordinated Units Issued at Formation of Partnership. On November 14, 2009,
all of our remaining 850,674 outstanding subordinated units, which were issued at the formation of
the partnership and owned by Martin Resource Management through a subsidiary, converted into common
units on a one-for-one basis following our quarterly cash distribution on such date. All of the 4,253,362 original subordinated units
issued to Martin Resource Management have been converted into common units on a one-for-one basis
since the formation of the Partnership.
Investment by Martin Resource Management. On November 25, 2009, we closed a private equity
sale with Martin Resource Management, under which Martin Resource Management invested $20.0 million
in cash in the Partnership in exchange for 714,285 of our common units (the Investment). In
connection with the Investment, our general partner made a capital contribution to us of $0.4
million in order to maintain its 2% general partner interest in us. Proceeds from the Investment
were used to repay borrowings under our credit facility.
Subsequent Events
Fifth Amendment to Credit Agreement. On January 14, 2010, we entered into a Fifth Amendment
(the Fifth Amendment) to the Credit Agreement. The Fifth Amendment modified the Credit Agreement
to, among other things, (1) permit us to invest up to $25 million in our joint ventures and (2)
limit our ability to make capital expenditures.
Increase Joinder. On February 25, 2010, we entered into a Commitment Increase and Joinder
Agreement (the Increase Joinder) with respect to the Credit Agreement. The Increase Joinder
increased the maximum amount of borrowings and letters of credit under our credit facility from
approximately $335.7 million to $350.0 million.
Acquisition
by Waskom of the Harrison Pipeline System. On January 15,
2010, we,
through Prism Gas, as 50% owner and the operator of Waskom Gas Processing Company (WGPC), through
WGPCs wholly owned subsidiaries Waskom Midstream LLC and Olin Gathering LLC, acquired from
Crosstex North Texas Gathering, L.P., a 100% interest in approximately 62 miles of gathering
pipeline, two 35 MMcfd dew point control plants and equipment
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referred to as the Harrison Pipeline System. The Partnerships share of the acquisition cost is approximately $20.0 million.
Quarterly Distribution. On January 21, 2010, we declared a quarterly cash distribution of
$0.75 per common unit for the fourth quarter of 2009, or $3.00 per common unit on an annualized
basis, to be paid on February 12, 2010 to unitholders of record as of February 5, 2010, reflecting
no change over the quarterly distribution paid in respect to the third quarter of 2009.
Public Offering. On February 8, 2010, we completed a public offering of 1,650,000 common
units, resulting in net proceeds of $50.6 million, after payment of underwriters discounts,
commissions and offering expenses. Our general partner contributed $1.1 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.
Business Strategy
The key components of our business strategy are to:
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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. This ability to pursue organic growth opportunities which
can be seen in the construction of our Beaumont, Texas sulfur prilling facility, which
provides our customers with access to foreign markets. |
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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 product and service
offerings to existing customers is the most efficient and cost-effective method of
achieving organic growth. We believe significant opportunities exist to expand our
customer base and provide additional services and products to existing customers. |
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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. Our acquisitions have tended to focus on targets
with which we are familiar through historical business relations (as suppliers or
customers). This allows us to seek out operations that we believe will be strengthened
by our management team and existing operations. An example of our strategy is the
acquisition of our Prism subsidiary in 2005 which complemented and expanded our NGL
distribution capabilities. We believe that our diversified base of operations provides
multiple platforms for strategic growth through acquisitions. |
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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. Due to our diversified portfolio of assets and the comprehensive
solutions provided thereby, we believe we are an attractive partner for the pursuit of
strategic alliances and we intend to pursue strategic alliances with customers in the
future. |
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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. Our focus on geographic expansion can be seen in the 2005 acquisition
of our Bay Sulfur assets in Stockton, California which allowed for us to establish our
presence in the West Coast sulfur markets. |
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Maintain Financial Strength and Flexibility. We continue to seek
additional long-term, fee-based contracts to further minimize our exposure to commodity
price fluctuations and sustain our long-term customer relationships. We continue to
hedge a significant portion of our remaining exposure to commodity price fluctuations.
In addition, we intend to continue to maintain a strong balance sheet by financing
growth through a combination of long-term debt and equity, with the goal of having
flexibility to fund future organic growth and strategic acquisitions through
opportunistically accessing the capital markets. |
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 integrated distribution network consisting of
transportation, terminalling and storage 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
with a complementary portfolio of transportation, terminalling, distribution and
other midstream services for petroleum products and by-products. We believe our
customers value the efficiency of using this complementary portfolio as opposed to
contracting with a varying number of other service providers to obtain the same
services. |
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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 comprehensive
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. In addition, our natural gas services business is well
positioned in the East Texas area with the only full fractionation facilities
serving this area. |
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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. 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 allow us to enhance
relationships with our customers by offering them services to handle their unique
product requirements. These specialized assets, and the comprehensive solutions
provided thereby, provide us with the flexibility to require minimum fee contracts
with certain of our customers that require these specialized services. |
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Ability for Growth Across Multiple Segments. Our distinct lines of business allow
us to allocate capital to the most promising growth opportunities based on current
and anticipated market conditions. 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. We believe Prism Gas assets are
well situated in the Haynesville Shale, which is one of the four largest U.S. shale
deposits, and anticipate growth opportunities as these deposits are further
developed. Additionally, we believe we could significantly increase our sulfur
processing capacity with minimal capital investment. |
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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 30 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 18 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 |
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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 Strength and Flexibility. We have historically financed our operations
with a combination of debt and equity while maintaining a modest leverage profile,
even in challenging business environments. Since our initial public offering, we
have accessed the public equity markets 4 times for $241.0 million in total net
proceeds, including capital contributions from our general partner. We have also
occasionally issued units to Martin Resource Management in exchange for cash or
assets. |
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Fee-Based Contracts and Active Commodity Risk Management. We generate a majority
of our cash flow from fee-based contracts with our customers. In addition, a
significant portion of these fee-based contracts consist of reservation charges or
minimum fee arrangements, which reduce the volatility of a portion of cash flows to
volume fluctuations. We seek to further minimize our exposure to commodity price
fluctuations through swaps for crude oil, natural gas and natural gasoline. As of December 31, 2009, Prism Gas has hedged approximately 50% of its
commodity risk by volume for 2010. |
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. 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 Shore Based Terminals. We own or operate 12 marine shore based terminals along the
Gulf Coast from Venice, Louisiana 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.
We are one of the largest operators of marine shore based 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
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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. In addition, Martin Resource Management, through
contractual arrangements, pays us for terminalling and storage of fuel oil and lubricants at these
terminal facilities.
Our 12 marine shore based terminals are divided into two classes of terminals: (i) full
service terminals and (ii) fuel and lubricant terminals.
Full Service Terminals. We own or operate eight full service terminals. These terminal
facilities provide logistical support services and provide storage and handling services for fuel
oil and lubricants. 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 of our full service terminals are primarily oil and gas 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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Tanks |
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|
Aggregate Capacity |
|
Pelican Island |
|
Galveston, Texas |
|
|
51.3 |
|
|
|
16 |
|
|
87,200 Bbls. |
Harbor Island(1) |
|
Harbor Island, Texas |
|
|
25.5 |
|
|
|
12 |
|
|
32,500 Bbls. |
Freeport |
|
Freeport, Texas |
|
|
17.8 |
|
|
|
1 |
|
|
8,300 Bbls. |
Port OConnor(2) |
|
Port OConnor, Texas |
|
|
22.8 |
|
|
|
8 |
|
|
7,000 Bbls. |
Sabine Pass(3) |
|
Sabine Pass, Texas |
|
|
23.1 |
|
|
|
11 |
|
|
17,000 Bbls. |
Cameron
East(4) |
|
Cameron, Louisiana |
|
|
34.3 |
|
|
|
12 |
|
|
34,000 Bbls. |
Cameron
West(5) |
|
Cameron, Louisiana |
|
|
16.9 |
|
|
|
5 |
|
|
16,500 Bbls. |
Venice (6) |
|
Venice, Louisiana |
|
|
2.8 |
|
|
|
2 |
|
|
15,000 Bbls. |
|
|
|
(1) |
|
A portion of this terminal is located on land owned by a third party and leased under a lease
that expires in January 2015. |
|
(2) |
|
This terminal is located on land owned by a third party and leased under a lease that expires
in March 2014. |
|
(3) |
|
A portion of this terminal is located on land owned by a third party and leased under a lease
that expires in September 2036. |
|
(4) |
|
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. |
|
(5) |
|
This terminal is located on land owned by a third party and leased under a lease that expires
in February 2013. |
|
(6) |
|
This terminal is located on land owned by a third party and leased under a sublease
agreement that expires in August 2012. |
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 services for lubricants and fuel oil.
The following is a summary description of our fuel and lubricant terminals:
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminal |
|
Location |
|
|
Tanks |
|
|
Aggregate Capacity |
|
Amelia |
|
Amelia, Louisiana |
|
|
17 |
|
|
14,900 Bbls. |
Berwick(1) |
|
Berwick, Louisiana |
|
|
2 |
|
|
25,000 Bbls. |
Intracoastal City(2)(3) |
|
Intracoastal City, Louisiana |
|
|
16 |
|
|
39,000 Bbls. |
Fourchon(4) |
|
Fourchon, Louisiana |
|
|
11 |
|
|
80,000 Bbls. |
|
|
|
(1) |
|
This terminal is located on land owned by third parties and leased under a lease that expires
in September 2012 and can be extended by us through September 2017. |
|
(2) |
|
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 expired in January 2010 and is automatically renewed on
a monthly basis. |
|
(3) |
|
A portion of this terminal is located on land owned by third parties and leased under a lease
that expires in April 2014. |
|
(4) |
|
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. |
- 7 -
Specialty Petroleum Terminals. We own or operate 11 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 2.24 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. 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.
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 commenced on December 16, 2006 with two
five-year options. Our Stanolind terminal is located on approximately 11 acres of land owned by us
located on the Neches River in 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 either a fixed monthly fee or a
throughput 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. In addition, a significant portion of the contracts for our
specialty terminals provide for minimum fee arrangements that are not based on the volume handled.
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.
In Channelview, Texas, we operate an inland terminal used for lubricant blending, 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 Smackover, Arkansas, we own a refining terminal where we process crude oil into finished
products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts. This
process is dedicated to an affiliate of Martin Resource Management through a long-term tolling
agreement based upon throughput rates and a monthly reservation fee.
In Houston, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin
Resource Management through a terminalling service agreement based on 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.
In Omaha, Nebraska, we own an asphalt terminal whose use is dedicated to an affiliate of
Martin Resource Management through a terminalling service agreement based on throughput rates.
In Beaumont, Texas we own Spindletop Terminal where we receive natural gasoline via pipeline
and then ship the product to our customers via other pipelines to which the facility is connected.
Our fees for the use of this facility are based on the number of barrels shipped from the terminal.
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:
- 8 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
|
|
|
Terminal |
|
Location |
|
Tanks |
|
Capacity |
|
Products |
|
Description |
Tampa(1) |
|
Tampa, Florida |
|
8 |
|
779,000 Bbls. |
|
Asphalt, sulfur and fuel oil |
|
Marine terminal, loading/unloading for vessels, barges railcars and trucks |
|
|
|
|
|
|
|
|
|
|
|
Stanolind |
|
Beaumont, Texas |
|
8 |
|
555,000 Bbls. |
|
Asphalt, crude oil, sulfur, sulfuric acid and fuel oil |
|
Marine terminal, marine dock for loading/unloading of vessels, barges, railcars and trucks |
|
|
|
|
|
|
|
|
|
|
|
Neches |
|
Beaumont, Texas |
|
7 |
|
500,400 Bbls. |
|
Ammonia, asphalt, fuel oil, crude oil and sulfur-based 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 barges and trucks |
|
|
|
|
|
|
|
|
|
|
|
Corpus Christi |
|
Corpus Christi, Texas |
|
4 |
|
330,000 Bbls. |
|
Fuel oil and diesel |
|
Marine Terminal, loading/unloading barges and vessels and unloading trucks |
|
|
|
|
|
|
|
|
|
Terminal |
|
Location |
|
Aggregate Capacity |
|
Products |
|
Description |
Channelview
|
|
Houston, Texas
|
|
34,000 sq. ft.
Warehouse/29,000
Bbls
|
|
Lubricants
|
|
Lubricants blending and truck loading/unloading |
|
|
|
|
|
|
|
|
|
Cross Refining
|
|
Smackover, Arkansas
|
|
7,500 Bbls per day
|
|
Naphthenic
lubricants,
Distillates,
Asphalt
|
|
Crude refining facility |
|
|
|
|
|
|
|
|
|
South Houston
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 |
|
|
|
|
|
|
|
|
|
Omaha Asphalt
|
|
Omaha, Nebraska
|
|
114,225 Bbls
|
|
Asphalt
|
|
Asphalt Processing and storage |
|
|
|
|
|
|
|
|
|
Spindletop
|
|
Beaumont, Texas
|
|
90,000 Bbls
|
|
Natural Gasoline
|
|
Pipeline receipts and shipments |
|
|
|
(1) |
|
This terminal is located on land owned by the Tampa Port Authority that was leased to us
under a 10-year lease that expires in December 2016 with two five-year extension options. |
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.
- 9 -
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, anhydrous ammonia and 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.
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, alkylation or MTBE 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 natural gas processors and, to a lesser
extent, major domestic oil refiners. 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 |
|
Location |
|
Capacity |
|
Description |
Wholesale terminals
|
|
Arcadia, Louisiana(1)
|
|
2,000,000 barrels
|
|
Underground storage |
|
|
Hattiesburg, Mississippi(2)
|
|
100,000 barrels
|
|
Underground storage |
|
|
Mt. Belvieu, Texas(3)(2)
|
|
40,000 barrels
|
|
Underground storage |
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 |
|
|
|
(1) |
|
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. |
|
(2) |
|
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. |
|
(3) |
|
In addition, under a throughput agreement, we are entitled to the access and use of a
truck loading and unloading and pipeline distribution terminal owned by Enterprise Products
and located at Mont Belvieu, Texas. Effective |
- 10 -
|
|
|
|
|
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
8,000 barrels. |
Our NGL customers that utilize these assets consist of retail propane distributors, industrial
processors and refiners. For the year ended December 31, 2009, we sold approximately 32% of our NGL
volume to independent retail propane distributors located in Texas and the southeastern United
States and approximately 68% 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 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.
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. 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 615 miles of 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 285 MMcfd
natural gas processing plant located in East Texas. The underlying assets are in two operating
areas:
East Texas and North Central Texas
The East Texas and North Central Texas area assets consist of the Waskom Processing Plant,
Woodlawn, the McLeod Gathering System, the Hallsville Gathering System, the Marshall Line,
Bosque County Pipeline (BCP), the East Texas Gathering System and the Prism Liquids
Pipeline.
|
|
|
Waskom Processing Plant The Waskom Processing Plant, located in Harrison
County in East Texas, currently has 285 MMcfd of processing capacity with full
fractionation facilities. Expansions to the processing plant were completed in March
and June of 2007, July of 2008 and June of 2009 increasing the capacity from 150 MMcfd
to 285 MMcfd. In June 2009, the Waskom fractionator was expanded to a capacity of
14,500 barrels per day (bpd). For the years ended December 31, 2009 and 2008, inlet
throughput and NGL fractionation averaged approximately 243 and 257 MMcfd and 10,034
and 10,542 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. |
|
|
|
|
Harrison Pipeline System In January of 2010, as 50% owner and operator of
Waskom Gas Processing Company, through Waskom Gas Processing Companys wholly owned
subsidiaries Waskom Midstream LLC and Olin Gathering LLC, we acquired the Harrison
Pipeline System, located in Harrison County in East Texas. The system consists of
approximately 62 miles of gathering pipeline, two 35 MMcfd dew point control plants and
various equipment. We will reflect the results of operations from this system using
the equity method of accounting. |
- 11 -
|
|
|
Woodlawn Plant and Gathering System On May 2, 2007, we, through our subsidiary
Prism Gas, acquired 100% of the outstanding stock of Woodlawn. The results of
Woodlawns operations have been included in our consolidated financial statements
beginning May 2, 2007. Woodlawn is a natural gas gathering and processing company
which owns integrated gathering and processing assets in East Texas. Woodlawns system
consists of approximately 142 miles of natural gas gathering pipe, approximately 33
miles of condensate transport pipe and a 30 MMcfd processing plant. Prism Gas acquired
a nine-mile pipeline from a Woodlawn related party that delivers residue gas from the
Woodlawn plant to the Texas Eastern Transmission pipeline system. |
|
|
|
|
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 years ended December
31, 2009 and 2008, the McLeod Gathering System gathered approximately 4 and 5 MMcfd of
natural gas, respectively. Prism Gas owns a consolidated 100% interest in this system. |
|
|
|
|
East Harrison Gathering System In December of 2009, we acquired 6.45
miles of gathering pipeline referred to as the East Harrison Pipeline System. For
December 2009, the system transported 514 Mcfd. Prism Gas owns a consolidated 100%
interest in this system. |
|
|
|
|
Hallsville Gathering System The Hallsville Gathering System, which
Prism Gas constructed in 2006 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. For the years ended December 31, 2009 and
2008, the Hallsville Gathering System gathered approximately 18 and 21 MMcfd of natural
gas, respectively. 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 owned an
unconsolidated 20% non-operating interest in a partnership that owned the lease rights
to the assets of the Bosque County Pipeline, with Panther Pipeline Ltd. owning a 42.5%
operating interest and two unrelated parties owning the remaining 37.5% interest. The
lease contract terminated in June 2009. |
|
|
|
|
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 Woodlawn Plant and Gathering
System, 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 and Haynesville formations 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 419 and 2,323 in calendar years 2009 and
2008, respectively. These annual permit numbers include 200 and 261 permits for horizontal wells
in 2009 and 2008, respectively. Improved technology and drilling applications have enhanced the
economics of drilling in the Cotton Valley formation; however, in 2009 the economic benefit was
more than offset by lower prices and as a result drilling activity declined. We anticipate that
drilling activity in 2010 will begin to recover from the low levels of 2009.
- 12 -
In 2008 and 2009, development of the Haynesville Shale began. The Haynesville Shale is one of
the four largest U.S. shale deposits. One of the largest producers in the Haynesville Shale
estimates the formation will ultimately produce over 500 TCF of natural gas and will be among the
top 10 natural gas fields in the world. Haynesville gas contains less natural gas liquids than
Cotton Valley gas and as a result, in 2009, the inlet stream to Waskom Processing Plant contained
less natural gas liquids than the historical average.
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 70% of the 257 MMcfd of natural gas supplied in 2008 and
approximately 64% of the 243 MMcfd of natural gas supplied for the year ended December 31, 2009. A
substantial portion (approximately 26%) 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. In June 2009, we completed
construction to expand the fractionator to 14,500 bpd to provide additional capacity for the
increase in NGL volumes from the plant expansion that was underway and trucked-in NGL volumes. In
2009, trucked-in NGL volumes decreased along with the decline in drilling activity. The processing
plant was expanded to 285 MMcfd in four phases with the first expansion of 30 MMcfd being completed
in March 2007, the second expansion of 70 MMcfd being completed in June 2007, the third phase of 15
MMcfd being completed in July 2008 and the fourth phase of 20 MMcfd being completed in June 2009.
There are currently five cryogenic processing plants that compete with Waskom for natural gas
supplies. Drilling activity in the Cotton Valley formation 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.
The processing contracts for the Waskom Processing Plant are primarily percent-of-liquids
(POL) contracts, in which we retain a portion of the NGLs recovered as a processing fee,
percent-of-proceeds (POP) contracts in which we retain a portion of both the residue gas and the
NGLs as payment for services and straight fee contracts in which we receive a fee for every Mcf of
gas delivered to the plant. Currently, approximately 50% of the contracts are POL, 34% of the
contracts are fee and 16% of the contracts are POP. In addition, there is one minor contract for
processing on a keep-whole basis.
Woodlawn provides gathering and processing services. The Woodlawn gathering system provides
both low and intermediate pressure gathering services. The gas is gathered to a 30 MMcfd
refrigerated gas processing plant. The NGLs that are recovered at Woodlawn are trucked to the
Waskom Processing Plant for fractionation. For both years ended December 31, 2009 and 2008, the
system gathered and processed 24 MMcfd. The contracts on the Woodlawn system are primarily
wellhead purchase with some POP contracts.
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 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 POP contracts. Natural gas gathered in the region surrounding the McLeod Gathering
System has two primary outlets, including the Waskom Processing Plant.
Cotton Valley and Haynesville 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 POL contracts with a small gathering fee. These contracts are typically lower margin, higher
volume contracts. The Haynesville wells are typically fee based gathering. 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.
- 13 -
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 East Texas Gathering System was constructed in 2004 to tie producers into DCP Midstreams
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.
The Prism Liquids Pipeline condensate system was formed from the condensate pipeline system
obtained in the Woodlawn acquisition. The system was subsequently extended approximately 10 miles
using lateral lines to gather condensate from additional locations. The pipeline is a common
carrier under the Rules and Regulations of the Railroad Commission of Texas, Oil and Gas Division
and, as such, operates under a tariff filed with the Railroad Commission of Texas. The system
gathers and transports condensate for producers along the main line which extends south from the
Woodlawn Plant to the Carthage Plant operated by DCP Midstream.
Gulf Coast
The Gulf Coast area assets consist of the Fishhook Gathering System and the Matagorda
Offshore Gathering System (Matagorda) located offshore and onshore of the Texas Gulf
Coast.
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Fishhook Gathering System The Fishhook Gathering System, located in
Jefferson County, Texas offshore federal waters, gathers and transports gas in both
offshore and onshore areas. In September 2008, Hurricane Ike caused extensive damage to
an offshore platform on the system. Repairs were completed in February 2009. Prior to
the hurricane damage approximately 15 MMcfd of natural gas was gathered and transported
for the year ended December 31, 2008. For the year ended December 31, 2009
approximately 26 MMcfd of natural gas was gathered and transported on the system.
Prism Gas owns an unconsolidated 50% non-operating interest in Panther Interstate
Pipeline Energy, LLC (PIPE), 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. |
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|
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 years ended December 31, 2009 and 2008,
the Matagorda Offshore Gathering System gathered approximately 10 and 15 MMcfd of
natural gas, respectively. 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 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 Jefferson County, Texas offshore federal waters
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
PIPEs 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
- 14 -
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.
Sulfur Services Segment
Industry Overview. Sulfur is a natural element and is required to produce a variety of
industrial products. In the United States, approximately 10 million tons of sulfur are 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 primarily used in the manufacture of 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.
Sulfur-based 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.
Industrial sulfur products (including sulfuric acid) 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.
Our Operations and Products. We have an integrated system of transportation assets and
facilities relating to our sulfur services. We gather 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 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 terms of our commercial sulfur contracts typically range from one to five years in length.
We handle molten sulfur on margin-based contracts. The prices in such contracts are usually tied
to a published market indicator and fluctuate 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
with remaining lives from one to two years in duration.
The sulfur prilling assets we acquired from the acquisition of Bay Sulfur in April 2005 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. In January 2007,
we completed the construction of a sulfur priller at our Neches facility in Beaumont, Texas. In
January 2009, we completed the construction of a second sulfur priller at our Neches facility in
Beaumont, Texas. The two Beaumont prillers have the capacity to process approximately 4,000 metric
tons of molten sulfur per day. We process molten sulfur into prilled sulfur on take-or-pay fee
contracts. Our sulfur prilling facilities provide refiners access to the export market for the
sale of their residual sulfur.
In late September 2007, we completed construction of a sulfuric acid production facility at
our Plainview, Texas location. This facility processes molten sulfur to produce approximately 500
short tons of sulfuric acid per day. Our sulfuric acid facility provides our Plainview fertilizer
plant with an economical supply of sulfuric acid and the remaining sulfuric production is sold to
Martin Resource Management which markets the product to third parties.
We entered the sulfur based fertilizer manufacturing business in 1990 through an acquisition.
We acquired two additional fertilizer manufacturing companies in 1998. Over the next two years we
expended significant resources to replace and update facilities and other assets 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
- 15 -
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 molten sulfur business
because of our access to sulfur and our distribution capabilities. These products allow us to
leverage the sulfur services segment of our business. Our annual fertilizer and industrial sulfur
products sales have grown from approximately 62,000 tons in 1997 to approximately 238,000 tons in
2009 as a result of acquisitions and internal growth.
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 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 products are sold in accordance with price lists that vary from state to state.
These price lists are updated periodically to reflect changes in seasonal or competitive prices.
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.
We manufacture and market the following sulfur-based fertilizer and related sulfur products:
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|
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. |
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|
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. |
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|
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. |
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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 Sulfur Services Facilities.
We own 59 railcars and lease approximately 150 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:
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Asset |
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Class of Equipment |
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Capacity/Horsepower |
|
Products Transported |
Margaret Sue
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Offshore tank barge
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10,450 long tons
|
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Molten sulfur |
M/V Martin Explorer
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Offshore tugboat
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7,200 horsepower
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N/A |
M/V Martin Express
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Inland push boat
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1,200 horsepower
|
|
N/A |
MGM 101
|
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Inland tank barge
|
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2,450 long tons
|
|
Molten sulfur |
MGM 102
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Inland tank barge
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2,450 long tons
|
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Molten sulfur |
- 16 -
We own the following sulfur prilling facilities as part of our sulfur services business:
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Terminal |
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Location |
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Daily Production Capacity |
|
Products Stored |
Stockton
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Stockton, California
|
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1,000 metric tons per day
|
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Molten and prilled sulfur |
Neches
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Beaumont, Texas
|
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4,000 metric tons per day
|
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Molten and prilled sulfur |
We lease approximately 40 railcars to transport ammonium thiosulfate. We own the following
manufacturing plants as part of our sulfur services business:
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Facility |
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Location |
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Capacity |
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Description |
Fertilizer plants (two)
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Odessa, Texas
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70,000 tons/year
|
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Dry sulfur fertilizer production |
Fertilizer plant
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Seneca, Illinois
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36,000 tons/year
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Dry sulfur fertilizer production |
Fertilizer plant
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Plainview Texas
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180,000 tons/year
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Fertilizer production |
Fertilizer plant
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Salt Lake City, Utah
|
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25,000 tons/year
|
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Blending and packaging |
Fertilizer plant strial sulfur
plant
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Beaumont, Texas
|
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70,000 tons/year
|
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Liquid sulfur fertilizer production |
Industrial sulfur plant
|
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Texarkana, Texas
|
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18,000 tons/year
|
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Emulsified sulfur production |
Sulfuric acid plant
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Plainview Texas
|
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150,000 tons/year
|
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Sulfuric acid production |
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
United States ports on the Gulf of Mexico and Tampa, Florida. 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. Our sulfuric acid products compete with regional producers and importers in the South and
Southwest portion of the U.S. from Louisiana to California. Our sulfur-based fertilizer products
compete with several large fertilizer and sulfur products manufacturers. However, the close
proximity of our manufacturing plants to our customer base is a competitive advantage for us in the
markets we serve and allows us to minimize freight costs and respond quickly to customer requests.
Seasonality. Sales of our agricultural fertilizer products are partly seasonal as a result of
increased demand during the growing season.
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 coastwise along the Gulf of Mexico and 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.
- 17 -
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:
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|
Class of Equipment |
|
Number in Class |
|
Capacity/Horsepower |
|
Description of Products Carried |
Inland tank barges |
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12 |
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20,000 bbl and under |
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Asphalt, crude oil, fuel oil, |
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gasoline and sulfur(1) |
Inland tank barges |
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28 |
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20,000 - 30,000 bbl |
|
Asphalt, crude oil, fuel oil |
|
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and gasoline(1) |
Inland push boats |
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17 |
|
800 - 3,800 |
|
N/A |
|
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|
|
horsepower |
|
|
Offshore tank barges |
|
4 |
|
40,000 bbl and 95,000 |
|
Asphalt, fuel oil and NGLs |
|
|
|
|
bbl |
|
|
Offshore tugboats |
|
4 |
|
3,200 - 7,200 |
|
N/A |
|
|
|
|
horsepower |
|
|
|
|
|
(1) |
|
One of our 12 inland tank barges with capacity of up to 20,000 bbl, and 15 of our 28 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 on a fee basis primarily under annual contracts.
The average age of our vessels is 22 years as of March 4, 2010 and we anticipate that the
average age of our vessels will be 19 years by the end of 2010.
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:
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the increasing age of the domestic tank barge fleet, resulting in
retirements; |
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a reduction in tax incentives, which previously encouraged speculative
construction of new equipment; |
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stringent operating standards to adequately address safety and
environmental risks; |
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the elimination of government programs supporting small refineries; |
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an increase in environmental regulations mandating expensive equipment
modification; and |
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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:
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significant start-up capital requirements; |
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the costs and operational difficulties of complying with stringent safety
and environmental regulations; |
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the cost and difficulty in obtaining insurance; and |
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the number and expertise of personnel required to support marine fleet
operations. |
- 18 -
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 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.
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; |
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|
|
|
distributing fuel oil, asphalt, sulfuric acid, marine fuel and other
liquids; |
|
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|
|
providing marine bunkering and other shore-based marine services in
Alabama, Louisiana, Mississippi and Texas; |
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|
operating a small crude oil gathering business in Stephens, Arkansas; |
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operating a lube oil packaging facility in Smackover, Arkansas; |
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operating an underground NGL storage facility in Arcadia, Louisiana; |
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building and marketing sulfur prillers; |
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developing an underground natural gas storage facility in Arcadia,
Louisiana; |
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supplying employees and services for the operation of our business; |
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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 |
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operating, solely for our account, the asphalt facilities in Omaha,
Nebraska. |
We are and will continue to be closely affiliated with Martin Resource Management as a result
of the following relationships.
- 19 -
Ownership
As of March 4, 2010, Martin Resource Management owned an approximate 40.0% limited partnership
interest and a 2% general partnership interest in us and all of our incentive distribution rights.
Management
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 Managements 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 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 $63.1 million of direct costs and expenses for the twelve months ended
December 31, 2009, compared to $67.5 million for the twelve months ended December 31, 2008. There
is no monetary limitation on the amount we are required to reimburse Martin Resource Management for
direct expenses.
In addition to the direct expenses, under the omnibus agreement, we are required to reimburse
Martin Resource Management for indirect general and administrative and corporate overhead expenses.
The amount of this reimbursement was capped at $2.0 million through November 1, 2007 when the cap
expired. For the years ended December 31, 2009, 2008, and 2007, the Conflicts Committee of our
general partner approved reimbursement amounts of $3.5, $2.9 and $1.5 million, respectively,
reflecting our allocable share of such expenses. The Conflicts Committee will review and approve
future adjustments in the reimbursement amount for indirect expenses, if any, annually. These
indirect expenses covered 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 Managements 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 may not be 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, and Director Independence 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 2.0 million barrels. 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.
In the aggregate, our purchases of land transportation services, NGL storage services, and
lube oil product purchases and sulfur services payroll reimbursements from Martin Resource
Management accounted for approximately
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15%, 10% and 12% of our total cost of products sold during the years ended December 31, 2009, 2008, and 2007, 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 7%, 6% and 5% of our total revenues for the years ended December 31, 2009, 2008, and
2007, respectively. In connection with the closing of the Tesoro Marine asset acquisition in 2003,
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. Additionally,
we have entered into a long-term, fee for services-based Tolling Agreement with Martin Resource
Management where Martin Resource Management agrees to pay us for the processing of its crude oil
into finished products, including naphthenic lubricants, distillates, asphalt and other
intermediate cuts.
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, and Director Independence 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.
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,
(P&I), insurance coverage is provided by P&I associations and other insurance underwriters. Our
vessels are entered in P&I associations that are parties to a pooling agreement, known as the
International Group Pooling Agreement, (Pooling Agreement), through which approximately 90% of
the worlds ocean-going 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.
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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 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
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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 Neches Terminal we use is located
in an EPA-designated ozone non-attainment area, referred to as the Beaumont/Port Arthur
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
Beaumont/Port Arthur 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 Beaumont/Port Arthur 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.
Global Warming and Climate Change. Recent scientific studies have suggested that emissions of
certain gases, commonly referred to as greenhouse gases and including carbon dioxide and methane,
may be contributing to warming of the Earths atmosphere. In response to such studies, the U.S.
Congress is actively considering climate change-related legislation to restrict greenhouse gas
emissions. At least 17 states have already taken legal measures to reduce emissions of greenhouse
gases, primarily through the planned development of greenhouse gas emission inventories and/or
regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Courts
decision on April 2, 2007, in Massachusetts, et al. v. EPA, the EPA must consider whether it is
required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if
Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The
Courts holding in Massachusetts that greenhouse gases fall under the federal Clean Air Acts
definition of air pollutant may also result in future regulation of greenhouse gas emissions from
stationary sources under various Clean Air Act programs. New legislation or regulatory programs
that restrict emissions of greenhouse gases in areas in which we conduct business could adversely
affect our operations and demand for our services.
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 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 (SWPPPs)) as well as for the prevention and control of oil spills (referred to
as spill prevention, control and countermeasure (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.
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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 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-flagged vessels be manned by United States citizens.
Foreign-flagged seamen generally receive lower wages and benefits than those received by United
States citizen seamen. This requirement significantly increases operating costs of United
States-flagged vessel operations compared to foreign-flagged 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-flagged vessel owners. The United States Coast
Guard and American Bureau of Shipping maintain the most stringent regimen of vessel inspection in
the world, which tends to result in higher regulatory compliance costs for United States-flagged
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.
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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 PIPE. PIPEs 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 (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 PIPE 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 George W. Bush signed into law the Domenici-Barton Energy Policy
Act of 2005 (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 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.
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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
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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 642 individuals who provide direct support to our
operations as of March 2, 2010. None of these employees are represented by labor unions.
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. 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. These documents may also be found at the SECs website at
www.sec.gov.
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.
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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;
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the amount, if any, of cash reserves established by our general partner in
its discretion. |
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.
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 a default or an event of default under our credit facility, or if the
payment of a distribution would cause a default or 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.
We may not be able to obtain funding on acceptable terms or at all because of the deterioration of
the credit and capital markets. This may hinder or prevent us from meeting our future capital
needs.
Global financial markets and economic conditions have been, and continue to be, disrupted and
volatile due to a variety of factors, including significant write-offs in the financial services
sector and the current weak economic conditions. As a result of these conditions, the availability
of funds from the credit and capital markets has diminished significantly and the cost of raising
money in the debt and equity capital markets has increased substantially. In particular, as a
result of concerns about the stability of financial markets generally and the solvency of lending
counterparties specifically, the cost of obtaining money from the credit markets generally has
increased as many lenders and institutional
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investors have increased interest rates, enacted
tighter lending standards, refused to refinance existing debt on similar terms or at all and
reduced, or in some cases ceased, to provide funding to borrowers. In addition, lending
counterparties under our existing revolving credit facility and other debt instruments may be
unwilling or unable to meet their funding obligations. These conditions, have made, and may
continue to make, it difficult to obtain funding for our capital needs. Due to these conditions, we
cannot be certain that new debt or equity financing will be available on acceptable terms or at
all. If funding is not available when needed, or is available only on unfavorable terms, we may be
unable to meet our obligations as they come due, complete future acquisitions or expansion and
maintenance capital projects, which could have a material adverse effect on our revenues and
results of operations.
We are exposed to counterparty risk in our credit facility and related interest rate protection
agreements.
We rely on our credit facility to assist in financing a significant portion of our working
capital, acquisitions and capital expenditures. Our ability to borrow under our credit facility may
be impaired because:
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one or more of our lenders may be unable or otherwise fail to meet its funding
obligations; |
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the lenders do not have to provide funding if there is a default under the credit
facility or if any of the representations or warranties included in the credit facility are
false in any material respect; and |
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if any lender refuses to fund its commitment for any reason, whether or not valid, the
other lenders are not required to provide additional funding to make up for the unfunded
portion. |
If we are unable to access funds under our credit facility, we will need to meet our capital
requirements, including some of our short-term capital requirements, using other sources.
Alternative sources of liquidity may not be available on acceptable terms, if at all. If the cash
generated from our operations or the funds we are able to obtain under our credit facility or other
sources of liquidity are not sufficient to meet our capital requirements, then we may need to delay
or abandon capital projects or other business opportunities, which could have a material adverse
effect on our business, financial condition and results of operations.
In addition, we have entered into interest rate protection agreements to manage our interest
rate risk exposure by fixing a portion of the interest expense we pay on our long-term debt under
our credit facility. There is considerable turmoil in the world economy and banking markets which
could affect whether the counterparties to such interest rate protection agreements are able to
honor their agreements. If the counterparties fail to honor their commitments, we could experience
higher interest rates, which could have a material adverse effect on our business, financial
condition and results of operations. In addition, if the counterparties fail to honor their
commitments, we also may be required to replace such interest rate protection agreements with new
interest rate protection agreements, and such replacement interest rate protection agreements may
be at higher rates than our current interest rate protection agreements, which could have a
material adverse effect on our business, financial condition and results of operations.
The current economic crisis may significantly affect our customers and their ability to make
payments to us.
The current economic crisis is having profound effects on all areas of the world economy. Our
customers abilities to make payments to us when due may be adversely affected in this environment.
As such, we could see an increase in delayed or uncollected receivables that may have an adverse
effect on our results of operations, cash flow and ability to make distributions to our
unitholders.
The impacts of climate-related initiatives, at the international, federal and state levels, remain
uncertain at this time.
Currently, there are numerous international, federal and state-level initiatives and proposals
addressing domestic and global climate issues. Within the U.S., most of these proposals would
regulate and/or tax, in one fashion
or another, the production of carbon dioxide and other greenhouse gases to facilitate the
reduction of carbon compound emissions to the atmosphere, and provide tax and other incentives to
produce and use more clean energy. For example, in 2009 the U.S. House of Representatives passed
the Markey-Waxman bill (HR 2454), which would establish a so-called cap and trade regime and new
permitting requirements to regulate greenhouse gas generation, as well as provide an incentive for
the production and use of clean energy. To date, the U.S. Senate has not passed any comparable
legislation. In sum, we believe that the potential for climate change legislation on the federal
level is unknown. In addition, in late 2009, the U.S. EPA issued an endangerment finding under
the Clear Air Act (CAA) with respect to carbon dioxide, which could lead to the regulation of
carbon dioxide as a criteria pollutant under the CAA and have significant ramifications for us and
the industry in general. On the international front, the United Nations
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Climate Change Conference
in Copenhagen, which took place in December 2009, did not result in any significant progress toward
a binding agreement to replace the Kyoto Protocol, which expires in 2012.
Overall, it is possible that future legislative and regulatory activity in this area will in
some way impact us, but it is unclear at this time whether such impact will be, in the aggregate,
positive or negative, or material. We continue to monitor political and regulatory developments in
this area, but their overall impact on us, from a cost, benefit and financial performance
standpoint, is uncertain at this time.
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 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.
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 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,
Rita and Ike, 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 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 liquidity and results of
operations and ability to make distributions to our unitholders.
We purchase hydrocarbon products and by-products such as molten sulfur, sulfur derivatives,
fuel oils, LPGs, lubricants, asphalt and other bulk liquids, and sell these products to wholesale
and bulk customers and to other end users. We also generate revenues through the terminalling and
storage of certain products for third parties. The price and market value of hydrocarbon products
and by-products can be, and has recently been, volatile. Our liquidity and 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. In addition, our liquidity and costs have been
adversely affected during periods of increasing prices because of the increased costs associated
with our purchase of hydrocarbon products and by-products. Future price volatility could have an
adverse impact on our liquidity and 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, such as those experienced in the past couple of years, 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.
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 sulfur-based fertilizer products are subject to seasonal demand 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 sulfur-based
fertilizer products experience 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 products 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.
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 or 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 lenders 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.
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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,
processing 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 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.
Political, regulatory and economic factors may significantly affect our operations, the manner in
which we conduct our business and slow our rate of growth.
Due to changes in the political climate as a result of the outcome of recent state elections
and the Presidential election in the United States, we cannot predict with any certainty the nature
and extent of the changes in federal, state and local laws, regulations and policy we will face, or
the effect of such elections on any pending legislation. Any increased regulation, new policy
initiatives, increased taxes or any other changes in federal law may have an adverse effect on our
business, financial condition and results of operations.
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
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significantly increase the costs of United States flagged vessels when
compared with foreign flagged 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.
The 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. Under OPA, 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 11
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 may require us to make substantial capital expenditures, which could
adversely affect our operations and market position and reduce our cash available for distribution.
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, 2009,
and 2008, Prism Gas purchased approximately 19% and 22%,
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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 2008, the spot price of Henry Hub natural gas ranged
from a high of $13.31 per MMBtu to a low of $5.38 per MMBtu. From January 1, 2009, through
December 31, 2009, the same price ranged from $6.10 per MMBtu to $1.84 per MMBtu. On December 31,
2009, the spot price was $5.79 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,
liquidity, cash flows and financial condition.
As of December 31, 2009, Prism Gas has hedged approximately 50% of its commodity risk by
volume for 2010. These hedging arrangements are in the form of swaps for crude oil, natural gas
and natural gasoline. We anticipate entering into additional hedges in 2010 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. Such risks may be more likely due to the worldwide
financial and credit crisis.
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
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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.
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 producers 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 producers for a significant portion of our natural gas and NGL
supply. While some of these producers 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 producers, 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
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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.
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 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 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.
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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 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 $0.5 million between 2010 and 2012
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 be 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 through its subsidiaries currently holds 889,444 subordinated units
and 6,703,823 common units. The subordinated units will have no distribution rights until
February, 2012. At the end of such second anniversary, the subordinated units will automatically
convert to common units, having the same distribution rights as existing common units.
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 we may issue an unlimited number of limited
partner interests of any type without a vote of the unitholders. 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. |
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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 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 40.8% of our outstanding limited partnership units as of March 4, 2010, our
general partner initially cannot be removed without the consent of it and its affiliates.
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 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.
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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.
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. |
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.
The issuance of additional common units or other equity securities of equal or senior rank
will have the following effects:
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our unitholders proportionate ownership interest in us will decrease; |
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the amount of cash available for distribution on a per unit basis may
decrease; |
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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; |
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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 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 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 Global Select Market (NASDAQ) 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. The price of our common units may,
therefore, be volatile.
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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
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
Existing litigation between Ruben Martin and Scott Martin and related parties concerning the
ownership, management and operation of Martin Resource Management, the owner of our General
Partner, could adversely effect us.
There are several pending lawsuits
between Ruben Martin, the President, Chief Executive Officer and member of the board of directors
of our General Partner, and Scott Martin, who is Ruben Martins brother, and related parties
concerning the ownership, management and operation of Martin Resource Management, the owner of our
General Partner. We are not a party to any of those lawsuits and they do not assert any claims (i)
against us, (ii) concerning our governance or operations or (iii) against our directors, officers
or employees with respect to their service to us. The existence of those lawsuits, however,
including any ultimate outcomes that might be deemed negative to us or our existing management
team, could adversely effect our ability to access capital markets or obtain additional credit or
negatively impact our business, results of operations and/or ability to make distributions to our
unitholders. Any similar effects from such litigation on Martin Resource Management or its existing
management team could also adversely affect us.
In addition, such litigation, depending on its ultimate outcome, could also result in changes
in the existing boards of directors and management teams of Martin Resource Management and us. To
the extent that any such adverse circumstances occur, they could be deemed by our lenders to have a
material adverse effect on us, thereby providing such lenders with an opportunity to prohibit
further borrowings by us under our credit facility and, depending on the circumstances, assert that
an event of default exists thereunder. If any such event of default exists and is continuing, then,
upon the election of our lenders, all outstanding amounts due under our credit facility could be
accelerated and could become immediately due and payable. Similarly, a negative outcome in such
litigation could result in a similar result under the credit facility maintained by Martin Resource
Management. While any such litigation remains pending, there can be no assurance that the
litigation parties adverse to our existing management team or the existing management team of
Martin Resource Management will not seek to disrupt, delay or postpone any future attempts by us to access the capital markets.
For
a more detailed discussion of these pending litigation matters, please see Item 9B. Other
Information Existing Litigation at 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.
As of March 4, 2010, Martin Resource Management owns an approximate 40.0% 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
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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:
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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. |
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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 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 incentive distributions. |
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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. |
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, and Director Independence. 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.
If Martin Resource Management were ever to file for bankruptcy or otherwise default on its
obligations under its credit facility, amounts we owe under our credit facility may become
immediately due and payable and our results of operations could be adversely affected.
If Martin Resource Management were ever to commence or consent to the commencement of a
bankruptcy proceeding or otherwise defaults on its obligations under its credit facility, its
lenders could foreclose on its pledge of the interests in our general partner and take control of
our general partner. If Martin Resources Management no longer
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controls our general partner, the
lenders under our credit facility may declare all amounts outstanding thereunder immediately due
and payable. In addition, either a judgment against Martin Resource Management or a bankruptcy
filing by or against Martin Resource Management could independently result in an event of default
under our credit facility if it could reasonably be expected to have a material adverse effect on
us. If our lenders do declare us in default and accelerate repayment, we may be required to
refinance our debt on unfavorable terms, which could negatively impact our results of operations
and our ability to make distributions to our unitholders. A bankruptcy filing by or against Martin
Resource Management could also result in the termination or material breach of some or all of the
various commercial contracts between us and Martin Resource Management, which could have a material
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. In order for us to be classified
as a partnership for U.S. federal income tax purposes, more than 90% of our gross income each year
must be qualifying income under Section 7704 of the U.S. Internal Revenue Code of 1986, as
amended (the Internal Revenue Code). Qualifying income includes income and gains derived from
the transportation, storage, processing and marketing of crude oil, natural gas and products
thereof. Other types of qualifying income include interest (other than from a financial business),
dividends, gains from the sale
of real property and gains from the sale or other disposition of capital assets held for the
production of income that otherwise constitutes qualifying income. Thus, qualifying income
includes income from providing marine transportation services to customers with respect to crude
oil, natural gas and certain products thereof but does not include rental income from leasing
vessels to customers. The recent decision of the United States Court of Appeals for the Fifth
Circuit in Tidewater Inc. v. United States, 565 F.3d 299 (5th Cir. April 13, 2009) held that marine
time charter agreements are leases that generate rental income for purposes of a foreign sales
corporation provision of the Code.
After the Tidewater decision, there is some uncertainty regarding the status of a significant
portion of our income as qualifying income and, thus, whether we are classified as a partnership
for federal income tax purposes. As a result of this uncertainty, our
counsel, Baker Botts L.L.P., has previously rendered an opinion that we should (as opposed to will) be classified as a partnership for U.S.
federal income tax purposes.
Additionally, as a result of the Tidewater decision, we have requested a private letter ruling from
the U.S. Internal Revenue Service to confirm that gross income from our marine time charter
agreements constitutes qualifying income under Section 7704 of the Internal Revenue Code. There
can be no assurance that the U.S. Internal Revenue Service (the IRS) will issue a favorable
private letter ruling to us.
If the income from our marine time charters were not considered qualifying income, then we
would not have satisfied the qualifying income requirement of Section 7704 for any year of our
existence and, accordingly, we would be classified as a corporation for federal income tax
purposes. If we were treated as a corporation for federal income tax purposes, we would owe federal
income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would
likely owe state income tax at varying rates, for 2006 through the current tax year. Distributions
would generally be taxed again to unitholders as corporate distributions and no income, gains,
losses, or deductions would flow through to unitholders. Because a tax would be imposed upon us as
an entity for a period of several years, cash available for distribution to unitholders would be
reduced. Treatment of us as a corporation would result in a reduction in the anticipated cash flow
and after-tax return to unitholders and therefore would likely result in a reduction in the value
of the common units.
Moreover, current law may change so as to cause us to be treated as a corporation for federal
income tax purposes or otherwise subject us to entity-level taxation. At the federal level, members
of Congress have considered substantive changes to the existing U.S. tax laws that would have
affected certain publicly traded partnerships. Although the legislation considered would not have
appeared to affect our tax treatment, we are unable to predict whether any
such change or other proposals will ultimately be enacted. Moreover, any modification to the
federal income tax laws and interpretations thereof may or may not be applied retroactively. Any
such changes could negatively impact the value of an investment in our common units. At the state
level, because of widespread state budget deficits and other reasons, several states are evaluating
ways to subject partnerships to entity-level taxation through the imposition of state income,
franchise and other forms of taxation. For example, we are required to pay Texas franchise tax at a
maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year.
Imposition of any such tax on us by any other state will reduce the cash available for distribution
to you.
- 43 -
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, debt
security holders and our general partner.
Except
as noted above, we have not requested a ruling from the IRS with respect to our treatment as a partnership for
federal income tax purposes. 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, debt security holders 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.
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 unitholders 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
- 44 -
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, Nebraska, 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.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to
potential legislative, judicial or administrative changes and differing interpretations, possibly
on a retroactive basis.
The present United States federal income tax treatment of publicly traded partnerships,
including us, or an investment in our common units may be modified by administrative, legislative
or judicial interpretation at any time. Any modification to the United States federal income tax
laws and interpretations thereof may or may not be applied retroactively and could make it more
difficult or impossible to meet the exception for us to be treated as a partnership for United
States federal income tax purposes that is not taxable as a corporation (referred to as the
Qualifying Income Exception), affect or cause us to change our business activities, affect the
tax considerations of an investment in us, change the character or treatment of portions of our
income and adversely affect an investment in our common units. For example, in response to certain
recent developments, members of Congress are considering substantive changes to the definition of
qualifying income under Internal Revenue Code Section 7704(d) and the treatment of certain types of
income earned from profits interests in partnerships. It is possible that these efforts could
result in changes to the existing United States tax laws that affect publicly traded partnerships,
including us. We are unable to predict whether any of these changes, or other proposals will
ultimately be enacted. Any such changes could negatively impact the value of an investment in our
common units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month
period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or
exchange of 50% or more of the total interests in our capital and profits within a twelve-month
period. Our termination would, among other things, result in the closing of our taxable year for
all unitholders, which would result in us filing two tax returns (and unitholders receiving two
Schedule K-1s) for one fiscal year. For purposes of determining whether the 50% threshold is met,
multiple sales of the same units are counted only once. Our termination could also result in a
deferral of depreciation deductions allowable in computing our taxable income. In the case of a
unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of
our taxable year may also result in more than twelve months of our taxable income or loss being
includable in his taxable income for the year of termination. Our termination currently would not
affect our classification as a partnership for federal income tax purposes, but instead, we would
be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new
tax elections and could be subject to penalties if we are unable to determine that a termination
occurred.
We prorate our items of income, gain, loss, and deduction between transferors and transferees of
our units each month based upon the ownership of our units on the first day of each month, instead
of on the basis of the date a particular unit is transferred. The IRS may challenge this
treatment, which could change the allocation of items of income, gain, loss and deduction among our
unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees
of our units each month based upon the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is transferred. The use of this proration
method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is
unable to opine as to the validity of this method. If the IRS were to challenge this method or
new Treasury regulations were issued, we may be required to change the allocation of items of
income, gain, loss and deduction among our unitholders.
A unitholder whose units are loaned to a short seller to cover a short sale of units may be
considered as having disposed of those units. If so, he would no longer be treated for tax
purposes as a partner with respect to those units during the period of the loan and may recognize
gain or loss from the disposition.
Because a unitholder whose units are loaned to a short seller to cover a short sale of units
may be considered as having disposed of the loaned units, he may no longer be treated for tax
purposes as a partner with respect to those units during the period of the loan to the short seller
and the unitholder may recognize gain or loss from such disposition. Moreover, during the period
of the loan to the short seller, any of our income, gain, loss or deduction with respect to those
units may not be reportable by the unitholder and any cash distributions received by the unitholder
as to those units could
- 45 -
be fully taxable as ordinary income. Our counsel has not rendered an
opinion regarding the treatment of a unitholder where common units are loaned to a short seller to
cover a short sale of common units; therefore, unitholders desiring to assure their status as
partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify
any applicable brokerage account agreements to prohibit their brokers from borrowing their 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.
In addition to the foregoing, as a result of a routine inspection by the U.S. Coast Guard of
our tug Martin Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, we have been
informed that an investigation has been commenced concerning a possible violation of the Act to
Prevent Pollution from Ships, 33 USC 1901, et. seq., and the MARPOL Protocol 73/78. In connection
with this matter, two of our employees were served with grand jury subpoenas during the fourth
quarter of 2007. We are cooperating with the investigation and, as of the date of this report, no
formal charges, fines and/or penalties have been asserted against us.
Item 4.
Reserved
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 under the symbol MMLP. As of March 2, 2010 there
were approximately 24 holders of record and approximately 10,934 beneficial owners of our common
units. In addition, as of that date there were 889,444 subordinated units representing limited
partner interests outstanding. All of the subordinated units are held by Martin Resource
Management through a subsidiary. 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 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Units |
|
Distributions Declared per Unit |
Quarters Ended |
|
High |
|
Low |
|
Common |
|
Subordinated1 |
March 31, 2009 |
|
$ |
21.00 |
|
|
$ |
14.89 |
|
|
$ |
0.750 |
|
|
$ |
0.750 |
|
June 30, 2009 |
|
$ |
21.96 |
|
|
$ |
17.33 |
|
|
$ |
0.750 |
|
|
$ |
0.750 |
|
September 30, 2009 |
|
$ |
28.50 |
|
|
$ |
20.70 |
|
|
$ |
0.750 |
|
|
$ |
0.750 |
|
December 31, 2009 |
|
$ |
31.69 |
|
|
$ |
26.02 |
|
|
$ |
0.750 |
|
|
$ |
0.750 |
|
- 46 -
Fiscal 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Units |
|
Distributions Declared per Unit |
Quarters Ended |
|
High |
|
Low |
|
Common |
|
Subordinated1 |
March 31, 2008 |
|
$ |
37.20 |
|
|
$ |
30.50 |
|
|
$ |
0.720 |
|
|
$ |
0.720 |
|
June 30, 2008 |
|
$ |
36.24 |
|
|
$ |
31.50 |
|
|
$ |
0.740 |
|
|
$ |
0.740 |
|
September 30, 2008 |
|
$ |
32.76 |
|
|
$ |
19.23 |
|
|
$ |
0.750 |
|
|
$ |
0.750 |
|
December 31, 2008 |
|
$ |
26.99 |
|
|
$ |
13.60 |
|
|
$ |
0.750 |
|
|
$ |
0.750 |
|
|
|
|
1 |
|
All of our original 4,253,362 subordinated units which were issued upon the
formation of the Partnership and subsequently converted into common units on a one-for-one bases
received distributions prior to their conversion. The 889,444 subordinated units issued in
connection with the acquisition of the Cross assets will not receive cash distributions until
February 2012, the first distribution paid after they automatically convert into common units in
November 2011. |
On March 3, 2010, the last reported sales price of our common units as reported on the
NASDAQ was $31.91 per unit.
On November 25, 2009, we closed a transaction with Martin Resource Management and Cross, in
which we acquired certain specialty lubricants processing assets from Cross for total consideration
of $44.9 million. As consideration for the Contribution, we issued 804,721 of our common units and
889,444 subordinated units to Martin Resource Management at a price of $27.96 and $25.16 per
limited partner unit, respectively. The common units will be entitled to receive distributions
beginning in February 2010, while the subordinated units will have no distribution rights until the
second anniversary of closing of the Contribution. At the end of such second anniversary, in
November 2011, the subordinated units will automatically convert to common units, having the same
distribution rights as existing common units. In connection with the Contribution, our general
partner made a capital contribution of $0.9 million to us in order to maintain its 2% general
partner interest in us. The units were issued in reliance on the exemption from registration
provided by Section 4(2) of the Securities Act of 1933, as amended (the Securities Act). We
accounted for the Cross acquisition as a transfer of net assets between entities under common
control. The Cross assets were recorded at $33.0
million, which represents the amounts reflected in Martin Resource Managements historical
consolidated financial statements. The difference between the purchase price and Martin Resource
Managements carrying value of the combined net assets acquired and liabilities assumed was
recorded as an adjustment to partners capital.
On November 25, 2009, we closed a private equity sale with Martin Resource Management, under
which Martin Resource Management invested $20.0 million in cash in us in exchange for 714,285 of
our common units. In connection with the Investment, our general partner made a capital
contribution to us of $0.4 million in order to maintain its 2% general partner interest in us.
Proceeds from the Investment were used to repay borrowings under our credit facility. In issuing the common units, we relied on the exemption from registration
provided by Section 4(2) of the Securities Act.
All of our original 4,253,362 outstanding subordinated units owned by Martin Resource
Management and its subsidiaries, which were issued at the formation of the Partnership, converted
into common units on a one-for-one basis following our quarterly cash distributions in November
2009. The subordinated units converted as follows: 850,674 on November 14, 2009 and 850,672 each
on November 14, 2008, 2007, 2006 and 2005. The common units into which the subordinated units were
converted were issued in reliance on Section 3(a)(9) of the Securities Act.
Within 45 days after the end of each quarter, we distribute all of our available cash, as
defined in our partnership agreement, to unitholders of record on the applicable record date.
Until our current subordinated units convert into common units in November 2011, the subordinated
units will not have the right to receive distributions of available cash from operating surplus .
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.
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 a default or an event of
- 47 -
default, or a 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.
- 48 -
Item 6. Selected Financial Data
The following table sets forth selected financial data and other operating data of Martin
Midstream Partners L.P. for the years ended December 31, 2009, 2008, 2007, 2006 and 2005 is 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20091 |
|
|
20081 |
|
|
20071 |
|
|
2006 |
|
|
2005 |
|
Income Statement Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
662,385 |
|
|
$ |
1,246,444 |
|
|
$ |
804,327 |
|
|
$ |
576,384 |
|
|
$ |
438,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold |
|
|
457,259 |
|
|
|
1,013,526 |
|
|
|
618,689 |
|
|
|
459,170 |
|
|
|
351,820 |
|
Operating expenses |
|
|
117,438 |
|
|
|
126,808 |
|
|
|
104,165 |
|
|
|
65,387 |
|
|
|
46,888 |
|
Selling, general, and administrative |
|
|
19,775 |
|
|
|
19,062 |
|
|
|
13,918 |
|
|
|
10,977 |
|
|
|
8,133 |
|
Depreciation and amortization |
|
|
39,506 |
|
|
|
34,893 |
|
|
|
26,323 |
|
|
|
17,597 |
|
|
|
12,642 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
633,978 |
|
|
|
1,194,289 |
|
|
|
763,095 |
|
|
|
553,131 |
|
|
|
419,483 |
|
Other operating income |
|
|
6,013 |
|
|
|
209 |
|
|
|
703 |
|
|
|
3,356 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
34,420 |
|
|
|
52,364 |
|
|
|
41,935 |
|
|
|
26,609 |
|
|
|
18,960 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated entities |
|
|
7,044 |
|
|
|
13,224 |
|
|
|
10,941 |
|
|
|
8,547 |
|
|
|
1,591 |
|
Interest expense |
|
|
(18,995 |
) |
|
|
(21,433 |
) |
|
|
(15,125 |
) |
|
|
(12,466 |
) |
|
|
(6,909 |
) |
Debt prepayment premium |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,160 |
) |
|
|
|
|
Other, net |
|
|
326 |
|
|
|
801 |
|
|
|
405 |
|
|
|
713 |
|
|
|
238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
22,795 |
|
|
|
44,956 |
|
|
|
38,156 |
|
|
|
22,243 |
|
|
|
13,880 |
|
Income taxes |
|
|
592 |
|
|
|
1,398 |
|
|
|
5,595 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
22,203 |
|
|
$ |
43,558 |
|
|
$ |
32,561 |
|
|
$ |
22,243 |
|
|
$ |
13,880 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit |
|
$ |
1.17 |
|
|
$ |
2.72 |
|
|
$ |
1.67 |
|
|
$ |
1.69 |
|
|
$ |
1.58 |
|
Weighted average limited partner units |
|
|
14,680,807 |
|
|
|
14,529,826 |
|
|
|
14,018,799 |
|
|
|
12,602,000 |
|
|
|
8,583,634 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at Period End): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
685,939 |
|
|
$ |
706,322 |
|
|
$ |
656,604 |
|
|
$ |
457,461 |
|
|
$ |
389,044 |
|
Due to affiliates |
|
|
13,810 |
|
|
|
23,085 |
|
|
|
17,119 |
|
|
|
10,474 |
|
|
|
3,492 |
|
Long-term debt |
|
|
304,372 |
|
|
|
295,000 |
|
|
|
225,000 |
|
|
|
174,021 |
|
|
|
192,200 |
|
Partners capital (owners equity) |
|
|
264,951 |
|
|
|
246,379 |
|
|
|
246,765 |
|
|
|
198,525 |
|
|
|
95,565 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flow provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
|
47,592 |
|
|
|
86,340 |
|
|
|
61,209 |
|
|
|
39,317 |
|
|
|
32,334 |
|
Investing activities |
|
|
(14,675 |
) |
|
|
(106,621 |
) |
|
|
(130,295 |
) |
|
|
(95,098 |
) |
|
|
(138,742 |
) |
Financing activities |
|
|
(34,944 |
) |
|
|
24,151 |
|
|
|
69,896 |
|
|
|
52,991 |
|
|
|
109,689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures |
|
|
7,601 |
|
|
|
17,998 |
|
|
|
11,955 |
|
|
|
12,391 |
|
|
|
5,100 |
|
Expansion capital expenditures |
|
|
28,572 |
|
|
|
89,435 |
|
|
|
109,474 |
|
|
|
78,267 |
|
|
|
74,110 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
36,173 |
|
|
$ |
107,433 |
|
|
$ |
121,429 |
|
|
$ |
90,658 |
|
|
$ |
79,210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per common unit (in dollars) |
|
$ |
3.00 |
|
|
$ |
2.91 |
|
|
$ |
2.60 |
|
|
$ |
2.44 |
|
|
$ |
2.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Financial information for 2007, 2008 and the period from January 1, 2009 through
November 24, 2009 have been revised to include results attributable to the Cross assets. The
acquisition of the Cross assets was considered a transfer of net assets between entities under
common control. We are required to revise our historical financial statements to include the
activities of the Cross assets as of the date of common control. Martin Resource Management
acquired Cross in November 2006; however, the activity for the period Cross was owned by Martin
Resource Management during 2006 was not considered significant to our consolidated financial
statements and has been excluded from the 2006 consolidated financial statements. The
acquisition of the Cross assets and increase in partners capital for the common and subordinated
units issued in November 2009 are recorded at amounts based on the historical carrying value of the
Cross assets at that date. |
- 49 -
The following tables present our historical results of operations, the effect of
including the results of the Cross assets which are included in our terminalling and storage
segment and the revised total amounts included in our consolidated financial statements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009 |
|
|
|
Historical |
|
|
|
|
|
|
|
|
|
Martin Midstream |
|
|
|
|
|
|
|
|
|
Partners LP |
|
|
Cross Assets Results |
|
|
Revised Total |
|
|
|
(Dollars in thousands, except per unit amounts) |
|
Revenues |
|
$ |
633,776 |
|
|
$ |
28,609 |
|
|
$ |
662,385 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (excluding depreciation and amortization) |
|
|
457,259 |
|
|
|
|
|
|
|
457,259 |
|
Operating expenses |
|
|
98,677 |
|
|
|
18,761 |
|
|
|
117,438 |
|
Selling, general and administrative |
|
|
18,090 |
|
|
|
1,685 |
|
|
|
19,775 |
|
Depreciation and amortization |
|
|
35,143 |
|
|
|
4,363 |
|
|
|
39,506 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
609,169 |
|
|
|
24,809 |
|
|
|
633,978 |
|
|
|
|
|
|
|
|
|
|
|
Other operating income |
|
|
6,160 |
|
|
|
(147 |
) |
|
|
6,013 |
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
30,767 |
|
|
|
3,653 |
|
|
|
34,420 |
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated entities |
|
|
7,044 |
|
|
|
|
|
|
|
7,044 |
|
Interest expense |
|
|
(18,124 |
) |
|
|
(871 |
) |
|
|
(18,995 |
) |
Other, net |
|
|
303 |
|
|
|
23 |
|
|
|
326 |
|
|
|
|
|
|
|
|
|
|
|
Net income before taxes |
|
|
19,990 |
|
|
|
2,805 |
|
|
|
22,795 |
|
Income tax benefit (expense) |
|
|
549 |
|
|
|
( 1,141 |
) |
|
|
( 592 |
) |
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
20,539 |
|
|
$ |
1,664 |
|
|
$ |
22,203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008 |
|
|
|
Historical |
|
|
|
|
|
|
|
|
|
Martin Midstream |
|
|
|
|
|
|
|
|
|
Partners LP |
|
|
Cross Assets Results |
|
|
Revised Total |
|
|
|
(Dollars in thousands, except per unit amounts) |
|
Revenues |
|
$ |
1,213,958 |
|
|
$ |
32,486 |
|
|
$ |
1,246,444 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (excluding depreciation and amortization) |
|
|
1,013,526 |
|
|
|
|
|
|
|
1,013,526 |
|
Operating expenses |
|
|
102,894 |
|
|
|
23,914 |
|
|
|
126,808 |
|
Selling, general and administrative |
|
|
16,939 |
|
|
|
2,123 |
|
|
|
19,062 |
|
Depreciation and amortization |
|
|
31,218 |
|
|
|
3,675 |
|
|
|
34,893 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
1,164,576 |
|
|
|
29,712 |
|
|
|
1,194289 |
|
|
|
|
|
|
|
|
|
|
|
Other operating income |
|
|
209 |
|
|
|
|
|
|
|
209 |
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
49,591 |
|
|
|
2,773 |
|
|
|
52,364 |
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated entities |
|
|
13,224 |
|
|
|
|
|
|
|
13,224 |
|
Interest expense |
|
|
(19,777 |
) |
|
|
(1,656 |
) |
|
|
(21,433 |
) |
Other, net |
|
|
483 |
|
|
|
318 |
|
|
|
801 |
|
|
|
|
|
|
|
|
|
|
|
Net income before taxes |
|
|
43,521 |
|
|
|
1,435 |
|
|
|
44,956 |
|
Income tax benefit (expense) |
|
|
( 711 |
) |
|
|
( 687 |
) |
|
|
(1,398 |
) |
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
42,810 |
|
|
$ |
748 |
|
|
$ |
43,558 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007 |
|
|
|
Historical |
|
|
|
|
|
|
|
|
|
Martin Midstream |
|
|
|
|
|
|
|
|
|
Partners LP |
|
|
Cross Assets Results |
|
|
Revised Total |
|
|
|
(Dollars in thousands, except per unit amounts) |
|
Revenues |
|
$ |
765,822 |
|
|
$ |
38,505 |
|
|
$ |
804,327 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (excluding depreciation and amortization) |
|
|
618,689 |
|
|
|
|
|
|
|
618,689 |
|
Operating expenses |
|
|
83,533 |
|
|
|
20,632 |
|
|
|
104,165 |
|
Selling, general and administrative |
|
|
11,985 |
|
|
|
1,933 |
|
|
|
13,918 |
|
Depreciation and amortization |
|
|
23,442 |
|
|
|
2,881 |
|
|
|
26,323 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
737,649 |
|
|
|
25,446 |
|
|
|
763,095 |
|
|
|
|
|
|
|
|
|
|
|
Other operating income |
|
|
703 |
|
|
|
|
|
|
|
703 |
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
28,876 |
|
|
|
13,059 |
|
|
|
41,935 |
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated entities |
|
|
10,941 |
|
|
|
|
|
|
|
10,941 |
|
Interest expense |
|
|
(14,533 |
) |
|
|
(592 |
) |
|
|
(15,125 |
) |
Other, net |
|
|
299 |
|
|
|
106 |
|
|
|
405 |
|
|
|
|
|
|
|
|
|
|
|
Net income before taxes |
|
|
25,583 |
|
|
|
12,573 |
|
|
|
38,156 |
|
Income tax benefit (expense) |
|
|
( 644 |
) |
|
|
( 4,951 |
) |
|
|
(5,595 |
) |
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
24,939 |
|
|
$ |
7,622 |
|
|
$ |
32,561 |
|
|
|
|
|
|
|
|
|
|
|
- 50 -
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 four primary business lines include:
|
|
|
Terminalling and storage services for petroleum and by-products; |
|
|
|
|
Natural gas services; |
|
|
|
|
Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and
distribution; and |
|
|
|
|
Marine transportation services for petroleum products and by-products. |
The petroleum products and by-products we gather, process, 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
generate the majority of our cash flow from fee-based contracts with these customers. Our location
in the Gulf Coast region of the United States provides us strategic access to 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, 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.
As of March 4, 2010, Martin Resource Management owns an approximate 40.0% 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.
- 51 -
The historical operation of our business segments by Martin Resource Management provides us
with several decades of experience and a demonstrated track record of customer service across our
operations. Our current lines of business have been developed and systematically integrated over
this period of more than 50 years, including natural gas services (1950s); sulfur (1960s); marine
transportation (late 1980s) and terminalling and storage (early 1990s). This development of a
diversified and integrated set of assets and operations has produced a complementary portfolio of
midstream services that facilitates the maintenance of long-term customer relationships and
encourages the development of new customer relationships.
2009 Developments and Subsequent Events
Global financial markets and economic conditions have been, and continue to be, disrupted and
volatile. Numerous events have restricted current liquidity in the capital markets throughout the
United States and around the world. The ability to raise money in the debt and equity markets has
diminished and, if available, the cost of funds has increased. One of the features driving
investments in master limited partnerships, including us, over the past few years has been the
distribution growth offered by master limited partnerships due to liquidity in the financial
markets for capital investments to grow distributable cash flow through development projects and
acquisitions. Growth opportunities have been and are expected to continue to be constrained by the
lack of liquidity in the financial markets.
Conditions in our industry continued to be challenging in 2009. For example:
|
|
|
Market prices of oil, natural gas, NGLs, and sulfur remained below the market prices
realized throughout most of 2008. |
|
|
|
|
The decline in drilling activity by gas producers in our areas of operations that
began during the fourth quarter of 2008 as a result of the global economic crisis has
continued. Several gas producers in our areas of operation substantially reduced
drilling activity during 2009 as compared to their drilling levels during 2008. |
|
|
|
|
The decline in the demand for marine transportation services based on decreased
refinery production resulting in an oversupply of equipment. |
|
|
|
|
A modest shift in marine transportation contracts from term contracts to spot
contracts. |
|
|
Despite the weaker commodity price environment and reduced drilling activity, we are
positioning ourselves to benefit from a recovering economy. In particular: |
|
|
|
We adjusted our business strategy for 2009 to focus on maximizing our liquidity,
maintaining a stable asset base and improving the profitability of our assets by
increasing their utilization while controlling costs. We also reduced our capital
expenditures. |
|
|
|
|
We continue to evaluate opportunities to enter into commodity hedging transactions
to further reduce our commodity price risk. |
|
|
|
|
We completed the disposition of certain non-strategic assets including the April
2009 sale of the Mont Belvieu Railcar Unloading Facility for $19.6 million, and we may
consider marketing certain other non-strategic assets in the future. |
|
|
|
|
We extended the maturity date of our existing credit facility and increased the
aggregate commitments of the lenders thereunder through an amendment in order to have
sufficient liquidity to fund our growth programs, while continuing the present
distribution rate to our unitholders. The current economic crisis and the existing
litigation at Martin Resource Management created a challenging operating environment
for us to maintain our liquidity and operating cash flows at levels consistent with the
recent past while maintaining the present distribution rate to our unitholders. |
|
|
|
|
We acquired certain assets of a subsidiary of Martin Resource Management in exchange
for the issuance of new common and subordinated units to maintain appropriate financial
ratios satisfactory to our lenders. See Recent Acquisitions Acquisition of Cross Assets. |
- 52 -
Recent Acquisitions
Acquisition of Cross Assets. On November 25, 2009, we closed a transaction with Martin
Resource Management and Cross Refining & Marketing, Inc. (Cross), a wholly owned subsidiary of
Martin Resource Management, in which we acquired certain specialty lubricants processing assets
(Assets) from Cross for total consideration of $44.9 million (the Contribution). As
consideration for the Contribution, we issued 804,721 of our common units and 889,444 subordinated
units to Martin Resource Management at a price of $27.96 and $25.16 per limited partner unit,
respectively. The common units will be entitled to receive distributions beginning in February
2010, while the subordinated units will have no distribution rights until the second anniversary of
closing of the Contribution. At the end of such second anniversary, the subordinated units will
automatically convert to common units, having the same distribution rights as existing common
units. In connection with the Contribution, our general partner made a capital contribution of $0.9
million to us in order to maintain its 2% general partner interest in us.
In connection with the closing of the Contribution, we and Martin Resource Management entered
into a long-term, fee for services-based Tolling Agreement whereby Martin Resource Management
agreed to pay us for the processing of its crude oil into finished products, including naphthenic
lubricants, distillates, asphalt and other intermediate cuts. Under the Tolling Agreement, Martin
Resource Management has generally agreed to refine a minimum of 6,500 barrels per day of crude oil
at the refinery at a price of $4.00 per barrel. Any additional barrels will be refined at a price
of $4.28 per barrel. In addition, Martin Resource Management has agreed to pay a monthly
reservation fee of $1.3 million and a periodic fuel surcharge fee based on certain parameters
specified in the Tolling Agreement. All of these fees (other than the fuel surcharge) are subject
to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for
a specified annual period. In addition, every three years, the parties can negotiate an upward or
downward adjustment in the fees subject to their mutual agreement. The Tolling Agreement has a 12
year term, subject to certain termination rights specified therein. Martin Resource Management will
continue to market and distribute all finished products under the Cross brand name. In addition,
Martin Resource Management will continue to own and operate the Cross packaging business.
The acquisition of the Cross assets was considered a transfer of net assets between entities
under common control. Accordingly, we are required to revise our financial statements to include
activities of the Cross assets as of the date of common control. Our historical financial
statements have been recast to reflect the results attributable to the Cross assets as if we owned
the Cross assets for all periods presented.
Acquisition of the East Harrison Pipeline System. In December 2009, we acquired, through
Prism Gas, from Woodward Partners, Ltd. 6.45 miles of gathering pipeline referred to as the East
Harrison Pipeline System for approximately $0.3 million. The system currently transports
approximately 500 Mcfd of natural gas under various transport contracts which provide for a minimum
monthly fee.
Other Developments
Fourth Amendment to Credit Agreement. On December 21, 2009, we entered into a Fourth
Amendment (the Fourth Amendment) to the Second Amended and Restated Credit Agreement (the Credit
Agreement), among Martin Operating Partnership L.P., a wholly-owned subsidiary of ours (the
Operating Partnership), as borrower, the Partnership and certain of our subsidiaries, as
guarantors, the financial institutions parties thereto, as lenders, Royal Bank of Canada, as
administrative agent and collateral agent, and the various other agents and parties thereto. The
Fourth Amendment modified our existing Credit Agreement to, among other things, (1) increase the
total commitments of the lenders thereunder from $325.0 million to approximately $335.7 million,
(2) provide that the term loans thereunder will automatically convert to revolving loans on
November 10, 2010, such that after giving effect to such conversion the aggregate revolving loan
commitments will be approximately $335.7 million, (3) extend the maturity date of amounts
outstanding under the Credit Agreement from November 10, 2010 to November 9, 2012, (4) increase the
applicable interest rate margin and fees payable to the lenders under the Credit Agreement, (5)
amend the financial covenants and certain other covenants under the Credit Agreement, (6) include
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 $375.0 million for
all term loan and revolving loan commitments under the Credit Agreement, (7) eliminate the
requirement that we make annual prepayments of the term loans outstanding under the Credit
Agreement with excess cash flow, (8) eliminate the swing line facility under the Credit Agreement
and (9) limit asset dispositions to $25 million per fiscal year.
Conversion of Subordinated Units Issued at Formation of Partnership. On November 14, 2009,
all of our remaining 850,674 outstanding subordinated units issued at the formation of the
partnership and owned by Martin Resource Management through a subsidiary converted into common
units on a one-for-one basis following our quarterly
cash distribution on such date. All of the 4,253,362 original subordinated units issued to
Martin Resource Management have been converted into common units on a one-for-one basis since the
formation of the Partnership.
- 53 -
Investment by Martin Resource Management. On November 25, 2009, we closed a private equity
sale with Martin Resource Management, under which Martin Resource Management invested $20.0 million
in cash in the Partnership in exchange for 714,285 of our common units (the Investment). In
connection with the Investment, our general partner made a capital contribution to us of $0.4
million in order to maintain its 2% general partner interest in us. Proceeds from the Investment
were used to repay borrowings under our credit facility.
Subsequent Events
Fifth Amendment to Credit Agreement. On January 14, 2010, we entered into a Fifth Amendment
(the Fifth Amendment) to the Credit Agreement. The Fifth Amendment modified the Credit Agreement
to, among other things, (1) permit us to invest up to $25 million in our joint ventures and (2)
limit our ability to make capital expenditures.
Increase Joinder. On February 25, 2010, we entered into a Commitment Increase and Joinder
Agreement (the Increase Joinder) with respect to the Credit Agreement. The Increase Joinder
increased the maximum amount of borrowings and letters of credit under our credit facility from
approximately $335.7 million to $350.0 million.
Acquisition by Waskom of the Harrison Pipeline System. On January 15, 2010, the Partnership,
through Prism Gas, as 50% owner and the operator of Waskom Gas Processing Company (WGPC), through
WGPCs wholly owned subsidiaries Waskom Midstream LLC and Olin Gathering LLC, acquired from
Crosstex North Texas Gathering, L.P., a 100% interest in approximately 62 miles of gathering
pipeline, two 35 MMcfd dew point control plants and equipment referred to as the Harrison Pipeline
System. The Partnerships share of the acquisition cost is approximately $20.0 million.
Quarterly Distribution. On January 21, 2010, we declared a quarterly cash distribution of
$0.75 per common unit for the fourth quarter of 2009, or $3.00 per common unit on an annualized
basis, to be paid on February 12, 2010 to unitholders of record as of February 5, 2010, reflecting
no change over the quarterly distribution paid in respect to the third quarter of 2009.
Public Offering. In February 2010, we completed a public offering of 1,650,000 common units,
resulting in net proceeds of $50.6 million, after payment of underwriters discounts, commissions
and offering expenses. Our general partner contributed $1.1 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.
Critical Accounting Policies
Our discussion and analysis of our financial condition and results of operations are based on
the historical consolidated and condensed 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 and condensed 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 as it relates to our
annual goodwill evaluation.
Derivatives
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. Our hedging policy allows us to use hedge accounting for financial
transactions that are designated as hedges. Derivative instruments not designated as hedges or
hedges that become ineffective are being marked to market with all market value adjustments being
recorded in the consolidated statements of operations. As of December 31, 2009, we have 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 partners capital.
- 54 -
Product Exchanges
We enter into product exchange agreements with third parties whereby we agree to exchange
natural gas liquids (NGLs) and sulfur with third parties. We record the balance of exchange
products due to other companies under these agreements at quoted market product prices and the
balance of exchange products due from other companies at the lower of cost or market. Cost is
determined using the first-in, first-out method.
Revenue Recognition
Revenue for our four 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. For our tolling agreement, revenue is
recognized based on the contracted monthly reservation fee and throughput volumes moved through the
facility. 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 our NGL customers, which occurs when the customer physically receives the
product. When product is sold in storage, or by pipeline, we recognize NGL distribution revenue
when the customer receives the product from either the storage facility or pipeline.
Sulfur services Revenue is recognized when the customer takes title to the product at our
plant or the customer facility.
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.
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. This goodwill is not subject to amortization and is accounted for as a component of the
investment. Equity method investments are subject to impairment evaluation. No portion of the net
income from these entities is included in our operating income.
We own an unconsolidated 50% of the ownership interests in Waskom Gas Processing Company
(Waskom), Matagorda Offshore Gathering System (Matagorda), Panther Interstate Pipeline Energy
LLC (PIPE) and a 20% ownership interest in a partnership which owns the lease rights to Bosque
County Pipeline (BCP). Each of these interests is accounted for under 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.
All four of our reporting units, terminalling and storage, marine transportation, natural
gas services and sulfur services, contain goodwill.
We have performed the annual impairment tests as of September 30, 2009, September 30, 2008,
and September 30, 2007, and we have determined fair value in each reporting unit based on the
weighted average of three
- 55 -
valuation techniques: (i) the discounted cash flow method, (ii) the
guideline public company method, and (iii) the guideline transaction method. At September 30,
2009, 2008 and 2007 the estimated fair value of each of our four reporting units was in excess of
its carrying value resulting in no impairment.
As a result of the deterioration in the overall stock market subsequent to September 30, 2008
and the decline in our unit price, we reviewed specific factors, as outlined in under certain
provisions of ASC 350-20, to determine if we had a trigging event that required us to test our
goodwill for impairment as of December 31, 2008. These factors included whether there have been
any significant fundamental changes since our annual impairment test to (i) our business as a whole
or to the reporting units, including regulatory changes, (ii) our level of operating cash flows,
(iii) our expectation of future levels of operating cash flows, (iv) our executive management team
and (v) the carrying value of our other long-lived assets. While these factors did not indicate a
triggering event occurred, our unit price fell to a point by December 31, 2008, that resulted in
our total market capitalization being less than our partners equity. We determined this to be a
triggering event requiring us to perform an impairment test as of December 31, 2008. As a result
of our goodwill impairment test for each of the four reporting units as of December 31, 2008, no
impairment was determined to exist.
No such triggering events occurred that would cause us to perform an impairment test at
December 31, 2009.
Significant changes in these estimates and assumptions could materially affect the
determination of fair value for each reporting unit which could give rise to future impairment.
Changes to these estimates and assumptions can include, but may not be limited to, varying
commodity prices, volume changes and operating costs due to market conditions and/or alternative
providers of services.
Environmental Liabilities and Litigation
We have not historically 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.
Because the outcomes of both contingent liabilities and litigation are difficult to predict,
when accounting for these situations, significant management judgment is required. Amounts paid for
contingent liabilities and litigation have not had a materially adverse effect on our operations or
financial condition and we do not anticipate they will in the future.
Allowance for Doubtful Accounts
In evaluating the collectability 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 specific and general reserves for bad debts to reduce the related receivables to the
amount we ultimately expect to collect from customers.
Our management closely monitors potentially uncollectible accounts. Estimates of
uncollectible amounts are revised each period, and changes are recorded in the period they become
known. If there is a deterioration of a major customers creditworthiness or actual defaults are
higher than the historical experience, managements estimates of the recoverability of amounts due
us could potentially be adversely affected. These charges have not had a materially
adverse effect on our operations or financial condition.
Asset Retirement Obligation
We recognize and measure our asset and conditional asset retirement obligations and the
associated asset retirement cost upon acquisition of the related asset and based upon the estimate
of the cost to settle the obligation at its anticipated future date. The obligation is accreted to
its estimated future value and the asset retirement cost is depreciated over the estimated life of
the asset.
Estimates of future asset retirement obligations include significant management judgment and
are based on projected future retirement costs. Such costs could differ significantly when they are
incurred. Revisions to estimated asset retirement obligations can result from changes in retirement
cost estimates due to surface repair, and labor and
- 56 -
material costs, revisions to estimated inflation rates and changes in the estimated
timing of abandonment. For example, the Company does not have access to natural gas reserves
information related to our gathering systems to estimate when abandonment will occur.
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. In addition to the direct expenses, under
the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general
and administrative and corporate overhead expenses. The amount of this reimbursement was capped at
$2.0 million through November 1, 2007, when the cap expired. For the years ended December 31,
2009, 2008 and 2007, the Conflicts Committee of our general partner approved reimbursement amounts
of $3.5, $2.9 and $1.5 million, respectively, reflecting our allocable share of such expenses. The
Conflicts Committee will review and approve future adjustments in the reimbursement amount for
indirect expenses, if any, annually.
We are required to reimburse Martin Resource Management for all direct 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 sell sulfuric acid and 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. 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, and Director Independence Agreements.
Results of Operations
The results of operations for the twelve months ended December 31, 2009, 2008 and 2007 have
been derived from our consolidated financial statements.
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 revenues and operating income by segment for the twelve months ended December 31,
2009, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
|
|
|
|
Operating |
|
|
Operating |
|
|
|
|
|
|
|
Revenues |
|
|
Revenues |
|
|
Operating |
|
|
Income |
|
|
Income(loss) |
|
|
|
Operating |
|
|
Intersegment |
|
|
after |
|
|
Income |
|
|
Intersegment |
|
|
after |
|
|
|
Revenues |
|
|
Eliminations |
|
|
Eliminations |
|
|
(loss) |
|
|
Eliminations |
|
|
Eliminations |
|
|
|
(In thousands) |
|
Year ended December 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
109,513 |
|
|
$ |
(4,219 |
) |
|
$ |
105,294 |
|
|
$ |
20,231 |
|
|
$ |
(2,332 |
) |
|
$ |
17,899 |
|
Natural gas services |
|
|
408,989 |
|
|
|
(7 |
) |
|
|
408,982 |
|
|
|
4,880 |
|
|
|
786 |
|
|
|
5,666 |
|
Sulfur services |
|
|
79,631 |
|
|
|
(2 |
) |
|
|
79,629 |
|
|
|
9,575 |
|
|
|
4,201 |
|
|
|
13,776 |
|
Marine transportation |
|
|
72,103 |
|
|
|
(3,623 |
) |
|
|
68,480 |
|
|
|
5,811 |
|
|
|
(2,655 |
) |
|
|
3,156 |
|
Indirect selling, general and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,077 |
) |
|
|
|
|
|
|
(6,077 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
670,236 |
|
|
$ |
(7,851 |
) |
|
$ |
662,385 |
|
|
$ |
34,420 |
|
|
$ |
|
|
|
$ |
34,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
122,960 |
|
|
$ |
(4,189 |
) |
|
$ |
118,771 |
|
|
$ |
15,034 |
|
|
$ |
(3,635 |
) |
|
$ |
11,399 |
|
Natural gas services |
|
|
679,375 |
|
|
|
|
|
|
|
679,375 |
|
|
|
2,780 |
|
|
|
945 |
|
|
|
3,725 |
|
Sulfur services |
|
|
372,987 |
|
|
|
(1,038 |
) |
|
|
371,949 |
|
|
|
31,956 |
|
|
|
5,224 |
|
|
|
37,180 |
|
Marine transportation |
|
|
80,059 |
|
|
|
(3,710 |
) |
|
|
76,349 |
|
|
|
8,104 |
|
|
|
(2,534 |
) |
|
|
5,570 |
|
Indirect selling, general and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,510 |
) |
|
|
|
|
|
|
(5,510 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,255,381 |
|
|
$ |
(8,937 |
) |
|
$ |
1,246,444 |
|
|
$ |
52,364 |
|
|
$ |
|
|
|
$ |
52,364 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 57 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
|
|
|
|
Operating |
|
|
Operating |
|
|
|
|
|
|
|
Revenues |
|
|
Revenues |
|
|
Operating |
|
|
Income |
|
|
Income(loss) |
|
|
|
Operating |
|
|
Intersegment |
|
|
after |
|
|
Income |
|
|
Intersegment |
|
|
after |
|
|
|
Revenues |
|
|
Eliminations |
|
|
Eliminations |
|
|
(loss) |
|
|
Eliminations |
|
|
Eliminations |
|
|
|
(In thousands) |
|
Year ended December 31, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
98,295 |
|
|
$ |
(865 |
) |
|
$ |
97,430 |
|
|
$ |
23,804 |
|
|
$ |
(472 |
) |
|
$ |
23,332 |
|
Natural gas services |
|
|
515,992 |
|
|
|
|
|
|
|
515,992 |
|
|
|
4,159 |
|
|
|
333 |
|
|
|
4,492 |
|
Sulfur services |
|
|
131,602 |
|
|
|
(276 |
) |
|
|
131,326 |
|
|
|
9,222 |
|
|
|
3,818 |
|
|
|
13,040 |
|
Marine transportation |
|
|
63,533 |
|
|
|
(3,954 |
) |
|
|
59,579 |
|
|
|
7,949 |
|
|
|
(3,679 |
) |
|
|
4,270 |
|
Indirect selling, general and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,199 |
) |
|
|
|
|
|
|
(3,199 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
809,422 |
|
|
$ |
(5,095 |
) |
|
$ |
804,327 |
|
|
$ |
41,935 |
|
|
$ |
|
|
|
$ |
41,935 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our results of operations are discussed on a comparative basis below. There are certain
items of income and expense which we do not allocate on a segment basis. These items, including
equity in earnings (loss) of unconsolidated entities, interest expense, and indirect selling,
general and administrative expenses, are discussed after the comparative discussion of our results
within each segment.
The acquisition of the Cross assets was considered a transfer of net assets between entities
under common control. Accordingly, we are required to revise our financial statements to include
activities of the Cross assets as of the date of common control. Our historical financial
statements have been recast to reflect the results attributable to the Cross assets as if we owned
the Cross assets for all periods presented.
Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008
Our total revenues before eliminations were $670.2 million for the year ended December 31,
2009 compared to $1,255.4 million for the year ended December 31, 2008, a decrease of $585.2
million, or 47%. Our operating income before eliminations was $34.4 million for the year ended
December 31, 2009 compared to $52.4 million for the year ended December 31, 2008, a decrease of
$18.0 million, or 34%.
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, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
Services |
|
$ |
73,885 |
|
|
$ |
72,604 |
|
Products |
|
|
35,628 |
|
|
|
50,356 |
|
|
|
|
|
|
|
|
Total Revenues |
|
|
109,513 |
|
|
|
122,960 |
|
Cost of products sold |
|
|
31,331 |
|
|
|
42,721 |
|
Operating expenses |
|
|
45,783 |
|
|
|
50,001 |
|
Selling, general and administrative expenses |
|
|
1,955 |
|
|
|
2,243 |
|
Depreciation and amortization |
|
|
15,717 |
|
|
|
12,947 |
|
|
|
|
|
|
|
|
|
|
|
14,727 |
|
|
|
15,048 |
|
|
|
|
|
|
|
|
Other operating income (loss) |
|
|
5,504 |
|
|
|
(14 |
) |
|
|
|
|
|
|
|
Operating income |
|
$ |
20,231 |
|
|
$ |
15,034 |
|
|
|
|
|
|
|
|
Revenues. Our terminalling and storage revenues decreased $13.4 million, or 11%, for the year
ended December 31, 2009 compared to the year ended December 31, 2008. Service revenue accounted
for a $1.3 million increase offset by a $14.7 million decrease in lubricant product sales. The
service revenue increase was primarily a result of new agreements entered into in 2008 and 2009,
including a new lubricant terminalling fee of $5.3 million. This service revenue increase
was offset by decreased activity at our terminals of $2.4 million, decreased revenues from the
Cross assets of $1.2 million, and lost revenues due to the sale of our Mont Belvieu terminal of
$0.4 million. Of the $14.7 million lubricant product sales decrease, $12.6 million was due to the
sale of our traditional lubricants business, including inventory, to Martin Resource
- 58 -
Management in
April 2009 in return for a service fee for lubricant volumes moved through our terminals. The
remaining $2.1 million decrease is due to a 13% decrease in average selling price offset by a 7%
increase in sales volumes at our Mega Lubricant facility.
Cost of products sold. Our cost of products sold decreased $11.4 million, or 27% for the year
ended December 31, 2009 compared to the year ended December 31, 2008. This decrease was primarily
due to the sale of our traditional lubricants business, including inventory to Martin Resource
Management in April 2009 in return for a service fee for lubricant volumes moved through our
terminals.
Operating
expenses. Operating expenses decreased $4.2 million, or 8%, for the year ended
December 31, 2009 compared to the year ended December 31, 2008. This decrease was a result of a
$3.2 million decrease from the Cross assets, a $1.1 million decreases in hurricane expenses that
were recorded in 2008, and a decrease in utility cost of $0.5 million. These decreases were offset
by an increase in salaries and burden of $0.3 million and product hauling costs of $0.3 million.
Selling, general and administrative expenses. Selling, general & administrative expenses
decreased $0.3 million, or 13% for the year ended December 31, 2009 compared to the year ended
December 31, 2008. This decrease was primarily due to the Cross assets.
Depreciation and amortization. Depreciation and amortization increased $2.8 million, or 21%,
for the year ended December 31, 2009 compared to the year ended December 31, 2008. This increase
was primarily a result of our recent acquisitions and capital expenditures.
Other operating income (loss). Other operating income for the year ended December 31, 2009
consisted primarily of a gain on the sale of our Mont Belvieu terminal on April 30, 2009.
In summary, terminalling and storage operating income increased $5.2 million, or 35%, for the
years ended December 31, 2009 and 2008.
Natural Gas Services Segment
The following table summarizes our results of operations in our natural gas services segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
NGLs |
|
$ |
384,124 |
|
|
$ |
615,966 |
|
Natural gas |
|
|
20,334 |
|
|
|
59,346 |
|
Non-cash mark to market and impairment adjustments of
commodity derivatives |
|
|
(2,490 |
) |
|
|
4,930 |
|
Gain (loss) on cash settlements of commodity derivatives |
|
|
3,273 |
|
|
|
(3,932 |
) |
Other operating fees |
|
|
3,748 |
|
|
|
3,065 |
|
|
|
|
|
|
|
|
Total revenues |
|
|
408,989 |
|
|
|
679,375 |
|
|
|
|
|
|
|
|
|
|
Cost of products sold: |
|
|
|
|
|
|
|
|
NGLs |
|
|
364,350 |
|
|
|
599,835 |
|
Natural gas |
|
|
19,261 |
|
|
|
58,771 |
|
|
|
|
|
|
|
|
Total cost of products sold |
|
|
383,611 |
|
|
|
658,606 |
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
8,627 |
|
|
|
8,633 |
|
Selling, general and administrative expenses |
|
|
7,332 |
|
|
|
5,292 |
|
Depreciation and amortization |
|
|
4,527 |
|
|
|
4,067 |
|
|
|
|
|
|
|
|
|
|
|
4,892 |
|
|
|
2,777 |
|
|
|
|
|
|
|
|
Other operating income |
|
|
(12 |
) |
|
|
3 |
|
|
|
|
|
|
|
|
Operating income |
|
$ |
4,880 |
|
|
$ |
2,780 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs Volumes (Bbls) |
|
|
9,880 |
|
|
|
8,794 |
|
|
|
|
|
|
|
|
Natural Gas Volumes (Mmbtu) |
|
|
6,155 |
|
|
|
7,267 |
|
|
|
|
|
|
|
|
Equity in Earnings of Unconsolidated Entities |
|
$ |
7,044 |
|
|
$ |
13,224 |
|
|
|
|
|
|
|
|
Waskom: |
|
|
|
|
|
|
|
|
Plant Inlet Volumes (MMcfd) |
|
|
243 |
|
|
|
257 |
|
|
|
|
|
|
|
|
Frac Volumes (Bbls/d) |
|
|
10,034 |
|
|
|
10,542 |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Information above does not include activities relating
to Waskom, PIPE, Matagorda and BCP investments |
- 59 -
Revenues. Our natural gas services revenues decreased $270.4 million, or 40% for the year
ended December 31, 2009 compared to the year ended December 31, 2008 primarily due to lower
commodity prices.
For the year ended December 31, 2009, NGL revenues decreased $231.8 million, or 38% and
natural gas revenues decreased $39.0 million, or 66%. During 2009, our NGL average sales price per
barrel decreased $31.17 or 45% and our natural gas average sales price per Mmbtu decreased $4.86,
or 60% compared to the same period in 2008. NGL sales volumes for the year increased 12% and
natural gas volumes decreased 15% compared to the same period of 2008. The increase in NGL volumes
is primarily due to increased industrial demand experienced during 2009 and the decrease in natural
gas volumes is primarily due to the Waskom plant shutdown in second quarter 2009 and operational
issues on various producers gathering lines in fourth quarter 2009.
Our natural gas services segment utilizes derivative instruments to manage the risk of
fluctuations in market prices for its anticipated sales of natural gas, condensate and NGLs. This
activity is referred to as price risk management. For the year ended December 31, 2009, 54% of our
total natural gas volumes and 35% of our total NGL volumes were hedged as compared to 58% and 33%,
respectively in 2008. The impact of price risk management and marketing activities increased total
natural gas and NGL revenues $0.8 million for 2009 compared to an increase of $1.0 million in the
same period of 2008.
Costs of product sold. Our cost of products decreased $275.0 million, or 42%, for the year
ended December 31, 2009 compared to the same period in 2008. Of the decrease, $235.5 million
relates to NGLs and $39.5 million relates to natural gas. The percentage decrease in NGL cost of
products sold is greater than our percentage decrease in NGL revenues as our NGL per barrel margins
increased $0.17, or 9%. The percentage decrease relating to natural gas cost of products sold is
greater than the percentage decrease in natural gas revenues which caused our Mmbtu margins to
increase by 121%. This is primarily a result of revisions to the terms of certain producer
contracts.
Operating expenses. Operating expenses remained consistent for the years ended December 31,
2009 and 2008.
Selling, general and administrative expenses. Selling, general and administrative expenses
increased $2.0 million, or 39%. for the year ended December 31, 2009 compared to the same period of
2008. This increase was primarily a result of increased salary expenses due to increased headcount
and compensation increases of $1.6 million and an increase in expense related to uncollectible
accounts receivable of $0.4 million.
Depreciation and amortization. Depreciation and amortization increased $0.5 million, or 11%,
for the year ended December 31, 2009 compared to the same period of 2008. This increase was
primarily a result of normal capital expenditure activity during the current year.
In summary, our natural gas services operating income increased $2.1 million, or 76%, for the
year ended December 31, 2009 compared to the year ended December 31, 2008.
Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities
was $7.0 million and $13.2 million for the year ended December 31, 2009 and 2008, respectively, a
decrease of 47%. This decrease is a result of several factors including significantly lower
commodity prices and the Waskom plant shutdown during the second quarter of 2009 which contributed
to our inlet volumes decreasing 5% and our fractionation volumes decreasing 5% for the year ended
December 31, 2009 compared to the same period of 2008.
- 60 -
Sulfur Services Segment
The following table summarizes our results of operations in our sulfur services segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
79,631 |
|
|
$ |
372,987 |
|
Cost of products sold |
|
|
43,748 |
|
|
|
314,001 |
|
Operating expenses |
|
|
17,113 |
|
|
|
17,963 |
|
Selling, general and administrative expenses |
|
|
3,449 |
|
|
|
3,382 |
|
Depreciation and amortization |
|
|
6,151 |
|
|
|
5,751 |
|
|
|
|
|
|
|
|
|
|
|
9,170 |
|
|
|
31,890 |
|
|
|
|
|
|
|
|
Other operating income |
|
|
405 |
|
|
|
66 |
|
|
|
|
|
|
|
|
Operating income |
|
$ |
9,575 |
|
|
$ |
31,956 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sulfur (long tons) |
|
|
1,107.4 |
|
|
|
1,094.3 |
|
Fertilizer (long tons) |
|
|
238.0 |
|
|
|
227.6 |
|
|
|
|
|
|
|
|
Sulfur Services Volumes (long tons) |
|
|
1,345.4 |
|
|
|
1,321.9 |
|
|
|
|
|
|
|
|
Revenues. Our sulfur services revenues decreased $293.4 million, or 79%, for the year ended
December 31, 2009 compared to the year ended December 31, 2008. This decrease was a result of
lower market prices in 2009 compared to 2008 while volumes remained relatively constant.
Cost of products sold. Our cost of products sold decreased $270.3 million, or 86%, for the
year ended December 31, 2009 compared to the year ended December 31, 2008. This decrease was
directly related to the decreased price of our raw materials in 2009 compared to 2008. Our overall
gross margin per ton decreased from $44.62 in 2008 to $26.66 in 2009. This is related to commodity
prices being extremely high in 2008 compared to a more normalized year like 2009.
Operating expenses. Our operating expenses decreased $0.9 million, or 5%, for the year ended
December 31, 2009 compared to the year ended December 31, 2008. This decrease was a result of
decreased costs relating to fuel prices for marine transportation of our sulfur products.
Selling, general, and administrative expenses. Our selling, general, and administrative
expenses increased less than $0.1 million, or 2%, for the year ended December 31, 2009 compared to
the year ended December 31, 2008.
Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 7%,
for the year ended December 31, 2009 compared to the year ended December 31, 2008. This is
attributable to a new sulfur priller at our Neches facility that came online in the first quarter
of 2009.
In summary, our sulfur services operating income decreased $22.4 million, or 70%, for the year
ended December 31, 2009 compared to the year ended December 31, 2008.
Marine Transportation Segment
The following table summarizes our results of operations in our marine transportation segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
72,103 |
|
|
$ |
80,059 |
|
Operating expenses |
|
|
52,335 |
|
|
|
57,346 |
|
Selling, general and administrative expenses |
|
|
962 |
|
|
|
2,635 |
|
Depreciation and amortization |
|
|
13,111 |
|
|
|
12,128 |
|
|
|
|
|
|
|
|
|
|
|
5,695 |
|
|
|
7,950 |
|
|
|
|
|
|
|
|
Other operating income |
|
|
116 |
|
|
|
154 |
|
|
|
|
|
|
|
|
Operating income |
|
$ |
5,811 |
|
|
$ |
8,104 |
|
|
|
|
|
|
|
|
Revenues. Our marine transportation revenues decreased $8.0 million, or 10%, for the year
ended December 31, 2009 compared to the year ended December 31, 2008. Our inland marine revenues
declined $6.9 million primarily due to decreases in ancillary charges of $4.8 million and a $2.1
million decrease due to reduced charter contract rates. Our offshore revenue decreased $1.1
million primarily from reduction in offshore fleet utilization.
Operating expenses. Operating expenses decreased $5.0 million, or 9%, for the year ended
December 31, 2009 compared to the year ended December 31, 2008. This was primarily a result of a
decrease in fuel costs of $5.3 million and
- 61 -
outside charter expenses of $2.1 million. These decreases were offset by increases in repair
and maintenance of $1.0 million, wage and burden cost of $0.8 million and other operating expenses,
including insurance premiums, of $0.6 million.
Selling, general and administrative expenses. Selling, general & administrative expenses
decreased $1.7 million, or 63% for the year ended December 31, 2009 compared to the year ended
December 31, 2008. This decrease was primarily a result of a reduction of bad debt expense in
2009.
Depreciation and amortization. Depreciation and amortization increased $1.0 million, or 8%,
for the year ended December 31, 2009 compared to the year ended December 31, 2008. This increase
was the result of capital expenditures made in the last 12 months.
Other operating income. Other operating income remained relatively flat for the year ended
December 31, 2009 compared to the year ended December 31, 2008. In 2009, there were fewer gains
recorded on the sale of property and equipment than in 2008.
In summary, our marine transportation operating income decreased $2.3 million, or 28%, for the
year ended December 31, 2009 compared to the year ended December 31, 2008.
Equity in Earnings of Unconsolidated Entities
For the years ended December 31, 2009 and 2008, equity in earnings of unconsolidated entities
relates to our unconsolidated interests in Waskom Gas Processing Company (Waskom), Matagorda,
PIPE and BCP. With respect to BCP, the lease contract terminated in June 2009, and, as such, the
investment was fully amortized as of June 20, 2009.
Equity in earnings of unconsolidated entities was $7.0 million for the year ended December 31,
2009, compared to $13.2 million for the year ended December 31, 2008, a decrease of $6.2 million.
This decrease is a result of several factors including significantly lower commodity prices and the
Waskom plant shutdown during the second quarter of 2009 which contributed to our inlet volumes
decreasing 5% and our fractionation volumes decreasing 5% for the year ended December 31, 2009
compared to the same period of 2008.
Interest Expense
Our interest expense for all operations was $19.0 million for 2009 compared to $21.4 million
for 2008, a decrease of $2.4 million, or 11%. This decrease was primarily due to a decrease in
average debt outstanding and a decrease in interest rates throughout 2009 compared to 2008. Also,
we had interest swap cash settlements of $7.9 million which increased interest expense in 2009.
Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses were $6.1 million for 2009 compared to
$5.5 million for 2008, an increase of $0.6 million or 11%.
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 of 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.
In addition to the direct expenses, under the omnibus agreement, we are required to reimburse
Martin Resource Management for indirect general and administrative and corporate overhead expenses.
The amount of this reimbursement was capped at $2.0 million through November 1, 2007, when the cap
expired. For the years ended December 31, 2009 and 2008, the Conflicts Committee of our general
partner approved reimbursement amounts of $3.5 and $2.9 million, respectively, reflecting our
allocable share of such expenses. The Conflicts Committee will review and approve future
adjustments in the reimbursement amount for indirect expenses, if any, annually.
- 62 -
Year Ended December 31, 2008 Compared to the Year Ended December 31, 2007
Our total revenues before eliminations were $1,255.4 million for the year ended December 31,
2008 compared to $809.4 million for the year ended December 31, 2007, an increase of $446.0
million, or 55%. Our operating income before eliminations was $52.4 million for the year ended
December 31, 2008 compared to $41.9 million for the year ended December 31, 2007, an increase of
$10.5 million, or 25%.
The acquisition of the Cross assets were considered transfers of net assets between entities
under common control. Accordingly, we are required to revise our financial statements to include
activities of the Cross assets as of the date of common control. Our historical financial
statements have been recast to reflect the results attributable to the Cross assets as if we owned
the Cross assets for all periods presented.
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, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
Services |
|
$ |
72,604 |
|
|
$ |
67,905 |
|
Products |
|
|
50,356 |
|
|
|
30,390 |
|
|
|
|
|
|
|
|
Total Revenues |
|
|
122,960 |
|
|
|
98,295 |
|
Cost of products sold |
|
|
42,721 |
|
|
|
26,298 |
|
Operating expenses |
|
|
50,001 |
|
|
|
36,871 |
|
Selling, general and administrative expenses |
|
|
2,243 |
|
|
|
2,071 |
|
Depreciation and amortization |
|
|
12,947 |
|
|
|
9,239 |
|
|
|
|
|
|
|
|
|
|
|
15,048 |
|
|
|
23,817 |
|
|
|
|
|
|
|
|
Other operating income (loss) |
|
|
(14 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
|
Operating income |
|
$ |
15,034 |
|
|
$ |
23,804 |
|
|
|
|
|
|
|
|
Revenues. Our terminalling and storage revenues increased $24.7 million, or 25%, for the year
ended December 31, 2008 compared to the year ended December 31, 2007. Service revenue accounted
for $4.7 million of this increase. The service revenue increase was primarily a result of recent
acquisitions and capital projects being placed into service during the end of 2007 and throughout
2008 which totaled $9.0 million and increased service revenue of $1.7 million. These increases were offset by a
$6.0 million decrease in Cross revenues. Product revenue, which is lubricant sales, increased
$20.0 million primarily due to our acquisition of the operations assets of Mega Lubricants Inc.
(Mega Lube) in June 2007.
Cost of products sold. Our cost of products sold increased $16.4 million, or 62% for the year
ended December 31, 2008 compared to the year ended December 31, 2007. This increase was primarily
a result of the Mega Lube acquisition.
Operating expenses. Operating expenses increased $13.1 million, or 36%, for the year ended
December 31, 2008 compared to the year ended December 31, 2007. The increase was result of our
recent acquisitions and capital projects placed into service during the end of 2007 and throughout
2008 which totaled $6.1 million. The increase was also a result
of inclusion of
operating expenses for the Cross assets of $3.3 million, increased
operating activities of $0.9 million and an increase in costs of those activities at our terminals,
including increased salaries and related burden of $1.3 million and
utility costs of $0.3 million.
Hurricane expenses also accounted for $1.1 million of this increase.
Selling, general and administrative expenses. Selling, general & administrative expenses
increased $0.2 million, or 8%, for the year ended December 31, 2008 compared to the year ended
December 31, 2007. This increase was primarily due to the Cross assets.
Depreciation and amortization. Depreciation and amortization increased $3.7 million, or 40%,
for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase
was primarily a result of our recent acquisitions and capital expenditures.
- 63 -
Other operating income (loss). Other operating income was approximately the same for the year
ended December 31, 2008 compared to the year ended December 31, 2007. This consisted solely of a
loss related to the sale of equipment for both periods.
In summary, terminalling and storage operating income decreased $8.8 million, or 37%, for the
years ended December 31, 2008 and 2007.
Natural Gas Services Segment
The following table summarizes our results of operations in our natural gas services segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
NGLs |
|
$ |
615,966 |
|
|
$ |
481,018 |
|
Natural gas |
|
|
59,346 |
|
|
|
35,983 |
|
Non-cash mark to market and impairment
adjustments of commodity derivatives |
|
|
4,930 |
|
|
|
(3,104 |
) |
Loss on cash settlements of commodity derivatives |
|
|
(3,932 |
) |
|
|
(611 |
) |
Other operating fees |
|
|
3,065 |
|
|
|
2,706 |
|
|
|
|
|
|
|
|
Total revenues |
|
|
679,375 |
|
|
|
515,992 |
|
|
|
|
|
|
|
|
|
|
Cost of products sold: |
|
|
|
|
|
|
|
|
NGLs |
|
|
599,835 |
|
|
|
461,489 |
|
Natural gas |
|
|
58,771 |
|
|
|
34,485 |
|
|
|
|
|
|
|
|
Total cost of products sold |
|
|
658,606 |
|
|
|
495,974 |
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
8,633 |
|
|
|
7,082 |
|
Selling, general and administrative expenses |
|
|
5,292 |
|
|
|
5,524 |
|
Depreciation and amortization |
|
|
4,067 |
|
|
|
3,252 |
|
|
|
|
|
|
|
|
|
|
|
2,777 |
|
|
|
4,160 |
|
|
|
|
|
|
|
|
Other operating income |
|
|
3 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
Operating income |
|
$ |
2,780 |
|
|
$ |
4,159 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs Volumes (Bbls) |
|
|
8,794 |
|
|
|
8,266 |
|
|
|
|
|
|
|
|
Natural Gas Volumes (Mmbtu) |
|
|
7,267 |
|
|
|
5,550 |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Information above does not include activities
relating to Waskom, PIPE, Matagorda and BCP
investments |
|
|
|
|
|
|
|
|
|
Equity in Earnings of Unconsolidated Entities |
|
$ |
13,224 |
|
|
$ |
10,941 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Waskom: |
|
|
|
|
|
|
|
|
Plant Inlet Volumes (MMcfd) |
|
|
257 |
|
|
|
229 |
|
|
|
|
|
|
|
|
Frac Volumes (Bbls/d) |
|
|
10,542 |
|
|
|
8,725 |
|
|
|
|
|
|
|
|
Revenues. Our natural gas services revenues increased $163.4 million, or 32% for the year
ended December 31, 2008 compared to the year ended December 31, 2007 due to higher commodity
prices, in addition to increased natural gas and NGL volumes.
For the year ended December 31, 2008, NGL revenues increased $134.9 million, or 28% and
natural gas revenues increased $23.4 million, or 65%. During 2008, our NGL average sales price per
barrel increased $11.85 or 20% and our natural gas average sales price per Mmbtu increased $1.68,
or 26% compared to the same period in 2007. NGL sales volumes for the year increased 6% and
natural gas volumes increased 31% compared to the same period of 2007. The increase in NGL volumes
is primarily due to increased industrial demand experienced during 2008 and the increase in natural
gas volumes is primarily due to receiving a full years benefit of the Woodlawn acquisition.
Our natural gas services segment utilizes derivative instruments to manage the risk of
fluctuations in market prices for its anticipated sales of natural gas, condensate and NGLs. This
activity is referred to as price risk
- 64 -
management. For the year ended December 31, 2008, 58% of our total natural gas volumes and 33% of
our total NGL volumes were hedged as compared to 46% and 53%, respectively in 2007. The impact of
price risk management and marketing activities increased total natural gas and NGL revenues $1.0
million for 2008 compared to a decrease of $3.7 million in the same period of 2007.
Costs of product sold. Our cost of products increased $162.6 million, or 33%, for the year
ended December 31, 2008 compared to the same period in 2007. Of the increase, $138.3 million
relates to NGLs and $24.3 million relates to natural gas. The percentage increase in NGL cost of
products sold is greater than our percentage increase in NGL revenues as our NGL per barrel margins
decreased $0.53, or 22%, primarily due to a sharp decline in commodity prices experienced in the
fourth quarter of 2008. The percentage increase relating to natural gas cost of products sold is
greater than the percentage increase in natural gas revenues which caused our Mmbtu margins to
decrease by 70%, primarily as a result of the terms of Woodlawns producer contracts compared to
our historical producer contracts.
Operating expenses. Operating expenses increased $1.6 million, or 22%, for the year ended
December 31, 2008 compared to the same period of 2007. This increase is primarily due to a full
year of operations of the Woodlawn acquisition.
Selling, general and administrative expenses. Selling, general and administrative expenses
remained consistent for the years ended December 31, 2008 and 2007.
Depreciation and amortization. Depreciation and amortization increased $0.8 million, or 25%,
for the year ended December 31, 2008 compared to the same period of 2007. This increase was
primarily a result of the Woodlawn acquisition.
In summary, our natural gas services operating income decreased $1.4 million, or 33%, for the
year ended December 31, 2008 compared to the year ended December 31, 2007.
Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities
was $13.2 million and $10.9 million for the year ended December 31, 2008 and 2007, respectively, an
increase of 21%. This increase is primarily a result of receiving full benefit of the expansion to
the Waskom plant and the Waskom fractionator in 2008 as the plant was shut down for a portion of
2007. As a result, our inlet volumes increased 12% and our fractionation volumes increased 21% for
the year ended December 31, 2008 compared to the same period of 2007.
Sulfur Services Segment
The following table summarizes our results of operations in our sulfur services segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
372,987 |
|
|
$ |
131,602 |
|
Cost of products sold |
|
|
314,001 |
|
|
|
97,747 |
|
Operating expenses |
|
|
17,963 |
|
|
|
17,033 |
|
Selling, general and administrative expenses |
|
|
3,382 |
|
|
|
2,587 |
|
Depreciation and amortization |
|
|
5,751 |
|
|
|
5,013 |
|
|
|
|
|
|
|
|
|
|
|
31,890 |
|
|
|
9,222 |
|
|
|
|
|
|
|
|
Other operating income |
|
|
66 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
31,956 |
|
|
$ |
9,222 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sulfur (long tons) |
|
|
1,094.3 |
|
|
|
1,169.8 |
|
Fertilizer (long tons) |
|
|
227.6 |
|
|
|
251.1 |
|
|
|
|
|
|
|
|
Sulfur Services Volumes (long tons) |
|
|
1,321.9 |
|
|
|
1,420.9 |
|
|
|
|
|
|
|
|
Revenues. Our sulfur services revenues increased $241.4 million, or 183%, for the year ended
December 31, 2008 compared to the year ended December 31, 2007. This increase was primarily a
result of the significant escalation in market prices during 2008, primarily driven by higher costs
of sulfur and raw materials, which generated higher revenues on decreased volumes. Margins were
positively impacted due to a contract pricing provision with a significant customer which allowed
us to invoice them at prices greater than the prevailing market prices in the fourth quarter of
2008.
- 65 -
Cost of products sold. Our cost of products sold increased $216.3 million, or 221%, for the
year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was
primarily a result of significant escalation in market prices during 2008 which generated higher
cost of products sold on decreased volumes, particularly with respect to prilled sulfur.
Operating expenses. Our operating expenses increased $0.9 million, or 5%, for the year ended
December 31, 2008 compared to the year ended December 31, 2007. This increase was a result of
increased costs relating to fuel prices for marine transportation $0.4 million and increased gas
utilities pricing $0.5 million.
Selling, general, and administrative expenses. Our selling, general, and administrative
expenses increased $0.8 million, or 31%, for the year ended December 31, 2008 compared to the year
ended December 31, 2007. This increase is a result of increased compensation expense.
Depreciation and amortization. Depreciation and amortization increased $0.7 million, or 15%,
for the year ended December 31, 2008 compared to the year ended December 31, 2007. This is
attributable to full year of operations at our sulfuric acid facility.
In summary, our sulfur services operating income increased $22.7 million, or 247%, for the
year ended December 31, 2008 compared to the year ended December 31, 2007.
Marine Transportation Segment
The following table summarizes our results of operations in our marine transportation segment.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
80,059 |
|
|
$ |
63,533 |
|
Operating expenses |
|
|
57,346 |
|
|
|
46,946 |
|
Selling, general and administrative expenses |
|
|
2,635 |
|
|
|
535 |
|
Depreciation and amortization |
|
|
12,128 |
|
|
|
8,819 |
|
|
|
|
|
|
|
|
|
|
|
7,950 |
|
|
|
7,233 |
|
|
|
|
|
|
|
|
Other operating income |
|
|
154 |
|
|
|
716 |
|
|
|
|
|
|
|
|
Operating income |
|
$ |
8,104 |
|
|
$ |
7,949 |
|
|
|
|
|
|
|
|
Revenues. Our marine transportation revenues increased $16.5 million, or 26%, for the year
ended December 31, 2008 compared to the year ended December 31, 2007. Our inland marine assets
generated an additional $16.8 million in revenue from expansion of our inland fleet and increased
contract rates. This increase was offset by a slight decrease in our offshore revenues of $0.3
million resulting primarily from downtime associated with capital expenditures of offshore vessels.
Operating expenses. Operating expenses increased $10.4 million, or 22%, for the year ended
December 31, 2008 compared to the year ended December 31, 2007 due to increases in fuel of $4.7
million, salaries and wages of $3.3 million, property and liability premiums of $0.6 million and
repair and maintenance expenses of $0.4 million.
Selling, general and administrative expenses. Selling, general & administrative expenses
increased $2.1 million, or 393% for the year ended December 31, 2008 compared to the year ended
December 31, 2007. This increase was a result of the bankruptcy of a contractor to which we had
made advance payments for the construction of vessels of $1.3 million and other expenses associated
with the expansion of our fleet.
Depreciation and amortization. Depreciation and amortization increased $3.3 million, or 38%,
for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase
was the result of capital expenditures made in the last 12 months.
Other operating income. Other operating income decreased $0.5 million, or 78%, for the year
ended December 31, 2008 compared to the year ended December 31, 2007. In 2008, there were less
gains recorded on the sale of property and equipment than in 2007.
In summary, our marine transportation operating income increased $0.2 million, or 2%, for the
year ended December 31, 2008 compared to the year ended December 31, 2007.
- 66 -
Equity in Earnings of Unconsolidated Entities
For the years ended December 31, 2008 and 2007, equity in earnings of unconsolidated entities
relates to our unconsolidated interests in Waskom Gas Processing Company (Waskom), Matagorda,
PIPE and BCP.
Equity in earnings of unconsolidated entities was $13.2 million for the year ended December
31, 2008, compared to $10.9 million for the year ended December 31, 2007, an increase of $2.3
million. This increase is primarily a result of receiving full benefit of the expansion to the
Waskom plant and the Waskom fractionator in 2008 as the plant was shut down for a portion of 2007.
As a result, our inlet volumes increased 12% and our fractionation volumes increased 21% for the
year ended December 31, 2008 compared to the same period of 2007.
Interest Expense
Our interest expense for all operations was $21.4 million for 2008 compared to $15.1 million
for 2007, an increase of $6.3 million, or 42%. This increase was primarily due to an increase in
average debt outstanding offset by a decrease in interest rates throughout 2008 compared to 2007.
Also, we had interest swap cash settlements of $2.7 million and mark-to-market charges of $0.7
million which increased interest expense in 2008.
Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses were $5.5 million for 2008 compared to
$3.2 million for 2007, an increase of $2.3 million or 72%.
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 of 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.
In addition to the direct expenses, under the omnibus agreement, we are required to reimburse
Martin Resource Management for indirect general and administrative and corporate overhead expenses.
The amount of this reimbursement was capped at $2.0 million through November 1, 2007, when the cap
expired. For the years ended December 31, 2008 and 2007, the Conflicts Committee of our general
partner approved reimbursement amounts of $2.9 and $1.5 million, respectively, reflecting our
allocable share of such expenses. The Conflicts Committee will review and approve future
adjustments in the reimbursement amount for indirect expenses, if any, annually.
Liquidity and Capital Resources
Amendment to Credit Facility; Impact of Current Economic Crisis and Existing Litigation at Martin
Resource Management
On December 21, 2009, we entered into a Fourth Amendment (the Fourth Amendment) to the
Second Amended and Restated Credit Agreement (the Credit Agreement), among Martin Operating
Partnership L.P., a wholly-owned subsidiary of ours (the Operating Partnership), as borrower, the
Partnership and certain of our subsidiaries, as guarantors, the financial institutions parties
thereto, as lenders, Royal Bank of Canada, as administrative agent and collateral agent, and the
various other agents and parties thereto. The Fourth Amendment modified our existing Credit
Agreement to, among other things, (1) increase the total commitments of the lenders thereunder from
$325.0 million to approximately $335.7 million, (2) provide that the term loans thereunder will
automatically convert to revolving loans on November 10, 2010, such that after giving effect to
such conversion the aggregate revolving loan commitments will be approximately $335.7 million, (3)
extend the maturity date of amounts outstanding under the Credit Agreement from November 10, 2010
to November 9, 2012, (4) increase the applicable interest rate margin and fees payable to the
lenders under the Credit Agreement, (5) amend the financial covenants and certain other covenants
under the Credit Agreement, (6) include 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 $375.0 million for all
- 67 -
term loan and revolving loan commitments under the Credit Agreement, (7) eliminate the
requirement that we make annual prepayments of the term loans outstanding under the Credit
Agreement with excess cash flow, (8) eliminate the swing line facility under the Credit Agreement
and (9) limit asset dispositions to $25 million per fiscal year.
Subsequently, on January 14, 2010, we entered into a Fifth Amendment (the Fifth Amendment)
to the Credit Agreement. The Fifth Amendment modified the Credit Agreement to, among other things,
(1) permit us to invest up to $25 million in our joint ventures and (2) limit our ability to make
capital expenditures. And on February 25, 2010, we entered into a Commitment Increase and Joinder
Agreement (the Increase Joinder) with respect to the Credit Agreement. The Increase Joinder
increased the maximum amount of borrowings and letters of credit under our credit facility from
approximately $335.7 million to $350.0 million.
Due to the foregoing, 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 maintenance capital expenditures and scheduled debt payments in 2010.
Due to restrictions on liquidity within the capital markets and the existing litigation at
Martin Resource Management our ability to access the capital markets in the future may be
constrained. Our near-term focus is to ensure we have sufficient liquidity to fund our growth
programs, while continuing the present distribution rate to our unitholders. The current economic
crisis and the existing litigation at Martin Resource Management has created a challenging
operating environment for us to maintain our liquidity and operating cash flows at levels
consistent with the recent past while maintaining the present distribution rate to our unitholders.
We continue to evaluate our liquidity and capital resources and we have and will continue to
consider sales of non-essential assets and other available options for additional liquidity. For
example, in the second quarter of 2009 we sold the assets comprising the Mont Belvieu railcar
unloading facility to Enterprise Products Operating LLC. See Note 16 to our Financial Statements
Gain on Disposal of Assets.
Within the constraints noted above, we intend to move forward with our commercially supported
internal growth projects. We may revise the timing and scope of other projects as necessary to
adapt to existing economic, capital market and litigation conditions affecting us.
Finally, 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. For example, the impact of the current economic
crisis may significantly affect our customers, including their ability to satisfy receivables to us
on a timely basis. Please read Item 1A. Risk Factors Risks Related to Our Business for a
discussion of such risks.
General
In 2009, cash decreased $2.0 million as a result of $47.6 million provided by operating
activities, $14.7 million used in investing activities and $34.9 million used in financing
activities. In 2008, cash increased $3.9 million as a result of $86.3 million provided by
operating activities, $106.6 million used in investing activities and $24.2 million provided by
financing activities. In 2007, cash increased $0.8 million as a result of $61.2 million provided
by operating activities, $130.3 million used in investing activities and $69.9 million provided by
financing activities.
For 2009, our investing activities of $14.7 million consisted primarily of capital
expenditures, acquisitions, proceeds from sale of property, insurance proceeds from involuntary
conversion of property, plant and equipment, and investments in and returns of investments from
unconsolidated partnerships. Our investment in unconsolidated
partnerships helped to fund $0.4
million and $3.8 million in expansion capital expenditures made by these unconsolidated entities
for the fourth quarter and year ended December 31, 2009, respectively. For 2008, our investing
activities of $106.6 million consisted primarily of capital expenditures, acquisitions, proceeds
from sale of property, insurance proceeds from involuntary conversion of property, plant and
equipment, and investments in and returns of investments from unconsolidated partnerships. Our
investment in unconsolidated partnerships helped to fund $0.9 million and $5.2 million in expansion
capital expenditures made by these unconsolidated entities for the fourth quarter and year ended
December 31, 2008, respectively. For 2007, our investing activities of $130.3 million consisted
primarily of capital expenditures, acquisitions, proceeds from sale of property, and investments in
and returns of investments from unconsolidated partnerships. Our investment in unconsolidated
partnerships helped to fund $1.2 million and $8.2 million in expansion capital expenditures made by
these unconsolidated entities for the fourth quarter and year ended December 31, 2007,
respectively.
- 68 -
For 2009, 2008 and 2007 our capital expenditures for property and equipment were $44.1
million, $107.4 million, and $121.4 million, respectively.
As to each period:
|
|
|
In 2009, we spent $36.5 million for expansion and $7.6 million for
maintenance (including $0.9 million for maintenance in the fourth quarter of 2009).
Our expansion capital expenditures were made in connection with marine vessel purchases
and conversions, construction projects associated with our terminalling and sulfur
services businesses. 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. |
|
|
|
|
In 2008, we spent $89.4 million for expansion and $18.0 million for
maintenance (including $7.0 million for maintenance in the fourth quarter of 2008).
Our expansion capital expenditures were made in connection with marine vessel purchases
and conversions, construction projects associated with our terminalling business. 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 terminalling and sulfur services at our Neches facility,
where $1.5 million in maintenance capital expenditures was spent in connection with
restoration of assets destroyed in Hurricanes Gustav and Ike. |
|
|
|
|
In 2007, we spent $109.5 million for expansion and $11.9 million for
maintenance (including $4.1 million for maintenance in the fourth quarter of 2007).
Our expansion capital expenditures were made in connection with the Woodlawn and Mega
Lube acquisitions, marine vessel purchases and conversions, construction projects
associated with our terminalling business, 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 include $0.3 million
spent in connection with the restoration of assets destroyed in hurricanes Rita and
Katrina. |
In 2009, our financing activities consisted of payments of long-term debt under our credit
facilities of $432.0 million and borrowings of long-term debt under our credit facilities of $433.7
million, cash distributions paid to common and subordinated unitholders of $47.5 million, purchase
of treasury stock of $0.1 million and payments of debt issuance costs of $10.4 million. Additional
financing activities consisted of $20.0 million in connection with a private equity offering
issuance of 714,285 common units to Martin Resource Management and contributions of $1.3 million
from our general partner to maintain its 2% general partner interest.
In November 2009, we acquired the Cross assets for total consideration of $44.9 million as a
result of a non-cash financing activity. As consideration for the contribution of the Cross
assets, we issued 804,721 of our common units and 889,444 subordinated units to Martin Resource
Management at a price of $27.96 and $25.16 per limited partner unit, respectively. In connection
with the contribution of the Cross assets, our general partner made a capital contribution of $0.9
million to us in order to maintain its 2% general partner interest.
In 2008, our financing activities consisted of payments of long-term debt under our credit
facilities of $257.2 million and borrowings of long-term debt under our credit facilities of $327.2
million, cash distributions paid to common and subordinated unitholders of $45.7 million, purchase
of treasury stock of $0.1 million and payments of debt issuance costs of $18 thousand.
In 2007, our financing activities consisted of payments of long-term debt under our credit
facilities of $169.0 million and borrowings of long-term debt under our credit facilities of $220.0
million, cash distributions paid to common and subordinated unitholders of $37.9 million and
payments of debt issuance costs of $0.3 million. Additional financing activities consisted of net
proceeds from a follow-on public equity offering of $55.9 million and contributions of $1.2 million
from our general partner to maintain its 2% general partner interest.
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 to be cash flows from operations and borrowings
under our credit facility.
As of December 31, 2009, we had $298.2 million of outstanding indebtedness, consisting of
outstanding borrowings of $230.3 million under our revolving credit facility and $67.9 million
under our term loan facility.
- 69 -
In November 2009, we acquired certain specialty lubricants processing assets through the
issuance of 804,721 common units and 889,444 subordinated units for total consideration of $44.9
million. Our general partner contributed $0.9 million in cash to us in conjunction with the
issuance in order to maintain its 2% general partner interest in us.
In November 2009, we issued 714,285 common units to Martin Resource LLC, an affiliate of
Martin Resource Management, for approximately $20.4 million, including a capital contribution of
approximately $0.4 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.
Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of
December 31, 2009 is as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment due by period |
|
|
|
Total |
|
|
|
|
|
|
1-3 |
|
|
3-5 |
|
|
|
|
Type of Obligation |
|
Obligation |
|
|
Less than One Year |
|
|
Years |
|
|
Years |
|
|
Due Thereafter |
|
Long-Term Debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving credit facility |
|
$ |
230,251 |
|
|
$ |
|
|
|
$ |
230,251 |
|
|
$ |
|
|
|
$ |
|
|
Term loan facility |
|
|
67,949 |
|
|
|
|
|
|
|
67,949 |
|
|
|
|
|
|
|
|
|
Capital leases including current maturities |
|
|
6,283 |
|
|
|
111 |
|
|
|
297 |
|
|
|
482 |
|
|
|
5,393 |
|
Non-competition agreements |
|
|
250 |
|
|
|
50 |
|
|
|
100 |
|
|
|
100 |
|
|
|
|
|
Purchase obligations |
|
|
23,280 |
|
|
|
7,760 |
|
|
|
15,520 |
|
|
|
|
|
|
|
|
|
Operating leases |
|
|
23,082 |
|
|
|
4,233 |
|
|
|
9,698 |
|
|
|
4,314 |
|
|
|
4,837 |
|
Interest expense(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving credit facility |
|
|
53,205 |
|
|
|
18,614 |
|
|
|
34,591 |
|
|
|
|
|
|
|
|
|
Term loan facility |
|
|
9,190 |
|
|
|
3,215 |
|
|
|
5,975 |
|
|
|
|
|
|
|
|
|
Capital leases |
|
|
6,071 |
|
|
|
991 |
|
|
|
1,921 |
|
|
|
1,800 |
|
|
|
1,359 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations |
|
$ |
419,561 |
|
|
$ |
34,974 |
|
|
$ |
366,302 |
|
|
$ |
6,696 |
|
|
$ |
11,589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Interest commitments are estimated using our current interest rates for the respective credit
agreements over their remaining terms. |
Letter of Credit. At December 31, 2009, we had outstanding irrevocable letters of credit in the
amount of $2.1 million, which were issued under our revolving credit facility.
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 $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, as amended on December 21, 2009,
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 $375.0
million for all commitments under the credit facility. Effective June 30, 2006, we increased our
revolving credit facility by $25.0 million, resulting in a committed $120.0 million revolving
credit facility. Effective December 28, 2007, we increased our revolving credit facility by $75.0
million, resulting in a committed $195.0 million revolving credit facility. Effective December 21,
2009, (i) we increased our revolving credit facility by approximately $72.7 million, resulting in a
committed $267.8 million revolving credit facility and (ii) decreased our term loan facility by
approximately $62.1 million, resulting in a $67.9 million term loan facility. On November 10, 2010,
the term loans under our credit facility will automatically convert to revolver loans that mature
on November 9, 2012 along with the aggregate principal amount all outstanding committed revolver
loans outstanding on such date.
Under the credit facility, as of December 31, 2009, we had approximately $230.3 million
outstanding under the revolving credit facility, $67.9 million outstanding under the term loan
facility, and $2.1 million of letters of credit issued under our credit facility, leaving
approximately $35.4 million available under our credit facility for future revolving credit
borrowings and letters of credit.
- 70 -
On February 25, 2010, we increased the maximum amount of borrowings and letters of credit
under our credit facility from approximately $335.7 million to $350.0 million. As of February 25,
2010, after giving effect to this increase, we had approximately $210.1 million outstanding under
the revolving credit facility, $67.9 million outstanding under the term loan facility, and $2.1
million of letters of credit issued under our credit facility, leaving approximately $69.9 million
available under our credit facility for future revolving credit borrowings and letters of credit.
The revolving credit facility is used for ongoing working capital needs and general partnership
purposes, and to finance permitted investments, acquisitions and capital expenditures. During
2009, draws on our credit facility ranged from a low of $285.0 million to a high of $315.0 million.
The credit facility matures on November 9, 2012, and all amounts outstanding thereunder are
due on such date. The credit facility is guaranteed by substantially all of our subsidiaries.
Obligations under the credit facility are secured by first priority liens on substantially all of
our assets and those of the guarantors, , including, without limitation, inventory, accounts
receivable, bank accounts, marine vessels, equipment, fixed assets and the interests in our
subsidiaries and certain of our equity method investees.
We may prepay all amounts outstanding under the credit facility at any time without premium or
penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The
credit facility requires mandatory prepayments of amounts outstanding thereunder with the net
proceeds of certain asset sales, equity issuances and debt incurrences. Prepayments as a result of
asset sales and debt incurrences require a mandatory reduction of the lenders commitments under
the credit facility equal to 25% of the corresponding mandatory prepayment, but in no event will
such prepayments cause the lenders commitments under the credit facility to be less than $250.0
million. Prepayments as a result of equity issuances do not require any reduction of the lenders
commitments under the credit facility.
Indebtedness under the credit facility bears interest at our option at the Eurodollar Rate
(the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the
highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the
administrative agents prime rate) plus an applicable margin. We pay a per annum fee on all letters
of credit issued under the credit facility, and we pay a commitment fee of 0.50% per annum on the
unused revolving credit availability under the credit facility. The letter of credit fee and the
applicable margins for our interest rate vary quarterly based on our leverage ratio (as defined in
the new credit facility, being generally computed as the ratio of total funded debt to consolidated
earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eurodollar Rate |
|
Letter of Credit |
Leverage Ratio |
|
Base Rate Loans |
|
Loans |
|
Fees |
Less than 2.75 to 1.00 |
|
|
2.50 |
% |
|
|
3.50 |
% |
|
|
3.50 |
% |
Greater than or equal to 2.75 to 1.00 and less than 3.00 to 1.00 |
|
|
2.75 |
% |
|
|
3.75 |
% |
|
|
3.75 |
% |
Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00 |
|
|
3.00 |
% |
|
|
4.00 |
% |
|
|
4.00 |
% |
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00 |
|
|
3.50 |
% |
|
|
4.50 |
% |
|
|
4.50 |
% |
Greater than or equal to 4.00 to 1.00 |
|
|
3.75 |
% |
|
|
4.75 |
% |
|
|
4.75 |
% |
As of December 31, 2009, based on our leverage ratio the applicable margin for existing
Eurodollar Rate borrowings is 4.50%. Effective January 1, 2010, based on our leverage ratio as of
December 31, 2010, the applicable margin for Eurodollar Rate borrowings will remain at 4.50% until
the next quarterly determination of our leverage ratio. The credit facility does not have a floor
for the Base Rate or the Eurodollar Rate.
The credit facility includes financial covenants that are tested on a quarterly basis, based
on the rolling four-quarter period that ends on the last day of each fiscal quarter. Prior to our
or any of our subsidiaries issuance of $100.0 million or more of unsecured indebtedness, the
maximum permitted leverage ratio is 4.00 to 1.00. After our or any of our subsidiaries issuance
of $100.0 million or more of unsecured indebtedness, the maximum permitted leverage ratio is 4.25
to 1.00. After our or any of our subsidiaries issuance of $100.0 million or more of unsecured
indebtedness, the maximum permitted senior leverage ratio (as defined in the new credit facility,
but generally computed as the ratio of total secured funded debt to consolidated earnings before
interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.00 to 1.00.
The minimum consolidated interest coverage ratio (as defined in the new credit facility, but
generally computed as the ratio of consolidated earnings before interest, taxes, depreciation,
amortization and certain other non-cash charges to consolidated interest charges) is 3.00 to 1.00.
In addition, the credit facility contains various covenants that, among other restrictions,
limit our and our subsidiaries ability to:
- 71 -
|
|
|
grant or assume liens; |
|
|
|
|
make investments (including investments in our joint ventures) and
acquisitions; |
|
|
|
|
enter into certain types of hedging agreements; |
|
|
|
|
incur or assume indebtedness; |
|
|
|
|
sell, transfer, assign or convey assets; |
|
|
|
|
repurchase our equity, make distributions and certain other restricted
payments, but the credit facility permits us to make quarterly distributions to
unitholders so long as no default or event of default exists under the credit facility; |
|
|
|
|
change the nature of our business; |
|
|
|
|
engage in transactions with affiliates. |
|
|
|
|
enter into certain burdensome agreements; |
|
|
|
|
make certain amendments to the omnibus agreement and our material agreements; |
|
|
|
|
make capital expenditures; and |
|
|
|
|
permit our joint ventures to incur indebtedness or grant certain liens. |
|
|
Each of the following will be an event of default under the credit facility: |
|
|
|
failure to pay any principal, interest, fees, expenses or other amounts when
due; |
|
|
|
|
failure to meet the quarterly financial covenants; |
|
|
|
|
failure to observe any other agreement, obligation, or covenant in the credit
facility or any related loan document, subject to cure periods for certain failures; |
|
|
|
|
the failure of any representation or warranty to be materially true and correct
when made; |
|
|
|
|
our or any of our subsidiaries default under other indebtedness that exceeds a
threshold amount; |
|
|
|
|
bankruptcy or other insolvency events involving us or any of our subsidiaries; |
|
|
|
|
judgments against us or any of our subsidiaries, in excess of a threshold
amount; |
|
|
|
|
certain ERISA events involving us or any of our subsidiaries, in excess of a
threshold amount; |
|
|
|
|
a change in control (as defined in the credit facility); |
|
|
|
|
the termination of any material agreement or certain other events with respect
to material agreements; |
|
|
|
|
the invalidity of any of the loan documents or the failure of any of the
collateral documents to create a lien on the collateral; |
|
|
|
|
any of our joint ventures incurs debt or liens in excess of a threshold amount. |
The credit facility also contains certain default provisions relating to Martin Resource
Management. If Martin Resource Management no longer controls our general partner, the lenders under
our credit facility may declare all amounts outstanding there under immediately due and payable. In
addition, either a bankruptcy event with respect to Martin Resource Management or a judgment with
respect to Martin Resource Management could independently result in an event of default under our
credit facility if it is deemed to have a material adverse effect on us.
- 72 -
If an event of default relating to bankruptcy or other insolvency events occurs with respect
to us or any of our subsidiaries, all indebtedness under our credit facility will immediately
become due and payable. If any other event of default exists under our credit facility, the lenders
may terminate their commitments to lend us money, accelerate the maturity of the indebtedness
outstanding under the credit facility and exercise other rights and remedies. In addition, if any
event of default exists under our credit facility, the lenders may commence foreclosure or other
actions against the collateral. Any event of default and corresponding acceleration of outstanding
balances under our credit facility could require us to refinance such indebtedness on unfavorable
terms and would have a material adverse effect on our financial condition and results of operations
as well as our ability to make distributions to unitholders.
If any default occurs under our credit facility, or if we are unable to make any of the
representations and warranties in the credit facility, we will be unable to borrow funds or have
letters of credit issued under our credit facility.
As of March 3, 2010, our outstanding indebtedness includes $275.0 million under our credit
facility.
We are subject to interest rate risk on our credit facility and may enter into interest rate
swaps to reduce this risk.
Effective October 2008, we entered into an interest rate swap that swaps $40.0 million of
floating rate to fixed rate. The fixed rate cost is 2.820% plus our applicable LIBOR borrowing
spread. Effective April 2009, we entered into two subsequent swaps to lower our effective fixed
rate to 2.580% plus our applicable LIBOR borrowing spread. The original swap and the first
subsequent swap are accounted for using mark-to-market accounting. The second subsequent swap is
accounted for using hedge accounting. Each of the swaps matures in October 2010.
Effective January 2008, we entered into an interest rate swap that swaps $25.0 million of
floating rate to fixed rate. The fixed rate cost is 3.400% plus our applicable LIBOR borrowing
spread. Effective April 2009, we entered into two subsequent swaps to lower our effective fixed
rate to 3.050% plus our applicable LIBOR borrowing spread. The original swap and the first
subsequent swap are accounted for using mark-to-market accounting. The second subsequent swap is
accounted for using hedge accounting. Each of the swaps matured in January 2010.
Effective September 2007, we entered into an interest rate swap that swaps $25.0 million of
floating rate to fixed rate. The fixed rate cost is 4.605% plus our applicable LIBOR borrowing
spread. Effective March 2009, we entered into two subsequent swaps to lower our effective fixed
rate to 4.305% plus our applicable LIBOR borrowing spread. The original swap and the first
subsequent swap are accounted for using mark-to-market accounting. The second subsequent swap is
accounted for using hedge accounting. Each of the swaps matures in September 2010.
Effective November 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 using hedge
accounting.
Effective March 2006, we entered into an interest rate swap that swaps $75.0 million of
floating rate to fixed rate. The fixed rate cost is 5.25% plus our applicable LIBOR borrowing
spread. Effective February 2009, we entered into two subsequent swaps to lower our effective fixed
rate to 5.10% plus our applicable LIBOR borrowing spread. The original swap and the first
subsequent swap are accounted for using mark-to-market accounting. The second subsequent swap is
accounted for using hedge accounting. Each of the swaps matures in November 2010.
Seasonality
A substantial portion of our revenues are dependent on sales prices of products, particularly
NGLs and sulfur-based fertilizer products, 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
- 73 -
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 Gustav and Ike in the third quarter of
2008 and Hurricanes Katrina and Rita in the third quarter of 2005 adversely impacted our operating
expenses and 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 2009, 2008 and 2007. 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.
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 2009, 2008 or 2007.
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 year ended December 31, 2009, changes in the fair value of our derivative contracts were
recorded both in earnings and accumulated other comprehensive income (AOCI) since we have
designated a portion of our derivative instruments as hedges as of December 31, 2009.
Commodity Price Risk. We are exposed to market risks associated with commodity prices,
counterparty credit and interest rates. 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. These outstanding
contracts expose us to credit loss in the event of nonperformance by the counterparties to the
agreements. We have incurred no losses associated with counterparty nonperformance on derivative
contracts.
On all transactions where we are exposed to counterparty risk, we analyze the counterpartys
financial condition prior to entering into an agreement, have established a maximum credit limit
threshold pursuant to our hedging policy, and monitor the appropriateness of these limits on an
ongoing basis. We have agreements with three counterparties containing collateral provisions. Based
on those current agreements, cash deposits are required to be posted whenever the net fair value of
derivatives associated with the individual counterparty exceed a specific threshold. If this
threshold is exceeded, cash is posted by us if the value of derivatives is a liability to us. As of
December 31, 2009, we have no cash collateral deposits posted with counterparties.
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. Our exposure to these
fluctuations is primarily in the gas processing component of our business. 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 and percent-of-proceeds basis.
|
1) |
|
Percent-of-liquids contracts: Under these contracts, we receive a fee
in the form of a percentage of the NGLs recovered, and the producer bears all of
the cost of natural gas shrink. Therefore, margins increase during periods of high
NGL prices and decrease during periods of low NGL prices. |
- 74 -
|
2) |
|
Percent-of-proceeds contracts: Under these contracts, we generally gather and
process natural gas on behalf of certain producers, sell the resulting residue gas
and NGLs at market prices and remit to producers an agreed upon percentage of the
proceeds based on an index price. In other cases, instead of remitting cash
payments to the producer, we deliver an agreed upon percentage of the residue gas
and NGLs to the producer and sell the volumes kept to third parties at market
prices. Under these types of contracts, revenues and gross margins increase as
natural gas prices and NGL prices increase, and revenues and gross margins decrease
as natural gas and NGL prices decease. |
Market risk associated with gas processing margins by contract type, and gathering and
transportation margins as a percent of total gross margin remained consistent for the years ended
December 31, 2009 and 2008 as our contract mix and volumes associated with those contracts did not
differ materially.
The aggregate effect of a hypothetical $1.00/MMbtu increase or decrease in the natural gas
price index would result in an approximate annual gross margin change of $0.5 million. In addition,
the aggregate effect of a hypothetical $10.00/Bbl increase or decrease in the crude oil price index
would result in an approximate annual gross margin change of $0.7 million.
Prism Gas has entered into hedging transactions through 2010 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 natural gasoline.
Based on estimated volumes, as of December 31, 2009, we had hedged approximately 50% of our
commodity risk by volume for 2010. We anticipate entering into additional commodity derivatives on
an ongoing basis to manage our 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 we will be able to do so or that the terms thereof
will be similar to our existing hedging arrangements.
The relevant payment indices for our various commodity contracts are as follows:
|
|
|
Natural gas contracts monthly posting for ANR Pipeline Co. Louisiana as
posted in Platts Inside FERCs Gas Market Report; |
|
|
|
|
Crude oil contracts WTI NYMEX average for the month of the daily closing
prices; and |
|
|
|
|
Natural gasoline contracts Mt. Belvieu Non-TET average monthly postings as
reported by the Oil Price Information Service (OPIS). |
Derivative Contracts in Place
As of December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
|
Commodity |
|
|
Fair Value |
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
Price |
|
|
Asse |
|
|
Liability |
|
Period |
|
Underlying |
|
|
Notional Volume |
|
|
We Receive |
|
|
We Pay |
|
|
(In Thousands) |
|
|
(In Thousands) |
|
|
January
2010-December 2010 |
|
Crude Oil |
|
24,000 (BBL) |
|
Index |
|
$69.15/bbl |
|
$ |
|
|
|
$ |
290 |
|
January
2010-December 2010 |
|
Crude Oil |
|
36,000 (BBL) |
|
Index |
|
$72.25/bbl |
|
|
|
|
|
|
326 |
|
January
2010-December 2010 |
|
Crude Oil |
|
12,000 (BBL) |
|
Index |
|
$104.80/bbl |
|
|
275 |
|
|
|
|
|
January
2010-December 2010 |
|
Natural Gasoline |
|
12,000 (BBL) |
|
Index |
|
$94.14/bbl |
|
|
241 |
|
|
|
|
|
January
2010-December 2010 |
|
Natural Gas |
|
240,000 (MMBTU) |
|
Index |
|
$5.95/Mmbtu |
|
|
42 |
|
|
|
|
|
January
2010-December 2010 |
|
Natural Gas |
|
120,000 (MMBTU) |
|
Index |
|
$6.005/Mmbtu |
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
586 |
|
|
$ |
616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our 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 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 discontinuance of deliveries to
the buyer unless the buyer provides security for payment in a form satisfactory to us.
- 75 -
Interest Rate Risk
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 7.32% as of December 31, 2009. As of
March 3, 2010, we had a total of $275.0 million of indebtedness outstanding under our credit
facility of which $110.0 million was unhedged floating rate debt. Based on the amount of unhedged
floating rate debt owed by us on December 31, 2009, 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 $1.1 million annually.
We have entered into interest rate protection agreements to manage our interest rate risk
exposure by fixing a portion of the interest expense we pay on our long-term debt under our credit
facility. Continued instability in the banking markets could affect whether our counterparties of
interest rate protection agreements are able to honor their agreements. If the counterparties fail
to honor their commitments, we could experience higher interest rates, which could have a material
adverse effect on our business, financial condition and results of operations. In addition, if the
counterparties fail to honor their commitments, we also may be required to replace such interest
rate protection agreements with new interest rate protection agreements, and such replacement
interest rate protection agreements may be at higher rates than our current interest rate
protection agreements.
We manage a portion of our interest rate risk with interest rate swaps, which reduce our
exposure to changes in interest rates by converting variable interest rates to fixed interest
rates. Pursuant to the terms of the interest rate swap agreement, we pay a fixed rate and receive
an interest payment based on the one-month LIBOR. The net difference to be paid or received under
the interest rate swap agreement is settled monthly and is recognized as an adjustment to interest
expense.
At December 31, 2009, we are party to interest rate swap agreements with Royal Bank of Canada
as shown below:
Interest Rate Swaps
As of December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
Fair Value |
|
|
|
|
|
|
|
Notional |
|
|
Interest Rate |
|
Interest Rate |
|
Asset |
|
|
Liability |
|
Date of Swap |
|
Maturity |
|
|
Amount |
|
|
We Pay |
|
We Receive |
|
(In Thousands) |
|
|
(In Thousands) |
|
|
March 2006 |
|
November 2010 |
|
$ |
75,000 |
|
|
|
5.250 |
% |
|
3 MO LIBOR |
|
$ |
|
|
|
$ |
3,448 |
|
November 2006 |
|
March 2010 |
|
$ |
30,000 |
|
|
|
4.765 |
% |
|
3 MO LIBOR |
|
|
|
|
|
|
334 |
|
September 2007 |
|
September 2010 |
|
$ |
25,000 |
|
|
|
4.605 |
% |
|
3 MO LIBOR |
|
|
|
|
|
|
771 |
|
January 2008 |
|
January 2010 |
|
$ |
25,000 |
|
|
|
3.400 |
% |
|
3 MO LIBOR |
|
|
|
|
|
|
198 |
|
October 2008 |
|
October 2010 |
|
$ |
40,000 |
|
|
|
2.820 |
% |
|
3 MO LIBOR |
|
|
|
|
|
|
938 |
|
February 2009 |
|
November 2010 |
|
$ |
75,000 |
|
|
|
1.295 |
% |
|
1 MO LIBOR |
|
|
|
|
|
|
556 |
|
March 2009 |
|
September 2010 |
|
$ |
25,000 |
|
|
|
1.290 |
% |
|
1 MO LIBOR |
|
|
|
|
|
|
169 |
|
April 2009 |
|
January 2010 |
|
$ |
25,000 |
|
|
|
.720 |
% |
|
1 MO LIBOR |
|
|
|
|
|
|
10 |
|
April 2009 |
|
October 2010 |
|
$ |
40,000 |
|
|
|
1.000 |
% |
|
1 MO LIBOR |
|
|
|
|
|
|
187 |
|
February 2009 |
|
November 2010 |
|
$ |
75,000 |
|
|
3 MO LIBOR |
|
|
1.445 |
% |
|
|
696 |
|
|
|
|
|
March 2009 |
|
September 2010 |
|
$ |
25,000 |
|
|
3 MO LIBOR |
|
|
1.590 |
% |
|
|
220 |
|
|
|
|
|
April 2009 |
|
January 2010 |
|
$ |
25,000 |
|
|
3 MO LIBOR |
|
|
1.070 |
% |
|
|
50 |
|
|
|
|
|
April 2009 |
|
October 2010 |
|
$ |
40,000 |
|
|
3 MO LIBOR |
|
|
1.240 |
% |
|
|
320 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,286 |
|
|
$ |
6,611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 76 -
Item 8. Financial Statements and Supplementary Data
The following financial statements of Martin Midstream Partners L.P. (Partnership):
|
|
|
|
|
|
|
Page |
|
|
|
|
|
|
|
|
|
78 |
|
|
|
|
|
|
|
|
|
79 |
|
|
|
|
|
|
|
|
|
80 |
|
|
|
|
|
|
|
|
|
81 |
|
|
|
|
|
|
|
|
|
82 |
|
|
|
|
|
|
|
|
|
83 |
|
|
|
|
|
|
|
|
|
84 |
|
|
|
|
|
|
|
|
|
85 |
|
- 77 -
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, 2009 and 2008, 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, 2009. 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 Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the 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, 2009, in conformity with U.S. generally accepted accounting
principles.
We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Martin Midstream Partners L.P. and subsidiaries internal control
over financial reporting as of December 31, 2009, 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 4, 2010 expressed an unqualified opinion on the
effectiveness of Martin Midstream Partners L.P. and subsidiaries internal control over financial
reporting.
/s/ KPMG LLP
Shreveport, Louisiana
March 4, 2010
- 78 -
Report of Independent Registered Public Accounting Firm
The Board of Directors
Martin Midstream GP LLC:
We have audited Martin Midstream Partners L.P. and subsidiaries internal control over
financial reporting as of December 31, 2009, 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 included in the accompanying Managements Report on Internal Control Over
Financial Reporting in Item 9A(b). Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of internal control based on the assessed
risk. Our audit also included 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 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 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, Martin Midstream Partners L.P. and subsidiaries maintained, in all respects,
effective internal control over financial reporting as of December 31, 2009, based on criteria
established in Internal Control Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
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, 2009 and 2008, 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, 2009, and our report dated March 4, 2010 expressed an
unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Shreveport, Louisiana
March 4, 2010
- 79 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 1 |
|
|
|
(Dollars in thousands) |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash |
|
$ |
5,956 |
|
|
$ |
7,983 |
|
Accounts and other receivables, less allowance for doubtful
accounts of $1,025 and $481, respectively |
|
|
77,413 |
|
|
|
68,168 |
|
Product exchange receivables |
|
|
4,132 |
|
|
|
6,924 |
|
Inventories |
|
|
35,510 |
|
|
|
42,754 |
|
Due from affiliates |
|
|
3,051 |
|
|
|
555 |
|
Fair value of derivatives |
|
|
1,872 |
|
|
|
3,623 |
|
Other current assets |
|
|
1,340 |
|
|
|
3,418 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
129,274 |
|
|
|
133,425 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, at cost |
|
|
584,036 |
|
|
|
576,608 |
|
Accumulated depreciation |
|
|
(162,121 |
) |
|
|
(130,976 |
) |
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
421,915 |
|
|
|
445,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill |
|
|
37,268 |
|
|
|
37,405 |
|
Investment in unconsolidated entities |
|
|
80,582 |
|
|
|
79,843 |
|
Fair value of derivatives |
|
|
|
|
|
|
1,469 |
|
Other assets, net |
|
|
16,900 |
|
|
|
8,548 |
|
|
|
|
|
|
|
|
|
|
$ |
685,939 |
|
|
$ |
706,322 |
|
|
|
|
|
|
|
|
Liabilities and Partners Capital |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current installments of lease obligations |
|
$ |
111 |
|
|
$ |
|
|
Trade and other accounts payable |
|
|
71,911 |
|
|
|
94,146 |
|
Product exchange payables |
|
|
7,986 |
|
|
|
10,924 |
|
Due to affiliates |
|
|
13,810 |
|
|
|
23,085 |
|
Income taxes payable |
|
|
454 |
|
|
|
414 |
|
Fair value of derivatives |
|
|
7,227 |
|
|
|
6,478 |
|
Other accrued liabilities |
|
|
5,000 |
|
|
|
6,428 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
106,499 |
|
|
|
141,475 |
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases, less current maturities |
|
|
304,372 |
|
|
|
295,000 |
|
Deferred income taxes |
|
|
8,628 |
|
|
|
17,499 |
|
Fair value of derivatives |
|
|
|
|
|
|
4,302 |
|
Other long-term obligations |
|
|
1,489 |
|
|
|
1,667 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
420,988 |
|
|
|
459,943 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners capital |
|
|
267,027 |
|
|
|
251,314 |
|
Accumulated other comprehensive loss |
|
|
(2,076 |
) |
|
|
(4,935 |
) |
|
|
|
|
|
|
|
Total partners capital |
|
|
264,951 |
|
|
|
246,379 |
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
$ |
685,939 |
|
|
$ |
706,322 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Financial information for 2008 has been revised to include balances attributable to the Cross
assets. See Note 2(a) Principles of Presentation and Consolidation. |
See accompanying notes to consolidated financial statements.
- 80 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 1 |
|
|
2008 1 |
|
|
2007 1 |
|
|
|
(Dollars in thousands, except per unit amounts) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling and storage * |
|
$ |
69,710 |
|
|
$ |
68,552 |
|
|
$ |
67,905 |
|
Marine transportation * |
|
|
68,480 |
|
|
|
76,349 |
|
|
|
59,579 |
|
Product sales: * |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas services |
|
|
408,982 |
|
|
|
679,375 |
|
|
|
515,992 |
|
Sulfur services |
|
|
79,629 |
|
|
|
371,949 |
|
|
|
131,326 |
|
Terminalling and storage |
|
|
35,584 |
|
|
|
50,219 |
|
|
|
29,525 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
524,195 |
|
|
|
1,101,543 |
|
|
|
676,843 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
662,385 |
|
|
|
1,246,444 |
|
|
|
804,327 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold: (excluding depreciation and amortization) |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas services * |
|
|
382,542 |
|
|
|
657,662 |
|
|
|
495,641 |
|
Sulfur services * |
|
|
43,386 |
|
|
|
313,143 |
|
|
|
97,577 |
|
Terminalling and storage |
|
|
31,331 |
|
|
|
42,721 |
|
|
|
25,471 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
457,259 |
|
|
|
1,013,526 |
|
|
|
618,689 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses * |
|
|
117,438 |
|
|
|
126,808 |
|
|
|
104,165 |
|
Selling, general and administrative * |
|
|
19,775 |
|
|
|
19,062 |
|
|
|
13,918 |
|
Depreciation and amortization |
|
|
39,506 |
|
|
|
34,893 |
|
|
|
26,323 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
633,978 |
|
|
|
1,194,289 |
|
|
|
763,095 |
|
|
|
|
|
|
|
|
|
|
|
Other operating income |
|
|
6,013 |
|
|
|
209 |
|
|
|
703 |
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
34,420 |
|
|
|
52,364 |
|
|
|
41,935 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated entities |
|
|
7,044 |
|
|
|
13,224 |
|
|
|
10,941 |
|
Interest expense |
|
|
(18,995 |
) |
|
|
(21,433 |
) |
|
|
(15,125 |
) |
Other, net |
|
|
326 |
|
|
|
801 |
|
|
|
405 |
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense) |
|
|
(11,625 |
) |
|
|
(7,408 |
) |
|
|
(3,779 |
) |
|
|
|
|
|
|
|
|
|
|
Net income before taxes |
|
|
22,795 |
|
|
|
44,956 |
|
|
|
38,156 |
|
Income tax benefit (expense) |
|
|
(592 |
) |
|
|
(1,398 |
) |
|
|
(5,595 |
) |
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
22,203 |
|
|
$ |
43,558 |
|
|
$ |
32,561 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income2 |
|
$ |
3,249 |
|
|
$ |
3,301 |
|
|
$ |
1,564 |
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income2 |
|
$ |
17,179 |
|
|
$ |
39,509 |
|
|
$ |
23,375 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit basic and diluted |
|
$ |
1.17 |
|
|
$ |
2.72 |
|
|
$ |
1.67 |
|
Weighted average limited partner units basic |
|
|
14,680,807 |
|
|
|
14,529,826 |
|
|
|
14,018,799 |
|
Weighted average limited partner units diluted |
|
|
14,684,775 |
|
|
|
14,534,722 |
|
|
|
14,022,545 |
|
|
|
|
1 |
|
Financial information for 2007, 2008 and for the period January 1, 2009 through November
24, 2009 has been revised to include results attributable to the
Cross assets. See Note 2(a)
Principles of Presentation and Consolidation. |
|
2 |
|
General and limited partners interest in net income includes net income of the Cross
assets since the date of the acquisition. |
|
|
|
See accompanying notes to consolidated financial statements. |
|
* |
|
Related Party Transactions Included Above |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
19,998 |
|
|
$ |
18,362 |
|
|
$ |
11,816 |
|
Marine transportation |
|
|
19,370 |
|
|
|
24,956 |
|
|
|
23,729 |
|
Product Sales |
|
|
5,838 |
|
|
|
26,704 |
|
|
|
7,577 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold: (excluding depreciation and amortization) |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas services |
|
|
56,914 |
|
|
|
92,322 |
|
|
|
62,686 |
|
Sulfur services |
|
|
12,583 |
|
|
|
13,282 |
|
|
|
13,992 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
37,284 |
|
|
|
37,661 |
|
|
|
28,991 |
|
Selling, general and administrative |
|
|
7,162 |
|
|
|
6,284 |
|
|
|
4,089 |
|
- 81 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL
For the years ended December 31, 2009, 2008 and 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners Capital |
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated |
|
|
|
|
|
|
Comprehensive |
|
|
|
|
|
|
Parent Net |
|
|
Common |
|
|
Units |
|
|
Amount |
|
|
General Partner |
|
|
Income |
|
|
|
|
|
|
Investment 1 |
|
|
Units |
|
|
Amount |
|
|
(Dollars in thousands) |
|
|
Amount |
|
|
Amount |
|
|
Total |
|
Balances December 31, 2006 |
|
$ |
3,295 |
|
|
|
10,603,808 |
|
|
$ |
201,426 |
|
|
|
2,552,018 |
|
|
$ |
(6,224 |
) |
|
$ |
3,201 |
|
|
$ |
122 |
|
|
$ |
201,820 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
7,622 |
|
|
|
|
|
|
|
19,781 |
|
|
|
|
|
|
|
3,594 |
|
|
|
1,564 |
|
|
|
|
|
|
|
32,561 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Follow-on public offering |
|
|
|
|
|
|
1,380,000 |
|
|
|
55,933 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55,933 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner contribution |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,192 |
|
|
|
|
|
|
|
1,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conversion of subordinated units to common units |
|
|
|
|
|
|
850,672 |
|
|
|
(3,243 |
) |
|
|
(850,672 |
) |
|
|
3,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit-based compensation |
|
|
|
|
|
|
3,000 |
|
|
|
46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions ($2.60 per unit) |
|
|
|
|
|
|
|
|
|
|
(29,423 |
) |
|
|
|
|
|
|
(6,635 |
) |
|
|
(1,845 |
) |
|
|
|
|
|
|
(37,903 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity hedging gains reclassified to earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
478 |
|
|
|
478 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustment in fair value of derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,362 |
) |
|
|
(7,362 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances December 31, 2007 |
|
$ |
10,917 |
|
|
|
12,837,480 |
|
|
$ |
244,520 |
|
|
|
1,701,346 |
|
|
$ |
(6,022 |
) |
|
$ |
4,112 |
|
|
$ |
(6,762 |
) |
|
$ |
246,765 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
748 |
|
|
|
|
|
|
|
34,978 |
|
|
|
|
|
|
|
4,531 |
|
|
|
3,301 |
|
|
|
|
|
|
|
43,558 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions ($2.91 per unit) |
|
|
|
|
|
|
|
|
|
|
(37,357 |
) |
|
|
|
|
|
|
(4,951 |
) |
|
|
(3,409 |
) |
|
|
|
|
|
|
(45,717 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conversion of subordinated units to common units |
|
|
|
|
|
|
850,672 |
|
|
|
(2,754 |
) |
|
|
(850,672 |
) |
|
|
2,754 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit-based compensation |
|
|
|
|
|
|
3,000 |
|
|
|
39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of treasury units |
|
|
|
|
|
|
(3,000 |
) |
|
|
(93 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(93 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustment in fair value of derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,827 |
|
|
|
1,827 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances December 31, 2008 |
|
$ |
11,665 |
|
|
|
13,688,152 |
|
|
$ |
239,333 |
|
|
|
850,674 |
|
|
$ |
(3,688 |
) |
|
$ |
4,004 |
|
|
$ |
(4,935 |
) |
|
$ |
246,379 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
1,664 |
|
|
|
|
|
|
|
16,310 |
|
|
|
|
|
|
|
980 |
|
|
|
3,249 |
|
|
|
|
|
|
|
22,203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner contribution |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,324 |
|
|
|
|
|
|
|
1,324 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units issued in connection with Cross acquisition |
|
|
|
|
|
|
804,721 |
|
|
|
16,523 |
|
|
|
889,444 |
|
|
|
16,434 |
|
|
|
|
|
|
|
|
|
|
|
32,957 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognition of beneficial conversion feature |
|
|
|
|
|
|
|
|
|
|
(111 |
) |
|
|
|
|
|
|
111 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common units |
|
|
|
|
|
|
714,285 |
|
|
|
20,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions ($3.00 per unit) |
|
|
|
|
|
|
|
|
|
|
(41,064 |
) |
|
|
|
|
|
|
(2,552 |
) |
|
|
(3,846 |
) |
|
|
|
|
|
|
(47,462 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conversion of subordinated units to common units |
|
|
|
|
|
|
850,674 |
|
|
|
(5,328 |
) |
|
|
(850,674 |
) |
|
|
5,328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit-based compensation |
|
|
|
|
|
|
3,000 |
|
|
|
98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of treasury units |
|
|
|
|
|
|
(3,000 |
) |
|
|
(78 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(78 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to parent |
|
|
(13,329 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,329 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustment in fair value of derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,859 |
|
|
|
2,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances December 31, 2009 |
|
$ |
|
|
|
|
16,057,832 |
|
|
$ |
245,683 |
|
|
|
889,444 |
|
|
$ |
16,613 |
|
|
$ |
4,731 |
|
|
$ |
(2,076 |
) |
|
$ |
264,951 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Financial information for 2007, 2008 and for the period January 1, 2009 through November
24, 2009 has been revised to include results attributable to the
Cross assets. See Note 2(a)
Principles of Presentation and Consolidation. |
See accompanying notes to consolidated financial statements.
- 82 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
20091 |
|
|
20081 |
|
|
20071 |
|
|
|
(Dollars in thousands) |
|
Net income |
|
$ |
22,203 |
|
|
$ |
43,558 |
|
|
$ |
32,561 |
|
Changes in fair values of commodity cash flow hedges |
|
|
14 |
|
|
|
4,219 |
|
|
|
(3,569 |
) |
Commodity cash flow hedging (gains) losses reclassified to earnings |
|
|
(2,646 |
) |
|
|
3,043 |
|
|
|
478 |
|
Changes in fair value of interest rate cash flow hedges |
|
|
(1,854 |
) |
|
|
(5,435 |
) |
|
|
(3,793 |
) |
Interest rate cash flow hedging losses reclassified to earnings |
|
|
7,345 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
25,062 |
|
|
$ |
45,385 |
|
|
$ |
25,677 |
|
|
|
|
|
|
|
|
|
|
|
1 Financial information for 2007, 2008 and for the period January 1, 2009 through November 24, 2009
has been revised to include results attributable to the
Cross assets. See Note 2(a) Principles of Presentation and Consolidation.
See accompanying notes to consolidated financial statements.
- 83 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
20091 |
|
|
20081 |
|
|
20071 |
|
|
|
(Dollars in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
22,203 |
|
|
$ |
43,558 |
|
|
$ |
32,561 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
39,506 |
|
|
|
34,895 |
|
|
|
26,322 |
|
Amortization of deferred debt issue costs |
|
|
1,689 |
|
|
|
1,120 |
|
|
|
1,233 |
|
Deferred income taxes |
|
|
294 |
|
|
|
2,442 |
|
|
|
680 |
|
Gain on disposition or sale of property, plant, and equipment |
|
|
(4,996 |
) |
|
|
(131 |
) |
|
|
(484 |
) |
Gain on involuntary conversion of property, plant, and equipment |
|
|
(1,017 |
) |
|
|
(65 |
) |
|
|
|
|
Equity in earnings of unconsolidated entities |
|
|
(7,044 |
) |
|
|
(13,224 |
) |
|
|
(10,941 |
) |
Distributions from unconsolidated entities |
|
|
650 |
|
|
|
500 |
|
|
|
1,523 |
|
Distribution in-kind from unconsolidated entities |
|
|
5,826 |
|
|
|
9,725 |
|
|
|
9,337 |
|
Non-cash mark-to-market on derivatives |
|
|
2,526 |
|
|
|
(2,327 |
) |
|
|
3,904 |
|
Other |
|
|
98 |
|
|
|
39 |
|
|
|
47 |
|
Change in current assets and liabilities, excluding effects of
acquisitions and dispositions: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts and other receivables |
|
|
(10,471 |
) |
|
|
19,753 |
|
|
|
(26,992 |
) |
Product exchange receivables |
|
|
2,792 |
|
|
|
3,988 |
|
|
|
(3,422 |
) |
Inventories |
|
|
7,135 |
|
|
|
9,398 |
|
|
|
(18,651 |
) |
Due from affiliates |
|
|
1,560 |
|
|
|
1,770 |
|
|
|
(995 |
) |
Other current assets |
|
|
2,461 |
|
|
|
(992 |
) |
|
|
(1,241 |
) |
Trade and other accounts payable |
|
|
(15,874 |
) |
|
|
(14,904 |
) |
|
|
46,119 |
|
Product exchange payables |
|
|
(2,938 |
) |
|
|
(13,629 |
) |
|
|
9,817 |
|
Due to affiliates |
|
|
4,133 |
|
|
|
5,966 |
|
|
|
(5,583 |
) |
Income taxes payable |
|
|
569 |
|
|
|
(453 |
) |
|
|
(1,225 |
) |
Other accrued liabilities |
|
|
871 |
|
|
|
101 |
|
|
|
793 |
|
Change in other non-current assets and liabilities |
|
|
(2,381 |
) |
|
|
(1,190 |
) |
|
|
(1,593 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
47,592 |
|
|
|
86,340 |
|
|
|
61,209 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Payments for property, plant, and equipment |
|
|
(35,846 |
) |
|
|
(101,450 |
) |
|
|
(85,359 |
) |
Acquisitions, net of cash acquired |
|
|
(327 |
) |
|
|
(5,983 |
) |
|
|
(41,271 |
) |
Proceeds from sale of property, plant, and equipment |
|
|
19,445 |
|
|
|
463 |
|
|
|
1,293 |
|
Insurance proceeds from involuntary conversion of property, plant and equipment |
|
|
2,224 |
|
|
|
1,503 |
|
|
|
|
|
Return of investments from unconsolidated entities |
|
|
877 |
|
|
|
1,225 |
|
|
|
1,952 |
|
Distributions from (contributions to) unconsolidated entities for operations |
|
|
(1,048 |
) |
|
|
(2,379 |
) |
|
|
(6,910 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(14,675 |
) |
|
|
(106,621 |
) |
|
|
(130,295 |
) |
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Payments of long-term debt |
|
|
(431,982 |
) |
|
|
(257,191 |
) |
|
|
(169,024 |
) |
Proceeds from long-term debt |
|
|
433,700 |
|
|
|
327,170 |
|
|
|
219,950 |
|
Net proceeds from follow on public offering |
|
|
|
|
|
|
|
|
|
|
55,933 |
|
General partner contribution |
|
|
1,324 |
|
|
|
|
|
|
|
1,192 |
|
Purchase of treasury units |
|
|
(78 |
) |
|
|
(93 |
) |
|
|
|
|
Proceeds from issuance of common units |
|
|
20,000 |
|
|
|
|
|
|
|
|
|
Payments of debt issuance costs |
|
|
(10,446 |
) |
|
|
(18 |
) |
|
|
(252 |
) |
Cash distributions paid |
|
|
(47,462 |
) |
|
|
(45,717 |
) |
|
|
(37,903 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(34,944 |
) |
|
|
24,151 |
|
|
|
69,896 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase(decrease) in cash |
|
|
(2,027 |
) |
|
|
3,870 |
|
|
|
810 |
|
|
Cash at beginning of period |
|
|
7,983 |
|
|
|
4,113 |
|
|
|
3,303 |
|
|
|
|
|
|
|
|
|
|
|
|
Cash at end of period |
|
$ |
5,956 |
|
|
$ |
7,983 |
|
|
$ |
4,113 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental schedule of non-cash investing and financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of assets under capital lease obligations |
|
$ |
7,764 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common and subordinated units in connection with Cross acquisition |
|
$ |
32,957 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
1 Financial information for 2007, 2008 and for the period January 1, 2009 through November 24, 2009
has been revised to include results attributable to the Cross assets.
See Note 2(a) Principles of Presentation and Consolidation.
See accompanying notes to consolidated financial statements.
- 84 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
(Dollars in Thousands)
(1) ORGANIZATION AND DESCRIPTION OF BUSINESS
Martin Midstream Partners L.P. (the Partnership) is a publicly traded limited partnership
with a diverse set of operations focused primarily in the United Stated Gulf Coast region. Its four
primary business lines include: terminalling and storage services for petroleum products and
by-products, natural gas services, sulfur and sulfur-based products processing, manufacturing,
marketing and distribution and marine transportation services for petroleum products and
by-products.
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 oil and gas exploration and production industry.
The Partnership owns 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. Prism Gas owns a 50% ownership interest in Waskom Gas Processing Company
(Waskom), the Matagorda Offshore Gathering System (Matagorda), Panther Interstate Pipeline
Energy LLC (PIPE), and Bosque County Pipeline (BCP) each accounted for under the equity method
of accounting.
(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 under certain provisions of the Financial
Accounting Standards Board (FASB) Accounting Standards Codification (ASC), 810-10 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 ASC 810-10. No such variable interest entities exist as of December
31, 2009 or 2008.
The Partnership acquired the assets of Cross Oil Refining & Marketing Inc. (Cross) from
Martin Resource Management (Martin Resource Management) in November 2009 as described in Note 5.
The acquisition of the Cross assets was considered a transfer of net assets between entities under
common control. The acquisition of the Cross assets and increase in partners capital for the
common and subordinated units issued in November 2009 are recorded at amounts based on the
historical carrying value of the Cross assets at that date, and the Partnership is required to
revise its historical financial statements to include the activities of the Cross assets as of the
date of common control. Martin Resource Management acquired Cross in November 2006; however, the
activity for the period Cross was owned by Martin Resource Management during 2006 was not
considered significant to the Partnerships consolidated financial statements and has been excluded
from the consolidated financial statements. The Partnerships historical financial statements for
2007, 2008 and the period January 1, 2009 through November 24, 2009 have been revised to reflect
the financial position, cash flows and results of operations attributable to the Cross assets as if
the Partnership owned the Cross assets for these periods. Net income
attributable to the Cross assets for periods prior to the Partnerships acquisition of the assets
is not allocated to the general and limited partners for purposes of calculating net income per
limited partner unit. See Note (2)(o).
(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 exchange products due to
- 85 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
(Dollars in Thousands)
other companies under these agreements at quoted market product prices and the balance of exchange
products due from other companies at the lower of cost or market. Cost is determined using the
first-in, first-out (FIFO) method.
(c) Inventories
Inventories are stated at the lower of cost or market. Cost is determined by using the
first-in, first-out (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. For the Partnerships
tolling agreement, revenue is recognized based on the contracted monthly reservation fee and
throughput volumes moved through the facility. 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 our 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.
Sulfur services Revenues are recognized when the products are delivered, which occurs when
the customer has taken title and has assumed the risks and rewards of ownership based on specific
contract terms at either the shipping or delivery point.
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.
(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 certain provisions of ASC
350-20, related to goodwill, 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 ASC 323-10, which relates to 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.
The Partnerships Prism Gas subsidiary owns an unconsolidated 50% interest in Waskom,
Matagorda, and PIPE. As a result, these assets are accounted for by the equity method.
(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.
Equipment under capital leases is stated at the present value of minimum lease payments less
accumulated amortization. Equipment under capital leases is amortized straight line over the
estimated useful life of the asset.
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.
- 86 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
(Dollars in Thousands)
(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 certain provisions of ASC 350-20. Intangible assets with estimated useful lives
are amortized over their respective estimated useful lives to their estimated residual values, and
reviewed for impairment under certain provisions of ASC 360-10 related to accounting for impairment
or disposal of long-lived assets. Other intangible assets primarily consist of covenants
not-to-compete and contracts obtained through business combinations and are being amortized over
the life of the respective agreements.
Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if
events or circumstances indicate there may be impairment. The Partnership is required to identify
their reporting units and determine the carrying value of each reporting unit by assigning the
assets and liabilities, including the existing goodwill and intangible assets. Goodwill is
assigned to reporting units at the date the goodwill is initially recorded. Once goodwill has been
assigned to reporting units, it no longer retains its association with a particular acquisition,
and all of the activities within a reporting unit, whether acquired or organically grown, are
available to support value of the goodwill.
The Partnership performed the annual impairment tests as of September 30, 2009, September 30,
2008 and September 30, 2007, respectively. In performing such tests, it was determined that there
were four reporting units which contained goodwill. These reporting units were in each of the
four reporting segments: terminalling, natural gas services, marine transportation, and sulfur
services. The estimated fair value of the reporting units with goodwill were developed using the
guideline public company method, the guideline transaction method, and the discounted cash flow
(DCF) method using observable market data where available. To the extent the carrying amount of
a reporting unit exceeds the fair value of the reporting unit, the Partnership 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. At September 30, 2009, 2008 and 2007 the estimated fair value of each of
the four reporting units was in excess of its carrying value, which indicates no impairment existed.
As a result of the deterioration in the overall stock market subsequent to September 30, 2008
and the decline in the Partnerships unit price, the Partnership reviewed specific factors, as
outlined under certain provisions of ASC 350-20, to determine if the Partnership had a trigging
event that required it to test the goodwill for impairment as of December 31, 2008. These factors
included whether there have been any significant fundamental changes since the annual impairment
test to (i) the Partnership as a whole or to the reporting units, including regulatory changes,
(ii) the level of operating cash flows, (iii) the expectation of future levels of operating cash
flows, (iv) the executive management team, and (v) the carrying value of the other long-lived
assets. While these factors did not indicate a triggering event occurred, the Partnerships unit
price fell to a point by December 31, 2008 that resulted in the total market capitalization being
less than the partners equity. The Partnership determined this to be a triggering event requiring
the Partnership to perform an impairment test as of December 31, 2008. As a result of the goodwill
impairment test for each of the four reporting units as of December 31, 2008, no impairment was
determined to exist.
(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.
In connection with the amendment and expansion of the Partnerships multi-bank credit facility on
December 28, 2007, it incurred debt issuance costs of $252. In connection with the amendment and
expansion of the Partnerships multi-bank credit facility in December, 2009, it incurred debt
issuance costs of $10,383. Due to a reduction in the number of lenders under the Partnerships
multi-bank credit agreement, $495 of the existing debt issuance costs were determined not to have
continuing benefit and were expensed during 2009. 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 term of the revised debt arrangement.
Amortization of debt issuance cost, which is included in interest expense for the years ended
December 31, 2009, 2008 and 2007, totaled $1,689, $1,120, and $1,233, respectively, and accumulated
amortization amounted to $105 and $5,445 at December 31, 2009 and 2008, respectively. The
unamortized balance of debt issuance costs, classified as other assets amounted to $10,885 and
$2,086 at December 31, 2009 and 2008, respectively.
- 87 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
(Dollars in Thousands)
(i) Impairment of Long-Lived Assets
In accordance with ASC 360-10, 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. The Partnership has not identified any triggering events
in 2009, 2008 or 2007 that would require an assessment for impairment of long-lived assets.
(j) Asset Retirement Obligation
Under ASC 410-20, which relates to 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. The Partnerships fixed assets include land, buildings,
transportation equipment, storage equipment, marine vessels and operating equipment.
The transportation equipment includes pipeline systems. The Partnership transports NGLs
through the pipeline system and gathering system. The Partnership also gathers natural gas from
wells owned by producers and delivers 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 certain provisions of ASC 815-10 related to 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.
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,
2009, 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 accumulated other
comprehensive income as a component of equity.
- 88 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
(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 ASC 815-10, 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 August 2009, the Partnership issued 1,000 restricted common units to each of its three
independent, non-employee directors under its long-term incentive plan from treasury shares
purchased by the Partnership in the open market for $77. These units vest in 25% increments
beginning in January 2010 and will be fully vested in January 2013.
In May 2008, the Partnership issued 1,000 restricted common units to each of its three
independent, non-employee directors under its long-term incentive plan from treasury shares
purchased by the Partnership in the open market for $93. These units vest in 25% increments
beginning in January 2009 and will be fully vested in January 2012.
In May 2007, the Partnership issued 1,000 restricted common units to each of its three
independent, non-employee directors under its long-term incentive plan. These units vest in 25%
increments beginning in January 2008 and will be fully vested in January 2011.
In January 2006, the Partnership issued 1,000 restricted common 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 certain provisions of FASB ASC 505-50-55
related to equity-based payments to non-employees. The cost resulting from the share-based payment
transactions was $98, $39, and $46 for the years ended December 31, 2009, 2008 and 2007,
respectively. The Partnerships general partner contributed cash of $2 in May 2007 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, 2009, 2008 and 2007, the general partner
received $2,896, $2,495, and $1,087 in incentive distributions.
(o) Net Income per Unit
In March 2008, the FASB amended the provisions of ASC 260-10 related to earnings per share,
which addresses the application of the two-class method in determining income per unit for master
limited partnerships having multiple classes of securities that may participate in partnership
distributions accounted for as equity
distributions. To the extent the partnership agreement does not explicitly limit distributions
to the general partner, any earnings in excess of distributions are to be allocated to the general
partner and limited partners utilizing the distribution formula for available cash specified in the
partnership agreement. When current period distributions are in excess of earnings, the excess
distributions for the period are to be allocated to the general partner and limited partners based
on their respective sharing of losses specified in the partnership agreement. ASC 260-10 is to be
- 89 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
(Dollars in Thousands)
applied retrospectively for all financial statements presented and is effective for financial
statements issued for fiscal years beginning after December 15, 2008, and interim periods within
those fiscal years.
The Partnership adopted the amended provisions of ASC 260-10 on January 1, 2009. Adoption did
not impact the Partnerships computation of earnings per limited partner unit as cash distributions
exceeded earnings for the years ended December 31, 2009, 2008 and 2007, respectively, and the IDRs
do not share in losses under the partnership agreement. In the event the Partnerships earnings
exceed cash distributions, ASC 260-10 will have an impact on the computation of the Partnerships
earnings per limited partner unit. The Partnership agreement does not explicitly limit
distributions to the general partner; therefore, any earnings in excess of distributions are to be
allocated to the general partner and limited partners utilizing the distribution formula for
available cash specified in the Partnership agreement. For years ended December 31, 2009, 2008 and
2007, the general partners interest in net income, including the IDRs, represents distributions
declared after period end on behalf of the general partner interest and IDRs less the allocated
excess of distributions over earnings for the periods.
General and limited partner interest in net income includes only net income of the Cross
assets since the date of acquisition. Accordingly, net income of the Partnership is adjusted to
remove the net income attributable to the Cross assets prior to the date of acquisition and such
income is allocated to the Parent. The recognition of the beneficial conversion feature for the
period is considered a deemed distribution to the subordinated unit holders and reduces net income
available to common limited partners in computing net income per unit.
For purposes of computing diluted net income per unit, the Partnership uses the more dilutive
of the two-class and if-converted methods. Under the if-converted method, the beneficial
conversion feature is added back to net income available to common limited partners, the
weighted-average number of subordinated units outstanding for the period is added to the
weighted-average number of common units outstanding for purposes of computing basic net income per
unit and the resulting amount is compared to the diluted net income per unit computed using the
two-class method.
The following table reconciles net income to limited partners interest in net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Net income attributable to Martin Midstream Partners L. P |
|
$ |
22,203 |
|
|
$ |
43,558 |
|
|
$ |
32,561 |
|
Less pre-acquisition income allocated to Parent |
|
|
1,664 |
|
|
|
748 |
|
|
|
7,622 |
|
Less general partners interest in net income: |
|
|
|
|
|
|
|
|
|
|
|
|
Distributions payable on behalf of IDRs |
|
|
2,896 |
|
|
|
2,495 |
|
|
|
1,087 |
|
Distributions payable on behalf of general partner
interest |
|
|
949 |
|
|
|
914 |
|
|
|
758 |
|
Distributions payable to the general partner
interest in excess of earnings allocable to the general
partner interest |
|
|
(596 |
) |
|
|
(108 |
) |
|
|
(281 |
) |
Less beneficial conversion feature |
|
|
111 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
17,179 |
|
|
$ |
39,509 |
|
|
$ |
23,375 |
|
|
|
|
|
|
|
|
|
|
|
The weighted average units outstanding for basic net income per unit were 14,680,807,
14,529,826, and 14,018,799 for years ended December 31, 2009, 2008 and 2007, respectively. For
diluted net income per unit, the weighted average units outstanding were increased by 3,968, 4,896
and 3,746 units for the years ended December 31, 2009, 2008 and 2007, respectively, due to the
dilutive effect of restricted units granted under the Partnerships long-term incentive plan.
(p) 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. Under the omnibus agreement, we are required to reimburse Martin Resource Management for
indirect general and administrative and corporate overhead expenses. The amount of this
- 90 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
(Dollars in Thousands)
reimbursement was capped at $2,000 through November 1, 2007 when the cap expired. For the years
ended December 31, 2009, 2008 and 2007, the Conflicts Committee of our general partner approved
reimbursement amounts of $3,542, $2,896, and $1,493, respectively, reflecting our allocable share
of such expenses. The Conflicts Committee will review and approve future adjustments in the
reimbursement amount for indirect expenses, if any, annually.
(q) Environmental Liabilities and Litigation
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. Recoveries of environmental remediation costs from other
parties are recorded as assets when their receipt is deemed probable.
(r) Accounts Receivable and 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.
(s) 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.
(t) Income Taxes
With respect to the Partnerships taxable subsidiary (Woodlawn Pipeline Co., Inc.) and the
Cross assets prior to the date of acquisition (see Notes 2(a) and 5(b)), income taxes are accounted
for under the asset and liability method. Deferred tax assets and liabilities are recognized for
the future tax consequences attributable to differences between the financial statement carrying
amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable income in the years
in which those temporary differences are expected to be recovered or settled. The effect on
deferred tax assets and liabilities of a change in tax rates is recognized in income in the period
that includes the enactment date.
(3) FAIR VALUE MEASUREMENTS
During the first quarter of 2008, the Partnership adopted certain provisions of ASC 820
related to fair value measurements and disclosures, which established a framework for measuring
fair value and expanded disclosures about fair value measurements. The adoption of this guidance
had no impact on the Partnerships financial position or results of operations.
ASC 820 applies to all assets and liabilities that are being measured and reported on a fair
value basis. This statement enables the reader of the financial statements to assess the inputs
used to develop those measurements by establishing a hierarchy for ranking the quality and
reliability of the information used to determine fair values. ASC 820 establishes a three-tier fair
value hierarchy, which prioritizes the inputs used in measuring fair value of each asset and
liability carried at fair value into one of the following categories:
Level 1: Quoted market prices in active markets for identical assets or liabilities.
Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.
Level 3: Unobservable inputs that are not corroborated by market data.
- 91 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
The Partnerships derivative instruments, which consist of commodity and interest rate swaps,
are required to be measured at fair value on a recurring basis. The fair value of the Partnerships
derivative instruments is determined based on inputs that are readily available in public markets
or can be derived from information available in publicly quoted markets, which is considered Level
2. Refer to Note 13 for further information on the Partnerships derivative instruments and hedging
activities.
The following items are measured at fair value on a recurring basis subject to the
disclosure requirements of ASC 820 at December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at Reporting Date Using |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
|
Active Markets for |
|
|
Significant Other |
|
|
Unobservable |
|
|
|
|
|
|
|
Identical Assets |
|
|
Observable Inputs |
|
|
Inputs |
|
|
|
December 31, |
|
|
|
|
|
|
|
|
|
|
Description |
|
2009 |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivatives |
|
$ |
1,286 |
|
|
$ |
|
|
|
$ |
1,286 |
|
|
$ |
|
|
Commodity derivatives |
|
|
586 |
|
|
|
|
|
|
|
586 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,872 |
|
|
$ |
|
|
|
$ |
1,872 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivatives |
|
$ |
6,611 |
|
|
$ |
|
|
|
$ |
6,611 |
|
|
$ |
|
|
Commodity derivatives |
|
|
616 |
|
|
|
|
|
|
|
616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
$ |
7,227 |
|
|
$ |
|
|
|
$ |
7,227 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following items are measured at fair value on a recurring basis subject to the
disclosure requirements of ASC 820 at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at Reporting Date Using |
|
|
|
|
|
|
Quoted Prices in |
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
Active Markets for |
|
|
Significant Other |
|
|
|
Unobservable |
|
|
|
|
|
|
Identical Assets |
|
|
Observable Inputs |
|
|
|
Inputs |
|
|
December 31, |
|
|
|
|
|
|
|
|
|
Description |
|
2008 |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
|
(Level 3) |
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$ |
5,092 |
|
$ |
|
|
|
$ |
5,092 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivatives
|
|
$ |
10,780 |
|
$ |
|
|
|
$ |
10,780 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
- 92 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
FASB ASC 825-10-65, 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. |
(4) RECENT ACCOUNTING PRONOUNCEMENTS
In April 2009, the FASB amended the provisions of ASC 805-10, 805-20 and 805-30 related to
accounting for assets acquired and liabilities assumed in a business combination that arise from
contingencies, to amend the provisions related to the initial recognition and measurement,
subsequent measurement and disclosure of assets and liabilities arising from contingencies in a
business combination under ASC. Under the new guidance, assets acquired and liabilities assumed in
a business combination that arise from contingencies should be recognized at fair value on the
acquisition date if fair value can be determined during the measurement period. If fair value
cannot be determined, companies should typically account for the acquired contingencies using
existing guidance. The Partnership adopted this guidance on January 1, 2009. As the provisions of
this guidance are applied prospectively to business combinations with an acquisition date on or
after the guidance became effective, the impact to the Partnership cannot be determined until the
transactions occur. No such transactions have occurred during 2009.
In March 2008, the FASB amended the provisions of ASC 260-10 related to earnings per share,
which addresses the application of the two-class method in determining income per unit for master
limited partnerships having multiple classes of securities that may participate in partnership
distributions. ASC 260-10 is to be applied retrospectively for all financial statements presented
and is effective for financial statements issued for fiscal years beginning after December 15,
2008, and interim periods within those fiscal years. The Partnership adopted this guidance on
January 1, 2009. See Note 1(o) for more information.
In March 2008, FASB amended the provisions of ASC 815-10-65 related to disclosures about
derivative instruments and hedging activities, which requires enhanced disclosures concerning
(1) the manner in which an entity uses derivatives (and the reasons it uses them), (2) the manner
in which derivatives and related hedged items are accounted for and (3) the effects that
derivatives and related hedged items have on an entitys financial position, financial performance
and cash flows. ASC 815-10-65 is effective for financial statements issued for fiscal years and
interim periods beginning on or after November 15, 2008. The Partnership adopted this guidance on
January 1, 2009, and the adoption did not have a material impact on the Partnerships financial
position or results of operations.
In December 2007, FASB amended the provisions of ASC 805-10-65 related to business
combinations, which establishes principles and requirements for how an acquiror in a business
combination (1) recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes
and measures the goodwill acquired in the business combination or a gain from a bargain purchase
price and (3) determines what information to disclose to enable users of the consolidated financial
statements to evaluate the nature and financial effects of the business combination. ASC 805-10-65
applies prospectively to business combinations for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after December 15, 2008. The
Partnership adopted certain provisions of ASC 805-10-65 on January 1, 2009. The application of ASC
805-10-65 will cause management to evaluate future transactions under different conditions than
previously completed significant acquisitions, particularly related to the near-term and long-term
economic impact of expensing transaction costs. No such transactions have occurred during 2009.
- 93 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(5) ACQUISITIONS
(a) East Harrison Pipeline System.
In December 2009, the Partnership acquired, through Prism Gas, from Woodward Partners, Ltd.
6.45 miles of gathering pipeline referred to as the East Harrison Pipeline System for $327. The
system currently transports approximately 500 Mcfd of natural gas under various transport contracts
which provide for a minimum monthly fee.
(b) Cross assets.
In November 2009, the Partnership closed a transaction with Martin Resource Management
(Martin Resource Management) and Cross Refining & Marketing, Inc. (Cross), a wholly owned
subsidiary of Martin Resource Management, in which the Partnership acquired certain specialty
lubricants processing assets (Assets) from Cross for total consideration of $44,878 (the
Contribution). As consideration for the Contribution, the Partnership issued 804,721 common units
and 889,444 subordinated units to Martin Resource Management at a price of $27.96 and $25.16 per
limited partner unit, respectively. In connection with the Contribution, the General Partner made a
capital contribution of $918 in cash to the Partnership in order to maintain its 2% general partner
interest.
The Partnership accounted for the Cross acquisition as a transfer of net assets between
entities under common control pursuant to the provisions of FASB ASC 850. The Cross assets were
recorded at $32,957, which represents the amounts reflected in Martin Resource Managements
historical consolidated financial statements. The difference between the purchase price and Martin
Resource Managements carrying value of the combined net assets acquired and liabilities assumed
was recorded as an adjustment to partners capital.
(c) Stanolind Assets.
In January 2008, the Partnership acquired 7.8 acres of land, a deep water dock and two
sulfuric acid tanks at its Stanolind terminal in Beaumont, Texas from Martin Resource Management
for $5,983 which was allocated to property, plant and equipment. Martin Resource Management entered
into a lease agreement with the Partnership for use of the sulfuric acid tanks. In connection with
the acquisition, the Partnership borrowed approximately $6,000 under its credit facility.
(6) ISSUANCE OF COMMON UNITS
In addition to the units referred to in Note 5(b) above, in November 2009, the Partnership
closed a private equity sale with Martin Resource Management, under which Martin Resource
Management invested $20,000 in cash in the Partnership in exchange for 714,285 common units of the
Partnership. In connection with the issuance of these common units, the General Partner made a
capital contribution to the Partnership of $408 in order to maintain its 2% general partner
interest in the Partnership.
(7) INVENTORIES
Components of inventories at December 31, 2009 and 2008 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Natural gas liquids |
|
$ |
15,002 |
|
|
$ |
10,530 |
|
Sulfur |
|
|
2,540 |
|
|
|
6,522 |
|
Sulfur Based Products |
|
|
10,053 |
|
|
|
14,879 |
|
Lubricants |
|
|
4,684 |
|
|
|
8,110 |
|
Other |
|
|
3,231 |
|
|
|
2,713 |
|
|
|
|
|
|
|
|
|
|
$ |
35,510 |
|
|
$ |
42,754 |
|
|
|
|
|
|
|
|
(8) PROPERTY, PLANT AND EQUIPMENT
At December 31, 2009 and 2008, property, plant, and equipment consisted of the following:
- 94 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciable Lives |
|
|
2009 |
|
|
2008 |
|
Land |
|
|
|
|
|
$ |
15,759 |
|
|
$ |
16,899 |
|
Improvements to land and buildings |
|
10-25 years |
|
|
48,704 |
|
|
|
47,237 |
|
Transportation equipment |
|
3-7 years |
|
|
1,786 |
|
|
|
2,443 |
|
Storage equipment |
|
5-20 years |
|
|
59,597 |
|
|
|
52,296 |
|
Marine vessels |
|
4-25 years |
|
|
210,593 |
|
|
|
200,473 |
|
Operating equipment |
|
3-20 years |
|
|
238,956 |
|
|
|
211,934 |
|
Furniture, fixtures and other equipment |
|
3-20 years |
|
|
1,646 |
|
|
|
2,168 |
|
Construction in progress |
|
|
|
|
|
|
6,995 |
|
|
|
43,158 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
584,036 |
|
|
$ |
576,608 |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation expense for the year ended December 31, 2009, 2008, and 2007 was $37,027, $33,060, and
$24,780, respectively, which includes amortization of fixed assets acquired under capital lease
obligations of $116, $0, and $0 for 2009, 2008, and 2007; respectively. Gross assets under capital
leases were $7,764 and $0 at December 31, 2009 and 2008. Accumulated amortization associated with
capital leases was $116 and $0 at December 31, 2009 and 2008.
(9) GOODWILL AND OTHER INTANGIBLE ASSETS
At December 31, 2009 and 2008, goodwill balances consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Carrying amount of goodwill: |
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
883 |
|
|
$ |
1,020 |
|
Natural gas services |
|
|
29,010 |
|
|
|
29,010 |
|
Sulfur services |
|
|
5,349 |
|
|
|
5,349 |
|
Marine transportation |
|
|
2,026 |
|
|
|
2,026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
37,268 |
|
|
$ |
37,405 |
|
|
|
|
|
|
|
|
In conjunction with the sale of the Partnerships railcar unloading facility at Mont Belvieu,
$137 of goodwill was allocated from the terminalling and storage segment to the carrying value of
the disposed assets in accordance with certain provisions of ASC 350-20 related to goodwill. See
Note 16 for more information regarding the disposal of the Mont Belvieu facility.
At December 31, 2009 and 2008, covenants not-to-compete balances consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Covenants not-to-compete: |
|
|
|
|
|
|
|
|
Terminalling and storage |
|
$ |
1,928 |
|
|
$ |
1,956 |
|
Natural gas services |
|
|
|
|
|
|
40 |
|
Sulfur services |
|
|
100 |
|
|
|
790 |
|
|
|
|
|
|
|
|
|
|
|
2,028 |
|
|
|
2,786 |
|
Less accumulated amortization |
|
|
1,324 |
|
|
|
1,572 |
|
|
|
|
|
|
|
|
|
|
$ |
704 |
|
|
$ |
1,214 |
|
|
|
|
|
|
|
|
Intangible assets consists of the covenants not-to-compete listed above, customer contracts
associated with gathering and processing assets and a transportation contract associated with the
residue gas pipeline. The covenants not-to-compete and contracts are presented in the consolidated
balance sheets as other assets, net. Aggregate amortization expense for amortizing intangible
assets was $2,479, $1,833, and $1,543 for the years ended December 31, 2009, 2008, and 2007,
respectively. Estimated amortization expenses for the years subsequent to December 31, 2009 are as
follows: 2010 $600; 2011 $516; 2012 $512; 2013 $514; 2014 $435; subsequent years
-$1,279.
- 95 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(10) 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. Certain of our marine
vessels have been acquired under capital leases.
The Partnerships future minimum lease obligations as of December 31, 2009 consist of the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital |
|
Fiscal year |
|
Operating Leases |
|
|
Leases |
|
2010 |
|
$ |
4,233 |
|
|
$ |
1,102 |
|
2011 |
|
|
4,036 |
|
|
|
1,102 |
|
2012 |
|
|
3,205 |
|
|
|
1,117 |
|
2013 |
|
|
2,457 |
|
|
|
1,135 |
|
2014 |
|
|
2,176 |
|
|
|
1,147 |
|
Thereafter |
|
|
6,975 |
|
|
|
6,751 |
|
|
|
|
|
|
|
|
Total |
|
|
23,082 |
|
|
|
12,354 |
|
Less amounts representing interest costs |
|
|
|
|
|
|
6,071 |
|
|
|
|
|
|
|
|
Present value of net minimum capital lease payments |
|
|
|
|
|
|
6,283 |
|
Less current installments |
|
|
|
|
|
|
111 |
|
|
|
|
|
|
|
|
Present value of net minimum capital lease payments, excluding current installments |
|
$ |
|
|
|
$ |
6,172 |
|
|
|
|
|
|
|
|
Rent expense for operating leases for the years ended December 31, 2009, 2008 and 2007 was
$11,158, $12,527 and $12,492; respectively. The amount recognized in interest expense for capital
leases was $250, $0, and $0 for the years ended December 31, 2009, 2008 and 2007; respectively.
(11) INVESTMENT IN UNCONSOLIDATED ENTITIES AND JOINT VENTURES
The Partnerships Prism Gas Systems I, L.P. (Prism Gas) subsidiary 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.
On June 30, 2006, 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). The lease contract terminated in June 2009, and, as such, the investment was fully
amortized as of June 30, 2009.
In accounting for the acquisition of the interests in Waskom, Matagorda and PIPE, 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 years ended December 31, 2009, 2008 and 2007, respectively,
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 $9,497, $10,091
and $10,685 at December 31, 2009, 2008 and 2007, respectively. The equity-method goodwill is not
amortized; however, it is analyzed for impairment annually or if changes in circumstance indicate
that a potential impairment exists. No impairment was recorded in 2009, 2008 or 2007.
As a partner in Waskom, the Partnership receives distributions in kind of natural gas liquids
(NGLs) that are retained according to Waskoms contracts with certain producers. The NGLs are
valued at prevailing market prices. In
- 96 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
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, 2007 |
|
$ |
70,237 |
|
|
$ |
1,582 |
|
|
$ |
3,693 |
|
|
$ |
178 |
|
|
$ |
75,690 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions in kind |
|
|
(9,725 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,725 |
) |
Return on investments |
|
|
(500 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(500 |
) |
Contributions to (distributions from) unconsolidated entities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash contributions |
|
|
1,250 |
|
|
|
129 |
|
|
|
|
|
|
|
80 |
|
|
|
1,459 |
|
Contributions to (distributions from) unconsolidated entities for operations |
|
|
920 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
920 |
|
Return of investments |
|
|
(300 |
) |
|
|
(180 |
) |
|
|
(745 |
) |
|
|
|
|
|
|
(1,225 |
) |
Equity in earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings from operations |
|
|
13,646 |
|
|
|
(302 |
) |
|
|
640 |
|
|
|
(166 |
) |
|
|
13,818 |
|
Amortization of excess investment |
|
|
(550 |
) |
|
|
(15 |
) |
|
|
(29 |
) |
|
|
|
|
|
|
(594 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in unconsolidated entities, December 31, 2008 |
|
$ |
74,978 |
|
|
$ |
1,214 |
|
|
$ |
3,559 |
|
|
$ |
92 |
|
|
$ |
79,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Waskom |
|
|
PIPE |
|
|
Matagorda |
|
|
BCP |
|
|
Total |
|
Investment in unconsolidated entities, December 31, 2008 |
|
$ |
74,978 |
|
|
$ |
1,214 |
|
|
$ |
3,559 |
|
|
|