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Mark One
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Annual Report Pursuant to Section 13 or 15(d) of the | |
| x | Securities Exchange Act of 1934 | |
| For the fiscal year ended December 31, 2011 |
| o | Transition Report Pursuant to Section 13 or 15(d) of the | |
| Securities Exchange Act of 1934 |
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Delaware
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05-0527861
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State or other jurisdiction of incorporation or organization
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(I.R.S. Employer Identification No.)
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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 Global Select Market
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Large accelerated filer
o
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Accelerated filer
x
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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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Page
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PART I
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1
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Item 1.
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26
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Item 1A.
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45
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Item 1B.
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45
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Item 2.
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45
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Item 3.
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45
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Item 4.
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44
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PART II
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45
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Item 5.
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45
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Item 6.
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46
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Item 7.
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48
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Item 8.
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75
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Item 9.
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116
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Item 9A.
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116
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Item 9B.
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116
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PART III
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117
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Item 10.
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117
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Item 11.
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122
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Item 12.
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131
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Item 13.
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136
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Item 14
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143
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PART IV
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144
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Item 15.
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144
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·
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Terminalling and storage services for petroleum products and by-products;
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·
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Natural gas services;
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·
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Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution; and
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·
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Marine transportation services for petroleum products and by-products.
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·
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Terminalling and Storage.
We own or operate 27 marine shore based terminal facilities and 12 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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·
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Natural Gas Services.
Through our acquisitions of our subsidiaries, Prism Gas Systems I, L.P. (“Prism Gas”) and Woodlawn Pipeline Co., Inc. (“Woodlawn”), and acquisition of the Darco Gathering System, the Harrison Gathering System and the East Harrison Pipeline System, we have ownership interests in over 719 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 320 MMcfd capacity natural gas processing plant located in East Texas. In 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 2.6 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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·
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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. In March 2011, we completed the construction of an ammonium sulfate production plant in Plainview, Texas which takes sulfuric acid from our sulfuric acid plant and processes in into ammonium sulfate. 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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·
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Marine Transportation.
We utilize a fleet of 41 inland marine tank barges, 20 inland push boats and four offshore tug barge units that transport petroleum products and by-products domestically, coastwise and along the inland waterways system, and internationally, including the Caribbean, Central America, and South America. 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 16 years as of March 5, 2012. 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.
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·
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Several gas producers in our areas of operation have reduced drilling activity as compared to their previous levels of activity demonstrating a bias toward newly found shale plays in other areas.
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·
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Coupled with the general decline in drilling activity are the federal government’s enhanced safety regulations and inspection requirements as it relates to deep-water drilling in the Gulf of Mexico. In October 2010, the United States Government lifted the moratorium on deep water permitting and drilling. These enhanced safety regulations and inspection requirements of the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) continue to provide uncertainty surrounding the requirements for and pace of issuance of permits on the Gulf of Mexico Outer Continental Shelf (OCS). Although permits began to be issued by the BOEMRE again during first quarter 2011, they have not been approved in a timely manner consistent with pre-BP/Macondo spill levels.
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·
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There has been a decline in the demand for certain marine transportation services based on decreased refinery production resulting in an oversupply of equipment. This was partially offset in 2010 by the marine transportation services required in the efforts to clean up the BP oil spill in the Gulf of Mexico.
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·
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We continue to adjust our business strategy 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. Over the past year we have had access to the capital markets and have appropriate levels of liquidity and operating cash flows to adequately fund our growth. Our goal over the next two years will be to increase growth capital expenditures primarily in our Terminalling and Storage and Sulfur Services segments.
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·
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We continue to evaluate opportunities to enter into interest rate and commodity hedging transactions. We believe these transactions can beneficially remove risks associated with interest rate and commodity price volatility.
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·
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During 2011, we have experienced positive changing market dynamics in certain segments including activity associated with the rapidly developing basins such as the Eagle Ford shale.
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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.
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·
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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, storing or marketing a limited range of products and services. We believe expanding our customer base and our service and product offerings to existing customers is an efficient and cost effective method of achieving organic growth in revenues and cash flow. We believe significant opportunities exist to expand our customer base and provide additional services and products to existing customers.
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·
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Pursue Strategic Acquisitions.
We continually monitor the marketplace to identify and pursue accretive acquisitions that expand the services and products we offer or that expand our geographic presence. After acquiring other businesses, we will attempt to utilize our industry knowledge, network of customers and suppliers and strategic asset base to operate the acquired businesses more efficiently and competitively, thereby increasing revenues and cash flow. We believe that our diversified base of operations provides multiple platforms for strategic growth through acquisitions.
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·
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Pursue Strategic Alliances.
Many of our larger customers, which include major integrated energy companies, have established strategic alliances with midstream service providers such as us to address logistical and transportation problems or achieve operational synergies. We intend to pursue strategic alliances with such customers in the future, pursuing growth opportunities.
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·
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Expand Geographically.
We work to identify and assess other attractive geographic markets for our services and products based on the market dynamics and the cost associated with penetration of such markets. We typically enter a new market through an acquisition or by securing at least one major customer or supplier and then dedicating or purchasing assets for operation in the new market. Once in a new territory, we seek to expand our operations within this new territory both by targeting new customers and by selling additional services and products to our original customers in the territory.
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·
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Asset Base and Integrated Distribution Network.
We operate a diversified asset base that 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 a complementary portfolio of transportation, terminalling, distribution and other midstream services for petroleum products and by-products.
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Strategically Located Assets.
We are one of the largest operators of marine service shore-based terminals in the United States Gulf Coast region providing broad geographic coverage and distribution capability of our products and services to our customers. Our natural gas gathering and processing and storage assets are focused in areas that continue to experience high levels of drilling activity. In addition, our natural gas transmission and storage assets are located in areas of high customer demand for such services. Finally, many of our Sulfur Services asserts are strategically located to source sulfur from the largest refinery sources in the United States.
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·
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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 a variety of specialty, products, including ammonia, molten sulfur and asphalt. Some of these specialty products require treatment across a wide range of temperatures ranging between approximately -30 to +275 degrees Fahrenheit to remain in liquid form. We believe these capabilities help us enhance relationships with our customers by offering them services to handle their unique product requirements.
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Strong Industry Reputation and Established Relationships with Suppliers and Customers.
We believe we have established a reputation in our industry as a reliable and cost-effective supplier of services to our customers and have a track record of safe, efficient operation of our facilities. Our management has also established long-term relationships with many of our suppliers and customers. We believe we benefit from our management’s 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 seven times for $434.3 million in total net proceeds, including capital contributions from our general partner. In addition, we have accessed the public debt market through the issuance of senior notes for $200.0 million. We have also occasionally issued units to Martin Resource Management in exchange for cash or assets.
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·
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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 direct exposure to commodity price fluctuations through swaps for crude oil, natural gas and natural gas liquids. As of December 31, 2011 and March 5, 2012, Prism Gas has hedged approximately 34% of its commodity risk by volume for 2012.
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·
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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. Our management team has a successful track record of creating internal growth and completing acquisitions. We believe our management team’s experience and familiarity with our industry and businesses are important assets that assist us in implementing our business strategies.
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| Terminal | Location |
Acres
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Tanks
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Aggregate
Capacity
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||||
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Pelican Island
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Galveston, Texas
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51.3
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16
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88,000 Bbls.
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||||
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Harbor Island(1)
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Harbor Island, Texas
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25.5
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12
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31,000 Bbls.
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||||
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Freeport
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Freeport, Texas
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17.8
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2
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8,300 Bbls.
|
||||
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Port O’Connor(2)
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Port O’Connor, Texas
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22.8
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8
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7,000 Bbls.
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||||
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Sabine Pass(3)
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Sabine Pass, Texas
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23.1
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8
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17,500 Bbls.
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||||
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Cameron “East”(4)
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Cameron, Louisiana
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34.3
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12
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34,000 Bbls.
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||||
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Cameron “West”(5)
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Cameron, Louisiana
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16.9
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5
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16,500 Bbls.
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||||
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Venice (6)
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Venice, Louisiana
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2.8
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2
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14,000 Bbls.
|
||||
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Theodore
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Theodore, Alabama
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14.0
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19
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20,000 Bbls.
|
||||
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Pascagoula
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Pascagoula, Mississippi
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29.0
|
3
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10,500 Bbls.
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||||
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Amelia-2 (7)(8)
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Amelia, Louisiana
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4.0
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12
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13,000 Bbls.
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||||
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Cameron-7 (7)(9)
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Cameron, Louisiana
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8.0
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1
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15,000 Bbls.
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||||
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Cameron-8 (7)(10)
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Cameron, Louisiana
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3.0
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6
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32,000 Bbls.
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||||
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Intracoastal City-2 (7)(11)
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Intracoastal City, Louisiana
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10.0
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7
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12,500 Bbls.
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||||
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Fourchon-15 (7)(12)
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Fourchon, Louisiana
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8.0
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33
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16,500 Bbls.
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(1)
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A portion of this terminal is located on land owned by a third party and leased under a lease that expires in January 2015.
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(2)
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This terminal is located on land owned by a third party and leased under a lease that expires in March 2014.
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(3)
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A portion of this terminal is located on land owned by a third party and leased under a lease that expires in September 2036.
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(4)
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This terminal is located on land owned by third parties and leased under a lease that expires in March 2022.
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(5)
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This terminal is located on land owned by a third party and leased under a lease that expires in February 2013.
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(6)
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This terminal is located on land owned by a third party and leased under a sublease agreement that expires in August 2012.
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(7)
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These terminals were acquired from Martin Resource Management on January 31, 2011. |
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(8)
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This terminal is located on land owned by a third party and leased under a lease that expires in August 2012 and can be extended by us through August 2018.
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(9)
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This terminal is located on land owned by a third party and leased under a lease that expires in July 2012 and can be extended by us through July 2017.
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(10)
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This terminal is located on land owned by a third party and leased under a lease that expires in July 2016 and can be extended by us through July 2036.
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| (11) |
This terminal is located on land owned by a third party and leased under a lease that expires in December 2015 and can be extended by us through December 2025.
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| (12) |
This terminal is located on land owned by a third party and leased under a lease that expires in December 2013 and can be extended by us through December 2033.
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| Terminal | Location | Tanks | Aggregate Capacity | |||
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Amelia
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Amelia, Louisiana
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17
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15,000 Bbls.
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Berwick(1)
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Berwick, Louisiana
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2
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25,000 Bbls.
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Intracoastal City(2)(3)
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Intracoastal City, Louisiana
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15
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30,500 Bbls.
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Fourchon(4)
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Fourchon, Louisiana
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11
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80,500 Bbls.
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Cameron 6(5)(6)
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Cameron, Louisiana
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2
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38,500 Bbls.
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Dulac(5)(7)
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Dulac, Louisiana
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2
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15,000 Bbls.
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|||
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Fourchon 17(5)(8)
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Fourchon, Louisiana
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4
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41,000 Bbls.
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|||
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River Ridge (5)(9)
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River Ridge, Louisiana
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33
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10,000 Bbls.
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|||
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Morgan City DWC 31(5)(10)
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Morgan City, Louisiana
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29
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25,500 Bbls.
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|||
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Morgan City 33(5)(11)
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Morgan City, Louisiana
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10
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53,500 Bbls.
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|||
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Fourchon 16(5)(12)
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Fourchon, Louisiana
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16
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13,500 Bbls.
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|||
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Venice 2(5)(13)
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Venice, Louisiana
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15
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25,000 Bbls.
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| (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.
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| (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.
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| (3) |
A portion of this terminal is located on land owned by third parties and leased under a lease that expires in April 2014.
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| (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.
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| (5) |
These terminals were acquired from Martin Resource Management on January 31, 2011.
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| (6) |
This terminal is located on land owned by third parties and leased under a lease that expires in March 2013.
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| (7) |
This terminal is located on land owned by third parties and leased under a lease that expires in December 2021 and can be extended by us through December 2041.
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| (8) |
This terminal is located on land owned by third parties and leased under a lease that expires in December 2013 and can be extended by us through December 2033.
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| (9) |
This terminal is located on land owned by third parties and leased under a lease that expires in April 2019.
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| (10) |
This terminal is located on land owned by third parties and leased under a lease that expires in December 2014 and can be extended by us through December 2034.
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| (11) |
This terminal is located on land owned by third parties and leased under a lease that expires in May 2014 and can be extended by us through May 2019.
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| (12) |
This terminal is located on land owned by third parties and leased under multiple leases that expires in July 2021, March 2012, and July 2012. These leases can be extended by us through July 2026, March 2022, and July 2022, respectively.
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| (13) |
This terminal is located on land owned by third parties and leased under a lease that expires in December 2012 and can be extended by us through December 2027.
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Terminal
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Location
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Tanks
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Aggregate
Capacity
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Products
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Description
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|||||
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Tampa(1)
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Tampa, Florida
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8
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718,000 Bbls.
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Asphalt, sulfur and fuel oil
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Marine terminal,
loading/unloading
for vessels, barges
railcars and trucks
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|||||
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||||||||||
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Stanolind
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Beaumont, Texas
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9
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555,000 Bbls.
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Asphalt, crude oil, sulfur, sulfuric acid and fuel oil
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Marine terminal, marine dock for
loading/unloading
of vessels, barges,
railcars and trucks
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|||||
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Neches
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Beaumont, Texas
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7
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500,400 Bbls.
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Ammonia, asphalt, fuel
oil, crude oil and
sulfur-based fertilizer
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Marine terminal,
loading/unloading
for vessels,
barges, railcars
and trucks
|
|||||
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Ouachita County
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Ouachita County, Arkansas
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2
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77,500 Bbls.
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Crude oil
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Marine terminal, loading/unloading for barges and trucks
|
|||||
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Corpus Christi
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Corpus Christi, Texas
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4
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330,000 Bbls.
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Fuel oil and diesel
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Marine Terminal, loading/unloading barges and vessels and unloading trucks
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Terminal
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Location
|
Aggregate
Capacity
|
Products
|
Description
|
||||
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Channelview
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Houston, Texas
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44,000 sq. ft.
Warehouse
35,000 Bbls
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Lubricants
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Lubricants blending and storage
|
||||
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Cross Refining
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Smackover, Arkansas
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7,500 Bbls per day
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Naphthenic lubricants, Distillates, Asphalt
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Crude refining facility
|
||||
| South Houston Asphalt | Houston, Texas | 71,000 Bbls | Asphalt | Asphalt Processing and storage | ||||
| Port Neches Asphalt | Port Neches, Texas | 31,300 Bbls | Asphalt | Asphalt Processing and storage | ||||
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Omaha Asphalt
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Omaha, Nebraska
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114,200 Bbls
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Asphalt
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Asphalt Processing and storage
|
||||
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Spindletop
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Beaumont, Texas
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90,000 Bbls
|
Natural Gasoline
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Pipeline receipts and shipments
|
||||
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Lake Charles(2)
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Lake Charles, Louisiana
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18,000 sq. ft.Warehouse 6,800 Bbls
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Lubricants
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Lubricants storage
|
|
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(1)
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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.
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|
|
(2)
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This terminal is located on land owned by third parties and leased under a lease that expires in January 2016 and can be extended by us through January 2021. This terminal was acquired from Martin Resource Management on January 31, 2011.
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|
·
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storage of NGLs purchased in off-peak months;
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|
·
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efficient use of the transportation fleet of vehicles owned by Martin Resource Management; and
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|
·
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product management expertise to obtain supplies when needed.
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|
NGL Facility
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Location
|
Capacity
|
Description
|
|||
|
Wholesale terminals
|
Arcadia, Louisiana(1)
|
2,400,000 barrels
|
Underground storage
|
|||
|
Hattiesburg, Mississippi(2)
|
60,000 barrels
|
Underground storage
|
||||
|
Mt. Belvieu, Texas(3)(2)
|
70,000 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 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.
|
|
|
·
|
Waskom Processing Plant — The Waskom Processing Plant, located in Harrison County in East Texas, currently has 320 MMcfd of processing capacity with full fractionation facilities. Expansions to the processing plant were completed in March 2007, June 2007, July 2008, June 2009 and September 2011, increasing the capacity from 150 MMcfd to 320 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, 2011 and 2010, inlet throughput and NGL fractionation averaged approximately 269 and 281 MMcfd and 9,157 and 9,691 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 Company’s wholly owned subsidiary Waskom Midstream LLC, we acquired the Harrison Pipeline System, located in Harrison County in East Texas. The system consisted of gathering pipeline, two 35 MMcfd dew point control plants and various equipment. In March of 2010, the gas was rerouted to the Waskom Processing Plant which resulted in the shutdown of the two dew point control plants. This allowed for the sale of one of the plants in 2010 with the second plant being sold in the second quarter of 2011. For the years ended December 31, 2011 and 2010, the system gathered 36 and 37 MMcfd, respectively. We reflect the results of operations from this system using the equity method of accounting.
|
|
|
·
|
East Harrison Gathering System – The East Harrison Gathering System located in Harrison County in East Texas was acquired in December of 2009. Prism Gas owns a consolidated 100% interest in this system but leased the system to Waskom Midstream LLC effective March 1, 2010, and as such we reflect the results of operations using the equity method of accounting. For 2011 and 2010, volumes transported through the system are included in the Harrison Pipeline System volumes.
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|
|
·
|
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 in East 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, which was assigned to Waskom Midstream LLC effective March 1, 2010, and as such, we reflect the results of operations using the equity method of accounting. For 2011 and 2010, volumes gathered on the Marshall Line are included in the Harrison Pipeline System volumes.
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|
·
|
Woodlawn Plant and Gathering System —Woodlawn is a natural gas gathering and processing company, which owns integrated gathering and processing assets in East Texas. Woodlawn’s system consists of natural gas gathering pipe, a condensate transport pipeline and a 30 MMcfd processing plant. For the years ended December 31, 2011 and 2010, the Woodlawn Gathering System gathered approximately 24 and 25 MMcfd of natural gas, respectively. Prism owns a consolidated 100% interest in this system.
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|
|
·
|
The Prism Liquids Pipeline — The Prism Liquids Pipeline condensate system was formed from the condensate transport pipe 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. For the years ended December 31, 2011 and 2010, the Prism Liquids Pipeline transported 1,323 and 1,278 bpd of condensate, respectively. Prism owns a consolidated 100% interest in this system.
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|
|
·
|
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. It provides processing and blending services for natural gas with high nitrogen and high liquids content gathered by the system. For the years ended December 31, 2011 and 2010, the McLeod Gathering System gathered approximately 5 and 5 MMcfd of natural gas, respectively. Prism Gas owns a consolidated 100% interest in this system.
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|
|
·
|
Hallsville Gathering System — The Hallsville Gathering System, located in Harrison County, Texas, provides gathering and centralized compression for producers in the Oak Hill Field of East Texas. The system operates at low pressure and redelivers gas to two interstate and three intrastate markets via the Oakhill Gathering System. For the years ended December 31, 2011 and 2010, the Hallsville Gathering System gathered approximately 10 and 13 MMcfd of natural gas, respectively. Prism Gas owns a consolidated 100% interest in this system.
|
|
|
·
|
Darco Gathering System — The Darco Gathering System located in Harrison County, Texas was acquired on November 1, 2010. The system consists of natural gas gathering pipe, various equipment and intangibles. The gathering system is tied to the Harrison Pipeline System and to a third party system. Prism Gas owns a consolidated 100% interest in this system. For the year ended December 31, 2011, the Darco Gathering System gathered approximately 20 MMcfd of natural gas. For November and December 2010, the Darco Gathering System gathered approximately 28 MMcfd of natural gas.
|
|
|
·
|
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 sold its 100% interest in these systems effective November 1, 2010.
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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 2010, volumes were shut in on a significant portion of the system as a pipeline was rerouted in response to a producer platform removal. For the years ended December 31, 2011 and 2010 approximately 14 and 6 MMcfd of natural gas was gathered and transported on the system, respectively. 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.
|
|
|
·
|
Matagorda Gathering System — The Matagorda 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, 2011 and 2010, the system gathered approximately 6 and 8 MMcfd of natural gas, respectively. Prism Gas owns an unconsolidated 50% non-operating interest in the Matagorda 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.
|
|
|
·
|
Plant nutrient sulfur products. We produce plant nutrient and agricultural ground sulfur products at our two facilities in Odessa, Texas. We also produce plant nutrient sulfur at our facility in Seneca, Illinois. Our plant nutrient sulfur product is a 90% degradable sulfur product marketed under the Disper-Sul® trade name and sold throughout the United States to direct application agricultural markets. Our agricultural ground sulfur products are used primarily in the western United States on grapes and vegetable crops.
|
|
|
·
|
Ammonium sulfate products, NPK 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. These products primarily serve direct application agricultural markets within a 400-mile radius of our manufacturing plant in Plainview, Texas. We blend our ammonium sulfate to make custom grades of lawn and garden fertilizer at our facility in Salt Lake City, Utah. We package these custom grade products under both proprietary and private labels and sell them to major retail distributors and other retail customers of these products.
|
|
|
·
|
Industrial sulfur products. We produce industrial sulfur products such as emulsified sulfur, elemental pastille sulfur, and industrial ground sulfur products. We produce emulsified sulfur at our Texarkana, Texas facility. Emulsified sulfur is primarily used to control the sulfur content in the pulp and paper manufacturing processes. We produce elemental pastille sulfur at our two Odessa, Texas facilities and at our Seneca, Illinois facility. Elemental pastille sulfur is used to increase the efficiency of the coal-fired precipitators in the power industry. These industrial ground sulfur products are also used in a variety of dusting and wettable sulfur applications such as rubber manufacturing, fungicides, sugar and animal feeds.
|
|
|
·
|
Liquid sulfur products. We produce ammonium thiosulfate at our Neches terminal location in Beaumont, Texas. This agricultural sulfur product is a clear liquid containing 12% nitrogen and 26% sulfur. This product serves as a liquid plant nutrient used directly through spray rigs or irrigation systems. It is also blended with other NPK liquids or suspensions as well. Our market is predominantly the Mid-South United States and Coastal Bend area of Texas.
|
|
Asset
|
Class of Equipment
|
Capacity/Horsepower
|
Products Transported
|
|||
|
Margaret Sue
|
Offshore tank barge
|
10,450 long tons
|
Molten sulfur
|
|||
|
M/V Martin Explorer
|
Offshore tugboat
|
7,200 horsepower
|
N/A
|
|||
|
M/V Martin Express
|
Inland push boat
|
1,200 horsepower
|
N/A
|
|||
|
MGM 101
|
Inland tank barge
|
2,450 long tons
|
Molten sulfur
|
|||
|
MGM 102
|
Inland tank barge
|
2,450 long tons
|
Molten sulfur
|
| Terminal | Location | Daily Production Capacity | Products Stored | |||
|
Stockton
|
Stockton, California
|
1,000 metric tons per day
|
Molten and prilled sulfur
|
|||
|
Neches
|
Beaumont, Texas
|
4,000 metric tons per day
|
Molten and prilled sulfur
|
|
Facility
|
Location
|
Capacity
|
Description
|
|||
|
Fertilizer plants (two)
|
Odessa, Texas
|
70,000 tons/year
|
Dry sulfur fertilizer production
|
|||
|
Fertilizer plant
|
Seneca, Illinois
|
36,000 tons/year
|
Dry sulfur fertilizer production
|
|||
|
Fertilizer plant
|
Plainview, Texas
|
180,000 tons/year
|
Fertilizer production
|
|||
|
Fertilizer plant
|
Salt Lake City, Utah
|
25,000 tons/year
|
Blending and packaging
|
|||
|
Fertilizer plant
|
Beaumont, Texas
|
100,000 tons/year
|
Liquid sulfur fertilizer production
|
|||
|
Industrial sulfur plant
|
Texarkana, Texas
|
18,000 tons/year
|
Emulsified sulfur production
|
|||
|
Sulfuric acid plant
|
Plainview Texas
|
150,000 tons/year
|
Sulfuric acid production
|
|
Class of Equipment
|
Number in Class
|
Capacity/Horsepower
|
Description of Products Carried
|
|||
|
Inland tank barges
|
13
|
20,000 bbl and under
|
Asphalt, crude oil, fuel oil,
gasoline and sulfur
|
|||
|
Inland tank barges
|
28
|
20,000 - 30,000 bbl
|
Asphalt, crude oil, fuel oil
and gasoline
|
|||
|
Inland push boats
|
20
|
800 - 3,800
horsepower
|
N/A
|
|||
|
Offshore tank barges
|
4
|
40,000 bbl and 95,000
bbl
|
Asphalt, fuel oil and NGLs
|
|||
|
Offshore tugboats
|
4
|
2,400 - 7,200
horsepower
|
N/A
|
|
|
·
|
the increasing age of the domestic tank barge fleet, resulting in retirements;
|
|
|
·
|
a reduction in tax incentives, which previously encouraged speculative construction of new equipment;
|
|
|
·
|
stringent operating standards to adequately address safety and environmental risks;
|
|
|
·
|
the elimination of government programs supporting small refineries;
|
|
|
·
|
an increase in environmental regulations mandating expensive equipment modification; and
|
|
|
·
|
more restrictive and expensive insurance.
|
|
|
·
|
significant start-up capital requirements;
|
|
|
·
|
the costs and operational difficulties of complying with stringent safety and environmental regulations;
|
|
|
·
|
the cost and difficulty in obtaining insurance; and
|
|
|
·
|
the number and expertise of personnel required to support marine fleet operations.
|
|
|
·
|
providing land transportation of various liquids using a fleet of trucks and road vehicles and road trailers;
|
|
|
·
|
distributing fuel oil, asphalt, sulfuric acid, marine fuel and other liquids;
|
|
|
·
|
providing marine bunkering and other shore-based marine services in Alabama, Louisiana, Mississippi and Texas;
|
|
|
·
|
operating a crude oil gathering business in Stephens, Arkansas;
|
|
|
·
|
operating a lube oil packaging facility in Smackover, Arkansas;
|
|
|
·
|
operating an underground NGL storage facility in Arcadia, Louisiana;
|
|
|
·
|
building and marketing of sulfur processing equipment;
|
|
|
·
|
developing underground natural gas storage facilities in Arcadia, Louisiana and near Delhi, Louisiana;
|
|
|
·
|
supplying employees and services for the operation of our business;
|
|
|
·
|
operating, for its account and our account, the docks, roads, loading and unloading facilities and other common use facilities or access routes at our Stanolind terminal; and
|
|
|
·
|
operating, solely for our account, the asphalt facilities in Omaha, Nebraska.
|
|
|
·
|
perform ongoing assessments of pipeline integrity;
|
|
|
·
|
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
|
|
|
·
|
improve data collection, integration and analysis;
|
|
|
·
|
repair and remediate the pipeline as necessary; and
|
|
|
·
|
implement preventive and mitigating actions.
|
|
Ite
m1
A.
|
Risk Factors
|
|
|
·
|
the costs of acquisitions, if any;
|
|
|
·
|
the prices of petroleum products and by-products;
|
|
|
·
|
fluctuations in our working capital;
|
|
|
·
|
the level of capital expenditures we make;
|
|
|
·
|
restrictions contained in our debt instruments and our debt service requirements;
|
|
|
·
|
our ability to make working capital borrowings under our credit facility; and
|
|
|
·
|
the amount, if any, of cash reserves established by our general partner in its discretion.
|
|
|
·
|
one or more of our lenders may be unable or otherwise fail to meet its funding obligations;
|
|
|
·
|
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
|
|
|
·
|
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.
|
|
|
·
|
post-closing discovery of material undisclosed liabilities of the acquired business or assets;
|
|
|
·
|
the unexpected loss of key employees or customers from the acquired businesses;
|
|
|
·
|
difficulties resulting from our integration of the operations, systems and management of the acquired business; and
|
|
|
·
|
an unexpected diversion of our management’s attention from other operations.
|
|
|
·
|
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;
|
|
|
·
|
leakage of NGLs and other petroleum products and by-products;
|
|
|
·
|
fires and explosions;
|
|
|
·
|
damage to transportation, terminalling and storage facilities, and surrounding properties caused by natural disasters; and
|
|
|
·
|
terrorist attacks or sabotage.
|
|
|
·
|
prevailing oil and natural gas prices and expectations about future prices and price volatility;
|
|
|
·
|
the cost of offshore exploration for and production and transportation of oil and natural gas;
|
|
|
·
|
worldwide demand for oil and natural gas;
|
|
|
·
|
consolidation of oil and gas and oil service companies operating offshore;
|
|
|
·
|
availability and rate of discovery of new oil and natural gas reserves in offshore areas;
|
|
|
·
|
local and international political and economic conditions and policies;
|
|
|
·
|
technological advances affecting energy production and consumption;
|
|
|
·
|
weather conditions;
|
|
|
·
|
environmental regulation; and
|
|
|
·
|
the ability of oil and gas companies to generate or otherwise obtain funds for exploration and production.
|
|
|
·
|
catastrophic events, including hurricanes;
|
|
|
·
|
environmental remediation;
|
|
|
·
|
labor difficulties; and
|
|
|
·
|
disruptions in the supply of our products to our facilities or means of transportation.
|
|
|
·
|
the impact of weather on the demand for oil and natural gas;
|
|
|
·
|
the level of domestic oil and natural gas production;
|
|
|
·
|
the level of domestic industrial and manufacturing activity;
|
|
|
·
|
the availability of imported oil and natural gas;
|
|
|
·
|
actions taken by foreign oil and gas producing nations;
|
|
|
·
|
the availability of local, intrastate and interstate transportation systems;
|
|
|
·
|
the availability and marketing of competitive fuels;
|
|
|
·
|
the impact of energy conservation efforts; and
|
|
|
·
|
the extent of governmental regulation and taxation.
|
|
|
·
|
perform ongoing assessments of pipeline integrity;
|
|
|
·
|
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
|
|
|
·
|
improve data collection, integration and analysis;
|
|
|
·
|
repair and remediate the pipeline as necessary; and
|
|
|
·
|
implement preventive and mitigating actions.
|
|
|
·
|
the issuance of common units in additional public offerings or in connection with acquisitions that increase cash flow from operations on a pro forma, per unit basis;
|
|
|
·
|
the conversion of subordinated units into common units;
|
|
|
·
|
the conversion of units of equal rank with the common units into common units under some circumstances; or
|
|
|
·
|
the conversion of our general partner’s general partner interest in us and its incentive distribution rights into common units as a result of the withdrawal of our general partner.
|
|
|
·
|
we had been conducting business in any state without compliance with the applicable limited partnership statute or
|
|
|
·
|
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.
|
|
|
·
|
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;
|
|
|
·
|
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;
|
|
|
·
|
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
|
|
|
·
|
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.
|
|
|
·
|
the issuance of common units in additional public offerings or in connection with acquisitions that increase cash flow from operations on a pro forma, per unit basis;
|
|
|
·
|
the conversion of subordinated units into common units;
|
|
|
·
|
the conversion of units of equal rank with the common units into common units under some circumstances; or
|
|
|
·
|
the conversion of our general partner’s general partner interest in us and its incentive distribution rights into common units as a result of the withdrawal of our general partner.
|
|
|
·
|
our unitholders’ proportionate ownership interest in us will decrease;
|
|
|
·
|
the amount of cash available for distribution on a per unit basis may decrease;
|
|
|
·
|
because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
|
|
|
·
|
the relative voting strength of each previously outstanding unit will diminish;
|
|
|
·
|
the market price of the common units may decline; and
|
|
|
·
|
the ratio of taxable income to distributions may increase.
|
|
|
·
|
Officers of Martin Resource Management who provide services to us also devote significant time to the businesses of Martin Resource Management and are compensated by Martin Resource Management for that time.
|
|
|
·
|
Neither our partnership agreement nor any other agreement requires Martin Resource Management to pursue a business strategy that favors us or utilizes our assets or services. Martin Resource Management’s 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.
|
|
|
·
|
Martin Resource Management may engage in limited competition with us.
|
|
|
·
|
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.
|
|
|
·
|
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.
|
|
|
·
|
Our general partner determines which costs incurred by Martin Resource Management are reimbursable by us.
|
|
|
·
|
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.
|
|
|
·
|
Our general partner controls the enforcement of obligations owed to us by Martin Resource Management.
|
|
|
·
|
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
|
|
|
·
|
The audit committee of our general partner retains our independent auditors.
|
|
|
·
|
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.
|
|
|
·
|
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.
|
|
Item 1B.
|
Unres
olv
ed Staff Comments
|
|
Item 2.
|
Pro
pe
rties
|
|
Item 3.
|
Legal Proce
ed
ings
|
|
Item 4.
|
Mine Sa
fety
Disclosures
|
|
Common Units
|
Distributions Declared per Unit
|
|||||||||||||||
|
Quarters Ended
|
High
|
Low
|
Common
|
Subordinated
(
1)
|
||||||||||||
|
March 31, 2011
|
$ | 42.35 | $ | 37.21 | $ | 0.7600 | $ | — | ||||||||
|
June 30, 2011
|
$ | 41.44 | $ | 36.24 | $ | 0.7625 | $ | — | ||||||||
|
September 30, 2011
|
$ | 40.05 | $ | 28.43 | $ | 0.7625 | $ | — | ||||||||
|
December 31, 2011
|
$ | 36.22 | $ | 30.06 | $ | 0.7625 | $ | — | ||||||||
|
Common Units
|
Distributions Declared per Unit
|
|||||||||||||||
|
Quarters Ended
|
High
|
Low
|
Common
|
Subordinated
1
|
||||||||||||
|
March 31, 2010
|
$ | 34.25 | $ | 29.34 | $ | 0.7500 | $ | — | ||||||||
|
June 30, 2010
|
$ | 32.45 | $ | 27.00 | $ | 0.7500 | $ | — | ||||||||
|
September 30, 2010
|
$ | 33.87 | $ | 28.78 | $ | 0.7500 | $ | — | ||||||||
|
December 31, 2010
|
$ | 39.37 | $ | 32.85 | $ | 0.7600 | $ | — | ||||||||
|
2011
|
2010
|
2009
|
2008
|
2007
|
||||||||||||||||
|
(Dollars in thousands, except per unit amounts)
|
||||||||||||||||||||
|
Income Statement Data:
|
||||||||||||||||||||
|
Revenues
|
$ | 1,237,073 | $ | 912,118 | $ | 662,385 | $ | 1,246,444 | $ | 804,327 | ||||||||||
|
Cost of product sold
|
990,904 | 693,902 | 457,259 | 1,013,526 | 618,689 | |||||||||||||||
|
Operating expenses
|
140,197 | 116,402 | 117,438 | 126,808 | 104,165 | |||||||||||||||
|
Selling, general, and administrative
|
22,665 | 21,118 | 19,775 | 19,062 | 13,918 | |||||||||||||||
|
Depreciation and amortization
|
44,957 | 40,656 | 39,506 | 34,893 | 26,323 | |||||||||||||||
|
Total costs and expenses
|
1,198,723 | 872,078 | 633,978 | 1,194,289 | 763,095 | |||||||||||||||
|
Other operating income
|
1,326 | 136 | 6,013 | 209 | 703 | |||||||||||||||
|
Operating income
|
39,676 | 40,176 | 34,420 | 52,364 | 41,935 | |||||||||||||||
|
Equity in earnings of unconsolidated entities
|
9,536 | 9,792 | 7,044 | 13,224 | 10,941 | |||||||||||||||
|
Interest expense
|
(24,518 | ) | (33,716 | ) | (18,995 | ) | (21,433 | ) | (15,125 | ) | ||||||||||
|
Other, net
|
233 | 287 | 326 | 801 | 405 | |||||||||||||||
|
Income before income taxes
|
24,927 | 16,539 | 22,795 | 44,956 | 38,156 | |||||||||||||||
|
Income taxes
|
585 | 517 | 592 | 1,398 | 5,595 | |||||||||||||||
|
Net income
|
$ | 24,342 | $ | 16,022 | $ | 22,203 | $ | 43,558 | $ | 32,561 | ||||||||||
|
Net income per limited partner unit
|
$ | 0.92 | $ | 0.63 | $ | 1.17 | $ | 2.72 | $ | 1.67 | ||||||||||
|
Weighted average limited partner units
|
19,545,427 | 17,525,089 | 14,680,807 | 14,529,826 | 14,018,799 | |||||||||||||||
|
Balance Sheet Data (at Period End):
|
||||||||||||||||||||
|
Total assets
|
$ | 949,109 | $ | 785,478 | $ | 685,939 | $ | 706,322 | $ | 656,604 | ||||||||||
|
Due to affiliates
|
18,485 | 6,957 | 13,810 | 23,085 | 17,119 | |||||||||||||||
|
Long-term debt
|
458,941 | 372,862 | 304,372 | 295,000 | 225,000 | |||||||||||||||
|
Partner’s capital (owner’s equity)
|
285,616 | 274,806 | 264,951 | 246,379 | 246,765 | |||||||||||||||
|
Cash Flow Data:
|
||||||||||||||||||||
|
Net cash flow provided by (used in):
|
||||||||||||||||||||
|
Operating activities
|
86,870 | 37,518 | 47,592 | 86,340 | 61,209 | |||||||||||||||
|
Investing activities
|
(167,335 | ) | (76,728 | ) | (14,675 | ) | (106,621 | ) | (130,295 | ) | ||||||||||
|
Financing activities
|
69,351 | 44,634 | (34,944 | ) | 24,151 | 69,896 | ||||||||||||||
|
Other Financial Data:
|
||||||||||||||||||||
|
Maintenance capital expenditures
|
10,947 | 4,653 | 7,601 | 17,998 | 11,955 | |||||||||||||||
|
Expansion capital expenditures
|
63,048 | 12,367 | 28,572 | 89,435 | 109,474 | |||||||||||||||
|
Total capital expenditures
|
$ | 73,995 | $ | 17,020 | $ | 36,173 | $ | 107,433 | $ | 121,429 | ||||||||||
|
Cash dividends per common unit (in dollars)
|
$ | 3.05 | $ | 3.00 | $ | 3.00 | $ | 2.91 | $ | 2.60 | ||||||||||
| 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 | ||||||
|
|
·
|
Terminalling and storage services for petroleum products 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.
|
|
|
·
|
Several gas producers in our areas of operation have reduced drilling activity as compared to their previous levels of activity demonstrating a bias toward newly found shale plays in other areas.
|
|
|
·
|
Coupled with the general decline in drilling activity are the federal government’s enhanced safety regulations and inspection requirements as it relates to deep-water drilling in the Gulf of Mexico. In October 2010, the United States Government lifted the moratorium on deep water permitting and drilling. These enhanced safety regulations and inspection requirements of the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) continue to provide uncertainty surrounding the requirements for and pace of issuance of permits on the Gulf of Mexico Outer Continental Shelf (OCS). Although permits began to be issued by the BOEMRE again during first quarter 2011, they have not been approved in a timely manner consistent with pre-BP/Macondo spill levels.
|
|
|
·
|
There has been a decline in the demand for certain marine transportation services based on decreased refinery production resulting in an oversupply of equipment. This was partially offset in 2010 by the marine transportation services required in the efforts to clean up the BP oil spill in the Gulf of Mexico.
|
|
|
·
|
We continue to adjust our business strategy 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. Over the past year we have had access to the capital markets and have appropriate levels of liquidity and operating cash flows to adequately fund our growth. Our goal over the next two years will be to increase growth capital expenditures primarily in our Terminalling and Storage and Sulfur Services segments.
|
|
|
·
|
We continue to evaluate opportunities to enter into interest rate and commodity hedging transactions. We believe these transactions can beneficially remove risks associated with interest rate and commodity price volatility.
|
|
|
·
|
During 2011, we have experienced positive changing market dynamics in certain segments, including activity associated with the rapidly developing basins such as the Eagle Ford shale.
|
|
Operating
Revenues
|
Revenues
Intersegment
Eliminations
|
Operating
Revenues
after
Eliminations
|
Operating
Income
(loss)
|
Operating
Income
Intersegment
Eliminations
|
Operating
Income (loss)
after
Eliminations
|
|||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||
|
Year ended December 31, 2011:
|
||||||||||||||||||||||||
|
Terminalling and storage
|
$ | 156,420 | $ | (4,414 | ) | $ | 152,006 | $ | 14,022 | $ | (948 | ) | $ | 13,074 | ||||||||||
|
Natural gas services
|
733,087 | — | 733,087 | 6,136 | 1,220 | 7,356 | ||||||||||||||||||
|
Sulfur services
|
275,044 | — | 275,044 | 27,651 | 6,944 | 34,595 | ||||||||||||||||||
|
Marine transportation
|
83,971 | (7,035 | ) | 76,936 | 731 | (7,216 | ) | (6,485 | ) | |||||||||||||||
|
Indirect selling, general and administrative
|
— | — | — | (8,864 | ) | — | (8,864 | ) | ||||||||||||||||
|
Total
|
$ | 1,248,522 | $ | (11,449 | ) | $ | 1,237,073 | $ | 39,676 | $ | — | $ | 39,676 | |||||||||||
|
Year ended December 31, 2010:
|
||||||||||||||||||||||||
|
Terminalling and storage
|
$ | 119,270 | $ | (4,354 | ) | $ | 114,916 | $ | 16,032 | $ | (1,776 | ) | $ | 14,256 | ||||||||||
|
Natural gas services
|
554,482 | — | 554,482 | 4,652 | 964 | 5,616 | ||||||||||||||||||
|
Sulfur services
|
165,078 | — | 165,078 | 15,886 | 4,280 | 20,166 | ||||||||||||||||||
|
Marine transportation
|
82,635 | (4,993 | ) | 77,642 | 9,992 | (3,468 | ) | 6,524 | ||||||||||||||||
|
Indirect selling, general and administrative
|
— | — | — | (6,386 | ) | — | (6,386 | ) | ||||||||||||||||
|
Total
|
$ | 921,465 | $ | (9,347 | ) | $ | 912,118 | $ | 40,176 | $ | — | $ | 40,176 | |||||||||||
|
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 | |||||||||||
| Years Ended December 31, | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Revenues:
|
||||||||
|
Services
|
$ | 81,697 | $ | 71,471 | ||||
|
Products
|
74,723 | 47,799 | ||||||
|
Total Revenues
|
156,420 | 119,270 | ||||||
|
Cost of products sold
|
70,601 | 44,549 | ||||||
|
Operating expenses
|
52,041 | 41,857 | ||||||
|
Selling, general and administrative expenses
|
242 | 426 | ||||||
|
Depreciation and amortization
|
18,983 | 16,650 | ||||||
| 14,553 | 15,788 | |||||||
|
Other operating income (loss)
|
(531 | ) | 244 | |||||
|
Operating income
|
$ | 14,022 | $ | 16,032 | ||||
|
Years Ended December 31,
|
||||||||
|
2011
|
2010
|
|||||||
|
(In thousands)
|
||||||||
|
Revenues:
|
||||||||
|
NGLs
|
$ | 688,407 | $ | 501,919 | ||||
|
Natural gas
|
37,945 | 46,812 | ||||||
|
Non-cash mark to market and impairment adjustments of commodity derivatives
|
1,322 | 253 | ||||||
|
Gain (loss) on cash settlements of commodity derivatives
|
39 | 582 | ||||||
|
Other operating fees
|
5,374 | 4,916 | ||||||
|
Total revenues
|
733,087 | 554,482 | ||||||
|
Cost of products sold:
|
||||||||
|
NGLs
|
668,747 | 482,231 | ||||||
|
Natural gas
|
36,546 | 46,187 | ||||||
|
Total cost of products sold
|
705,293 | 528,418 | ||||||
|
Operating expenses
|
8,457 | 7,689 | ||||||
|
Selling, general and administrative expenses
|
7,111 | 8,588 | ||||||
|
Depreciation and amortization
|
6,090 | 5,023 | ||||||
| 6,136 | 4,764 | |||||||
|
Other operating income (loss)
|
— | (112 | ) | |||||
|
Operating income
|
$ | 6,136 | $ | 4,652 | ||||
|
NGLs Volumes (Bbls)
|
10,494 | 9,730 | ||||||
|
Natural Gas Volumes (Mmbtu)
|
10,112 | 11,390 | ||||||
|
*Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments
|
||||||||
|
Equity in Earnings of Unconsolidated Entities
|
$ | 9,535 | $ | 9,792 | ||||
| Waskom: | ||||||||
| Plant Inlet Volumes (MMcfd) | 269 | 281 | ||||||
| Frac Volumes (Bbls/d) | 9,157 | 9,691 | ||||||
|
Years Ended December 31,
|
||||||||
|
2011
|
2010
|
|||||||
|
(In thousands)
|
||||||||
|
Revenues:
|
||||||||
|
Services
|
$ | 11,400 | $ | — | ||||
|
Products
|
263,644 | 165,078 | ||||||
|
Total revenues
|
275,044 | 165,078 | ||||||
|
Cost of products sold
|
220,059 | 122,483 | ||||||
|
Operating expenses
|
19,328 | 17,013 | ||||||
|
Selling, general and administrative expenses
|
3,361 | 3,422 | ||||||
|
Depreciation and amortization
|
6,725 | 6,262 | ||||||
| 25,571 | 15,898 | |||||||
|
Other operating income(loss)
|
2,080 | (12 | ) | |||||
|
Operating income
|
$ | 27,651 | $ | 15,886 | ||||
|
Sulfur (long tons)
|
1,314.5 | 1,129.2 | ||||||
|
Fertilizer (long tons)
|
271.8 | 274.9 | ||||||
|
Sulfur Services Volumes (long tons)
|
1,586.3 | 1,404.1 | ||||||
|
Years Ended December 31,
|
||||||||
|
2011
|
2010
|
|||||||
|
(In thousands)
|
||||||||
|
Revenues
|
$ | 83,971 | $ | 82,635 | ||||
|
Operating expenses
|
66,771 | 57,642 | ||||||
|
Selling, general and administrative expenses
|
3,087 | 2,296 | ||||||
|
Depreciation and amortization
|
13,159 | 12,721 | ||||||
| 954 | 9,976 | |||||||
|
Other operating income (loss)
|
(223 | ) | 16 | |||||
|
Operating income
|
$ | 731 | $ | 9,992 | ||||
| Years Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
|
Revenues:
|
||||||||
|
Services
|
$ | 71,471 | $ | 73,885 | ||||
|
Products
|
47,799 | 35,628 | ||||||
|
Total Revenues
|
119,270 | 109,513 | ||||||
|
Cost of products sold
|
44,549 | 31,331 | ||||||
|
Operating expenses
|
41,857 | 45,783 | ||||||
|
Selling, general and administrative expenses
|
426 | 1,955 | ||||||
|
Depreciation and amortization
|
16,650 | 15,717 | ||||||
| 15,788 | 14,727 | |||||||
|
Other operating income (loss)
|
244 | 5,504 | ||||||
|
Operating income
|
$ | 16,032 | $ | 20,231 | ||||
|
Years Ended December 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
(In thousands)
|
||||||||
|
Revenues:
|
||||||||
|
NGLs
|
$ | 501,919 | $ | 384,124 | ||||
|
Natural gas
|
46,812 | 20,334 | ||||||
|
Non-cash mark to market and impairment adjustments of commodity derivatives
|
253 | (2,490 | ) | |||||
|
Gain (loss) on cash settlements of commodity derivatives
|
582 | 3,273 | ||||||
|
Other operating fees
|
4,916 | 3,748 | ||||||
|
Total revenues
|
554,482 | 408,989 | ||||||
|
Cost of products sold:
|
||||||||
|
NGLs
|
482,231 | 364,350 | ||||||
|
Natural gas
|
46,187 | 19,261 | ||||||
|
Total cost of products sold
|
528,418 | 383,611 | ||||||
|
Operating expenses
|
7,689 | 8,627 | ||||||
|
Selling, general and administrative expenses
|
8,588 | 7,332 | ||||||
|
Depreciation and amortization
|
5,023 | 4,527 | ||||||
| 4,764 | 4,892 | |||||||
|
Other operating income
|
(112 | ) | (12 | ) | ||||
|
Operating income
|
$ | 4,652 | $ | 4,880 | ||||
|
NGLs Volumes (Bbls)
|
9,730 | 9,880 | ||||||
|
Natural Gas Volumes (Mmbtu)
|
11,390 | 6,155 | ||||||
|
*Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments
|
||||||||
|
Equity in Earnings of Unconsolidated Entities
|
$ | 9,792 | $ | 7,044 | ||||
|
Waskom:
|
||||||||
| Plant Inlet Volumes (MMcfd) | 281 | 243 | ||||||
| Frac Volumes (Bbls/d) | 9,691 | 10,034 | ||||||
|
Years Ended December 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
(In thousands)
|
||||||||
|
Revenues
|
$ | 165,078 | $ | 79,631 | ||||
|
Cost of products sold
|
122,483 | 43,748 | ||||||
|
Operating expenses
|
17,013 | 17,113 | ||||||
|
Selling, general and administrative expenses
|
3,422 | 3,449 | ||||||
|
Depreciation and amortization
|
6,262 | 6,151 | ||||||
| 15,898 | 9,170 | |||||||
|
Other operating income
|
(12 | ) | 405 | |||||
|
Operating income
|
$ | 15,886 | $ | 9,575 | ||||
|
Sulfur (long tons)
|
1,129.2 | 1,107.5 | ||||||
|
Fertilizer (long tons)
|
274.9 | 238.0 | ||||||
|
Sulfur Services Volumes (long tons)
|
1,404.1 | 1,345.5 | ||||||
|
Years Ended December 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
(In thousands)
|
||||||||
|
Revenues
|
$ | 82,635 | $ | 72,103 | ||||
|
Operating expenses
|
57,642 | 52,335 | ||||||
|
Selling, general and administrative expenses
|
2,296 | 962 | ||||||
|
Depreciation and amortization
|
12,721 | 13,111 | ||||||
| 9,976 | 5,695 | |||||||
|
Other operating income
|
16 | 116 | ||||||
|
Operating income
|
$ | 9,992 | $ | 5,811 | ||||
|
|
·
|
In 2011, we spent $11.0 million for expansion and $63.0 million for maintenance (including $0.8 million for maintenance in the fourth quarter of 2011). Our expansion capital expenditures were made in connection with marine vessel conversions, construction projects associated with our terminalling and storage and sulfur services businesses. Our maintenance capital expenditures were primarily made in our marine and sulfur services divisions for routine operating equipment improvements.
|
|
|
·
|
In 2010, we spent $13.2 million for expansion and $4.7 million for maintenance (including $1.2 million for maintenance in the fourth quarter of 2010). Our expansion capital expenditures were made in connection with marine vessel conversions, construction projects associated with our terminalling and storage and sulfur services businesses. Our maintenance capital expenditures were primarily made in our terminalling and storage and sulfur services divisions for routine operating equipment improvements.
|
|
|
·
|
In 2009, we spent $28.0 million for expansion and $7.8 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 storage 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.
|
|
Payment due by period
|
||||||||||||||||||||
|
Type of Obligation
|
Total
Obligation
|
Less than
One Year
|
1-3
Years
|
3-5
Years
|
Due
Thereafter
|
|||||||||||||||
|
Long-Term Debt
|
||||||||||||||||||||
|
Revolving credit facility
|
$ | 250,000 | $ | — | $ | — | $ | 250,000 | $ | — | ||||||||||
|
Senior unsecured notes
|
197,808 | — | — | — | 197,808 | |||||||||||||||
|
Note payable
|
6,363 | 1,068 | 2,392 | 2,778 | 125 | |||||||||||||||
|
Capital leases including current maturities
|
6,031 | 193 | 534 | 5,304 | — | |||||||||||||||
|
Non-competition agreements
|
150 | 50 | 100 | — | — | |||||||||||||||
|
Throughput commitment
|
52,298 | 3,147 | 9,746 | 10,382 | 29,023 | |||||||||||||||
|
Operating leases
|
47,365 | 11,776 | 14,990 | 11,861 | 8,738 | |||||||||||||||
|
Interest expense
(1)
|
||||||||||||||||||||
|
Revolving credit facility
|
32,838 | 7,659 | 15,317 | 9,862 | — | |||||||||||||||
|
Senior unsecured notes
|
112,417 | 17,750 | 35,500 | 35,500 | 23,667 | |||||||||||||||
|
Note payable
|
1,311 | 441 | 628 | 241 | 1 | |||||||||||||||
|
Capital leases
|
4,057 | 945 | 1,782 | 1,330 | — | |||||||||||||||
|
Total contractual cash obligations
|
$ | 710,638 | $ | 43,029 | $ | 80,989 | $ | 327,258 | $ | 259,362 | ||||||||||
|
|
(1)
Interest commitments are estimated using our current interest rates for the respective credit agreements over their remaining terms.
|
|
Leverage Ratio
|
Base
Rate
Loans
|
Eurodollar
Rate
Loans
|
Letters of
Credit
|
|||
|
Less than 2.25 to 1.00
|
1.00%
|
2.00%
|
2.00%
|
|||
|
Greater than or equal to 2.25 to 1.00 and less than 3.00 to 1.00
|
1.25%
|
2.25%
|
2.25%
|
|||
|
Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00
|
1.50%
|
2.50%
|
2.50%
|
|||
|
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00
|
1.75%
|
2.75%
|
2.75%
|
|||
|
Greater than or equal to 4.00 to 1.00
|
2.00%
|
3.00%
|
3.00%
|
|||
|
Greater than or equal to 4.50 to 1.00
|
2.25%
|
3.25%
|
3.25%
|
|
|
•
|
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.
|
|
|
•
|
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; and
|
|
|
•
|
any of our joint ventures incurs debt or liens in excess of a threshold amount.
|
|
|
•
|
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.
|
|
|
•
|
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 decrease.
|
|
|
•
|
Natural gas contracts - monthly posting for ANR Pipeline Co. - Louisiana as posted in Platts Inside FERC’s 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).
|
|
Period
|
Underlying
|
Notional Volume
|
Commodity
Price
We Receive
|
Commodity
Price
We Pay
|
Fair Value
Asset
(In Thousands)
|
Fair Value
Liability
(In Thousands)
|
||||||
|
January 2012-December 2012
|
Natural Gasoline
|
12,000 (BBL)
|
Index
|
$2.340/Gal
|
$ | — | $ | 13 | ||||
|
January 2012-December 2012
|
Natural Gas
|
120,000 (MMBTU)
|
Index
|
$4.87/Mmbtu
|
200 | — | ||||||
|
January 2012-December 2012
|
Natural Gas
|
240,000 (MMBTU)
|
Index
|
$4.96/Mmbtu
|
422 | — | ||||||
|
January 2012-December 2012
|
Crude Oil
|
24,000 (BBL)
|
Index
|
$88.63/bbl
|
— | 245 | ||||||
|
January 2012-December 2012
|
Natural Gasoline
|
12,000 (BBL)
|
Index
|
$90.20/bbl
|
— | 104 | ||||||
| $ | 622 | $ | 362 | |||||||||
|
Page
|
|
|
Report of Independent Registered Public Accounting Firm
|
76
|
|
Report of Independent Registered Public Accounting Firm on Internal Controls
|
77
|
|
Consolidated Balance Sheets as of December 31, 2011 and 2010
|
78
|
|
Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009
|
79
|
|
Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010 and 2009
|
80
|
|
Consolidated Statements of Changes in Capital for the years ended December 31, 2011, 2010 and 2009
|
81
|
|
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009
|
82
|
|
Notes to the Consolidated Financial Statements
|
83
|
|
December 31,
|
||||||||
|
2011
|
2010
|
|||||||
|
(Dollars in thousands)
|
||||||||
|
Assets
|
||||||||
|
Cash
|
$ | 266 | $ | 11,380 | ||||
|
Accounts and other receivables, less allowance for doubtful accounts of $3,021 and $2,528, respectively
|
126,461 | 95,276 | ||||||
|
Product exchange receivables
|
17,646 | 9,099 | ||||||
|
Inventories
|
78,163 | 52,616 | ||||||
|
Due from affiliates
|
5,968 | 6,437 | ||||||
|
Fair value of derivatives
|
622 | 2,142 | ||||||
|
Other current assets
|
1,978 | 2,784 | ||||||
|
Total current assets
|
231,104 | 179,734 | ||||||
|
Property, plant and equipment, at cost
|
711,052 | 632,456 | ||||||
|
Accumulated depreciation
|
(233,710 | ) | (200,276 | ) | ||||
|
Property, plant and equipment, net
|
477,342 | 432,180 | ||||||
|
Goodwill
|
37,268 | 37,268 | ||||||
|
Investment in unconsolidated entities
|
170,497 | 98,217 | ||||||
|
Debt issuance costs, net
|
13,330 | 13,497 | ||||||
|
Other assets
|
19,568 | 24,582 | ||||||
| $ | 949,109 | $ | 785,478 | |||||
|
Liabilities and Partners’ Capital
|
||||||||
|
Current installments of long-term debt and capital lease obligations
|
$ | 1,261 | $ | 1,121 | ||||
|
Trade and other accounts payable
|
125,970 | 82,837 | ||||||
|
Product exchange payables
|
37,313 | 22,353 | ||||||
|
Due to affiliates
|
18,485 | 6,957 | ||||||
|
Income taxes payable
|
893 | 811 | ||||||
|
Fair value of derivatives
|
362 | 282 | ||||||
|
Other accrued liabilities
|
11,022 | 10,034 | ||||||
|
Total current liabilities
|
195,306 | 124,395 | ||||||
|
Long-term debt and capital leases, less current maturities
|
458,941 | 372,862 | ||||||
|
Deferred income taxes
|
7,657 | 8,213 | ||||||
|
Fair value of derivatives
|
— | 4,100 | ||||||
|
Other long-term obligations
|
1,589 | 1,102 | ||||||
|
Total liabilities
|
663,493 | 510,672 | ||||||
|
Partners’ capital
|
284,990 | 273,387 | ||||||
|
Accumulated other comprehensive loss
|
626 | 1,419 | ||||||
|
Total partners’ capital
|
285,616 | 274,806 | ||||||
|
Commitments and contingencies
|
||||||||
| $ | 949,109 | $ | 785,478 | |||||
|
Year Ended December 31,
|
||||||||||||
|
2011
|
2010
|
2009 ¹ | ||||||||||
|
(Dollars in thousands, except per unit amounts)
|
||||||||||||
|
Revenues:
|
||||||||||||
|
Terminalling and storage *
|
$ | 77,283 | $ | 67,117 | $ | 69,710 | ||||||
|
Marine transportation *
|
76,936 | 77,642 | 68,480 | |||||||||
|
Sulfur services *
|
11,400 | — | — | |||||||||
|
Product sales: *
|
||||||||||||
|
Natural gas services
|
733,087 | 554,482 | 408,982 | |||||||||
|
Sulfur services
|
263,644 | 165,078 | 79,629 | |||||||||
|
Terminalling and storage
|
74,723 | 47,799 | 35,584 | |||||||||
| 1,071,454 | 767,359 | 524,195 | ||||||||||
|
Total revenues
|
1,237,073 | 912,118 | 662,385 | |||||||||
|
Costs and expenses:
|
||||||||||||
|
Cost of products sold: (excluding depreciation and amortization)
|
||||||||||||
|
Natural gas services *
|
704,073 | 527,232 | 382,542 | |||||||||
|
Sulfur services *
|
219,697 | 122,121 | 43,386 | |||||||||
|
Terminalling and storage
|
67,134 | 44,549 | 31,331 | |||||||||
| 990,904 | 693,902 | 457,259 | ||||||||||
|
Expenses:
|
||||||||||||
|
Operating expenses *
|
140,197 | 116,402 | 117,438 | |||||||||
|
Selling, general and administrative *
|
22,665 | 21,118 | 19,775 | |||||||||
|
Depreciation and amortization
|
44,957 | 40,656 | 39,506 | |||||||||
|
Total costs and expenses
|
1,198,723 | 872,078 | 633,978 | |||||||||
|
Other operating income
|
1,326 | 136 | 6,013 | |||||||||
|
Operating income
|
39,676 | 40,176 | 34,420 | |||||||||
|
Other income (expense):
|
||||||||||||
|
Equity in earnings of unconsolidated entities
|
9,536 | 9,792 | 7,044 | |||||||||
|
Interest expense
|
(24,518 | ) | (33,716 | ) | (18,995 | ) | ||||||
|
Other, net
|
233 | 287 | 326 | |||||||||
|
Total other income (expense)
|
(14,749 | ) | (23,637 | ) | (11,625 | ) | ||||||
|
Net income before taxes
|
24,927 | 16,539 | 22,795 | |||||||||
|
Income tax benefit (expense)
|
(585 | ) | (517 | ) | (592 | ) | ||||||
|
Net income
|
$ | 24,342 | $ | 16,022 | $ | 22,203 | ||||||
|
General partner’s interest in net income
|
$ | 5,289 | $ | 3,869 | $ | 3,249 | ||||||
|
Limited partners’ interest in net income
|
$ | 17,945 | $ | 11,045 | $ | 17,179 | ||||||
|
Net income per limited partner unit - basic and diluted
|
$ | 0.92 | $ | 0.63 | $ | 1.17 | ||||||
|
Weighted average limited partner units - basic
|
19,545,427 | 17,525,089 | 14,680,807 | |||||||||
|
Weighted average limited partner units - diluted
|
19,546,705 | 17,525,989 | 14,684,775 | |||||||||
|
Revenues:
|
||||||||||||
|
Terminalling and storage
|
$ | 54,211 | $ | 46,823 | $ | 19,998 | ||||||
|
Marine transportation
|
23,478 | 28,194 | 19,370 | |||||||||
|
Product Sales
|
15,561 | 14,998 | 5,838 | |||||||||
|
Costs and expenses:
|
||||||||||||
|
Cost of products sold: (excluding depreciation and amortization)
|
||||||||||||
|
Natural gas services
|
106,312 | 79,321 | 56,914 | |||||||||
|
Sulfur services
|
18,314 | 16,061 | 12,583 | |||||||||
|
Expenses:
|
||||||||||||
|
Operating expenses
|
59,134 | 49,286 | 37,284 | |||||||||
|
Selling, general and administrative
|
12,852 | 10,918 | 7,162 | |||||||||
|
Year Ended December 31,
|
||||||||||||
|
2011
|
2010
|
2009
|
||||||||||
|
(Dollars in thousands)
|
||||||||||||
|
Net income
|
$ | 24,342 | $ | 16,022 | $ | 22,203 | ||||||
|
Changes in fair values of commodity cash flow hedges
|
1,011 | 143 | 14 | |||||||||
|
Commodity cash flow hedging (gains) losses reclassified to earnings
|
(1,822 | ) | (617 | ) | (2,646 | ) | ||||||
|
Changes in fair value of interest rate cash flow hedges
|
— | (241 | ) | (1,854 | ) | |||||||
|
Interest rate cash flow hedging losses reclassified to earnings
|
18 | 4,210 | 7,345 | |||||||||
|
Comprehensive income
|
$ | 23,549 | $ | 19,517 | $ | 25,062 | ||||||
|
Partners’ Capital
|
||||||||||||||||||||||||||||||||
|
Parent Net
|
Common
|
Subordinated
|
General
Partner
|
Accumulated
Comprehensive
Income
|
||||||||||||||||||||||||||||
|
Investment
|
Units
|
Amount
|
Units
|
Amount
|
Amount
|
Amount
|
Total
|
|||||||||||||||||||||||||
|
(Dollars in thousands)
|
||||||||||||||||||||||||||||||||
|
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 | ) | |||||||||||||||||||||
|
Contributions 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 | |||||||||||||||||
|
Net Income
|
— | — | 12,153 | — | — | 3,869 | — | 16,022 | ||||||||||||||||||||||||
|
Recognition of beneficial conversion feature
|
— | — | (1,108 | ) | — | 1,108 | — | — | — | |||||||||||||||||||||||
|
Follow-on public offerings
|
— | 2,650,000 | 78,600 | — | — | — | — | 78,600 | ||||||||||||||||||||||||
|
Redemption of common units
|
— | (1,000,000 | ) | (28,070 | ) | — | — | — | — | (28,070 | ) | |||||||||||||||||||||
|
General partner contribution
|
— | — | — | — | — | 1,089 | — | 1,089 | ||||||||||||||||||||||||
|
Excess purchase price over carrying value of acquired assets
|
— | — | (4,590 | ) | — | — | — | — | (4,590 | ) | ||||||||||||||||||||||
|
Cash distributions ($3.00 per unit)
|
— | — | (51,886 | ) | — | — | (4,810 | ) | — | (56,696 | ) | |||||||||||||||||||||
|
Unit-based compensation
|
— | 3,500 | 113 | — | — | — | — | 113 | ||||||||||||||||||||||||
|
Purchase of treasury units
|
— | (3,500 | ) | (108 | ) | — | — | — | — | (108 | ) | |||||||||||||||||||||
|
Adjustment in fair value of derivatives
|
— | — | — | — | — | — | 3,495 | 3,495 | ||||||||||||||||||||||||
|
Balances – December 31, 2010
|
$ | — | 17,707,832 | $ | 250,787 | 889,444 | $ | 17,721 | $ | 4,879 | $ | 1,419 | $ | 274,806 | ||||||||||||||||||
|
Net income
|
— | — | 19,053 | — | — | 5,289 | — | 24,342 | ||||||||||||||||||||||||
|
Recognition of beneficial conversion feature
|
— | — | (1,108 | ) | — | 1,108 | — | — | — | |||||||||||||||||||||||
|
Follow-on public offering
|
— | 1,874,500 | 70,330 | — | — | — | — | 70,330 | ||||||||||||||||||||||||
|
General partner contribution
|
— | — | — | — | — | 1,505 | — | 1,505 | ||||||||||||||||||||||||
|
Conversion of subordinated units to common units
|
— | 889,444 | 18,829 | (889,444 | ) | (18,829 | ) | — | — | — | ||||||||||||||||||||||
|
Cash distributions ($3.05 per unit)
|
— | — | (58,252 | ) | — | — | (6,245 | ) | — | (64,497 | ) | |||||||||||||||||||||
|
Excess purchase price over carrying value of acquired assets
|
— | — | (19,685 | ) | — | — | — | — | (19,685 | ) | ||||||||||||||||||||||
|
Unit-based compensation
|
— | 14,850 | 190 | — | — | — | — | 190 | ||||||||||||||||||||||||
|
Purchase of treasury units
|
— | ( 14,850 | ) | (582 | ) | — | — | — | — | (582 | ) | |||||||||||||||||||||
|
Adjustment in fair value of derivatives
|
— | — | — | — | — | — | (793 | ) | (793 | ) | ||||||||||||||||||||||
|
Balances – December 31, 2011
|
$ | — | 20,471,776 | $ | 279,562 | — | $ | — | $ | 5,428 | $ | 626 | $ | 285,616 | ||||||||||||||||||
|
Year Ended December 31,
|
||||||||||||
|
2011
|
2010
|
2009
|
||||||||||
|
(Dollars in thousands)
|
||||||||||||
|
Cash flows from operating activities:
|
||||||||||||
|
Net income
|
$ | 24,342 | $ | 16,022 | $ | 22,203 | ||||||
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
||||||||||||
|
Depreciation and amortization
|
44,957 | 40,656 | 39,506 | |||||||||
|
Amortization of deferred debt issue costs
|
3,755 | 4,814 | 1,689 | |||||||||
|
Amortization of discount on notes payable
|
351 | 269 | — | |||||||||
|
Deferred income taxes
|
(157 | ) | (415 | ) | 294 | |||||||
|
(Gain) loss on disposition or sale of property, plant, and equipment
|
898 | (136 | ) | (4,996 | ) | |||||||
|
Gain on involuntary conversion of property, plant, and equipment
|
— | — | (1,017 | ) | ||||||||
|
Equity in earnings of unconsolidated entities
|
(9,536 | ) | (9,792 | ) | (7,044 | ) | ||||||
|
Distributions from unconsolidated entities
|
— | — | 650 | |||||||||
|
Distribution in-kind from unconsolidated entities
|
12,704 | 10,545 | 5,826 | |||||||||
|
Non-cash mark-to-market on derivatives
|
(3,293 | ) | 380 | 2,526 | ||||||||
|
Other
|
190 | 113 | 98 | |||||||||
|
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
|
||||||||||||
|
Accounts and other receivables
|
(28,781 | ) | (17,863 | ) | (10,471 | ) | ||||||
|
Product exchange receivables
|
(8,547 | ) | (4,967 | ) | 2,792 | |||||||
|
Inventories
|
(25,547 | ) | (17,106 | ) | 7,135 | |||||||
|
Due from affiliates
|
469 | (3,386 | ) | 1,560 | ||||||||
|
Other current assets
|
407 | (1,444 | ) | 2,461 | ||||||||
|
Trade and other accounts payable
|
43,599 | 10,918 | (15,874 | ) | ||||||||
|
Product exchange payables
|
14,961 | 14,366 | (2,938 | ) | ||||||||
|
Due to affiliates
|
11,528 | (6,853 | ) | 4,133 | ||||||||
|
Income taxes payable
|
82 | 357 | 569 | |||||||||
|
Other accrued liabilities
|
988 | 5,382 | 871 | |||||||||
|
Change in other non-current assets and liabilities
|
3,500 | (4,342 | ) | (2,381 | ) | |||||||
|
Net cash provided by operating activities
|
86,870 | 37,518 | 47,592 | |||||||||
|
Cash flows from investing activities:
|
||||||||||||
|
Payments for property, plant, and equipment
|
(73,994 | ) | (17,907 | ) | (35,846 | ) | ||||||
|
Acquisitions, net of cash acquired
|
(16,815 | ) | (41,762 | ) | (327 | ) | ||||||
|
Payments for plant turnaround costs
|
(2,103 | ) | (1,090 | ) | — | |||||||
|
Proceeds from sale of property, plant, and equipment
|
1,025 | 2,419 | 19,445 | |||||||||
|
Insurance proceeds from involuntary conversion of property, plant and equipment
|
— | — | 2,224 | |||||||||
|
Investments in unconsolidated entities
|
(59,319 | ) | (20,110 | ) | — | |||||||
|
Return of investments from unconsolidated entities
|
2,892 | 2,470 | 877 | |||||||||
|
(Contributions to) unconsolidated entities for operations
|
(19,021 | ) | (748 | ) | (1,048 | ) | ||||||
|
Net cash used in investing activities
|
(167,335 | ) | (76,728 | ) | (14,675 | ) | ||||||
|
Cash flows from financing activities:
|
||||||||||||
|
Payments of long-term debt
|
(442,000 | ) | (441,868 | ) | (430,500 | ) | ||||||
|
Payments of notes payable and capital lease obligations
|
(1,132 | ) | (111 | ) | (1,482 | ) | ||||||
|
Proceeds from long-term debt
|
529,000 | 503,856 | 433,700 | |||||||||
|
Net proceeds from follow on public offering
|
70,330 | 78,600 | — | |||||||||
|
General partner contribution
|
1,505 | 1,089 | 1,324 | |||||||||
|
Redemption of common units
|
— | (28,070 | ) | — | ||||||||
|
Excess purchase price over carrying value of acquired assets
|
(19,685 | ) | (4,590 | ) | — | |||||||
|
Purchase of treasury units
|
(582 | ) | (108 | ) | (78 | ) | ||||||
|
Proceeds from issuance of common units
|
— | — | 20,000 | |||||||||
|
Payments of debt issuance costs
|
(3,588 | ) | (7,468 | ) | (10,446 | ) | ||||||
|
Cash distributions paid
|
(64,497 | ) | (56,696 | ) | (47,462 | ) | ||||||
|
Net cash provided by (used in) financing activities
|
69,351 | 44,634 | (34,944 | ) | ||||||||
|
Net increase(decrease) in cash
|
(11,114 | ) | 5,424 | (2,027 | ) | |||||||
|
Cash at beginning of period
|
11,380 | 5,956 | 7,983 | |||||||||
|
Cash at end of period
|
$ | 266 | $ | 11,380 | $ | 5,956 | ||||||
|
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 | ||||||
|
Purchase of assets under note payable
|
$ | — | $ | 7,354 | $ | — | ||||||
|
(1)
|
ORGANIZATION AND DESCRIPTION OF BUSINESS
|
|
(2)
|
SIGNIFICANT ACCOUNTING POLICIES
|
|
Years Ended December 31,
|
||||||||||||
|
2011
|
2010
|
2009
|
||||||||||
|
Net income attributable to Martin Midstream Partners L. P
|
$ | 24,342 | $ | 16,022 | $ | 22,203 | ||||||
|
Less pre-acquisition income allocated to Parent
|
— | — | 1,664 | |||||||||
|
Less general partner’s interest in net income:
|
||||||||||||
|
Distributions payable on behalf of IDRs
|
4,901 | 3,623 | 2,896 | |||||||||
|
Distributions payable on behalf of general partner interest
|
1,344 | 1,187 | 949 | |||||||||
|
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest
|
(956 | ) | (941 | ) | (596 | ) | ||||||
|
Less beneficial conversion feature
|
1,108 | 1,108 | 111 | |||||||||
|
Limited partners’ interest in net income
|
$ | 17,945 | $ | 11,045 | $ | 17,179 | ||||||
|
(3)
|
FAIR VALUE MEASUREMENTS
|
|
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.
|
|
Fair Value Measurements at Reporting Date Using
|
||||||||||||||||
|
Quoted Prices in
Active Markets
for
Identical Assets
|
Significant
Other
Observable
Inputs
|
Significant
Unobservable
Inputs
|
||||||||||||||
|
Description
|
December 31,
2011
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||
|
Assets
|
||||||||||||||||
|
Natural gas derivatives
|
$ | 622 | $ | — | $ | 622 | $ | — | ||||||||
|
Total assets
|
$ | 622 | $ | — | $ | 622 | $ | — | ||||||||
|
Liabilities
|
||||||||||||||||
|
Crude oil derivatives
|
245 | — | 245 | — | ||||||||||||
|
Natural gas liquids derivatives
|
117 | — | 117 | — | ||||||||||||
|
Total liabilities
|
$ | 362 | $ | — | $ | 362 | $ | — | ||||||||
|
Fair Value Measurements at Reporting Date Using
|
||||||||||||||||
|
Quoted Prices in
Active Markets
for
Identical Assets
|
Significant
Other
Observable
Inputs
|
Significant
Unobservable
Inputs
|
||||||||||||||
|
Description
|
December 31,
2010
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||
|
Assets
|
||||||||||||||||
|
Interest rate derivatives
|
$ | 1,941 | $ | — | $ | 1,941 | $ | — | ||||||||
|
Natural gas derivatives
|
201 | — | 201 | — | ||||||||||||
|
Total assets
|
$ | 2,142 | $ | — | $ | 2,142 | $ | — | ||||||||
|
Liabilities
|
||||||||||||||||
|
Interest rate derivatives
|
$ | 3,930 | $ | — | $ | 3,930 | $ | — | ||||||||
|
Natural gas derivatives
|
28 | — | 28 | — | ||||||||||||
|
Crude oil derivatives
|
177 | — | 177 | — | ||||||||||||
|
Natural gas liquids derivatives
|
247 | — | 247 | — | ||||||||||||
|
Total liabilities
|
$ | 4,382 | $ | — | $ | 4,382 | $ | — | ||||||||
|
|
•
|
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. The estimated fair value of the Senior Notes was approximately $210,500 as of December 31, 2011, based on market prices of similar debt at December 31, 2011.
|
|
(4)
|
RECENT ACCOUNTING PRONOUNCEMENTS
|
|
(5)
|
ACQUISITIONS
|
|
Property, plant and equipment
|
9,925 | |||
|
Other assets
|
15,090 | |||
| $ | 25,015 |
|
(6)
|
ISSUANCE OF COMMON UNITS
|
|
(7)
|
INVENTORIES
|
|
2011
|
2010
|
|||||||
|
Natural gas liquids
|
$ | 25,664 | $ | 19,775 | ||||
|
Sulfur
|
24,335 | 15,933 | ||||||
|
Sulfur Based Products
|
14,857 | 9,027 | ||||||
|
Lubricants
|
11,012 | 5,267 | ||||||
|
Other
|
2,295 | 2,614 | ||||||
| $ | 78,163 | $ | 52,616 | |||||
|
(8)
|
PROPERTY, PLANT AND EQUIPMENT
|
|
Depreciable Lives
|
2011
|
2010
|
||||||||||
|
Land
|
— | $ | 19,446 | $ | 20,200 | |||||||
|
Improvements to land and buildings
|
10-25 years
|
73,432 | 53,655 | |||||||||
|
Transportation equipment
|
3-7 years
|
1,848 | 1,816 | |||||||||
|
Storage equipment
|
5-20 years
|
68,297 | 62,372 | |||||||||
|
Marine vessels
|
4-25 years
|
228,043 | 226,376 | |||||||||
|
Operating equipment
|
3-20 years
|
265,314 | 253,271 | |||||||||
|
Furniture, fixtures and other equipment
|
3-20 years
|
2,327 | 1,656 | |||||||||
|
Construction in progress
|
52,345 | 13,110 | ||||||||||
| $ | 711,052 | $ | 632,456 | |||||||||
|
(9)
|
GOODWILL AND OTHER INTANGIBLE ASSETS
|
|
2011
|
2010
|
|||||||
|
Carrying amount of goodwill:
|
||||||||
|
Terminalling and storage
|
$ | 883 | $ | 883 | ||||
|
Natural gas services
|
29,010 | 29,010 | ||||||
|
Sulfur services
|
5,349 | 5,349 | ||||||
|
Marine transportation
|
2,026 | 2,026 | ||||||
| $ | 37,268 | $ | 37,268 | |||||
|
(10)
|
LEASES
|
|
Fiscal year
|
Operating
Leases
|
Capital
Leases
|
||||||
|
2012
|
$ | 11,776 | $ | 1,138 | ||||
|
2013
|
7,975 | 1,147 | ||||||
|
2014
|
7,015 | 1,169 | ||||||
|
2015
|
6,297 | 1,169 | ||||||
|
2016
|
5,564 | 5,465 | ||||||
|
Thereafter
|
8,738 | — | ||||||
|
Total
|
$ | 47,365 | 10,088 | |||||
|
Less amounts representing interest costs
|
4,057 | |||||||
|
Present value of net minimum capital lease payments
|
6,031 | |||||||
|
Less current installments
|
193 | |||||||
|
Present value of net minimum capital lease payments, excluding current installments
|
$ | 5,838 | ||||||
|
(11)
|
INVESTMENT IN UNCONSOLIDATED ENTITIES AND JOINT VENTURES
|
|
Waskom
|
PIPE
|
Matagorda
|
Redbird
|
Total
|
||||||||||||||||
|
Investment in unconsolidated entities, December 31, 2009
|
$ | 75,844 | $ | 1,401 | $ | 3,337 | $ | — | $ | 80,582 | ||||||||||
|
Distributions in kind
|
(10,545 | ) | — | — | — | (10,545 | ) | |||||||||||||
|
Contributions to unconsolidated entities:
|
||||||||||||||||||||
|
Cash contributions
|
— | — | — | — | — | |||||||||||||||
|
Contributions to unconsolidated entities for operations
|
628 | 120 | — | — | 748 | |||||||||||||||
|
Cash contributions to fund asset acquisition
|
20,110 | — | — | — | 20,110 | |||||||||||||||
|
Return of investments
|
(2,100 | ) | (30 | ) | (340 | ) | — | (2,470 | ) | |||||||||||
|
Equity in earnings:
|
||||||||||||||||||||
|
Equity in earnings (losses) from operations
|
10,381 | (165 | ) | 170 | — | 10,386 | ||||||||||||||
|
Amortization of excess investment
|
(550 | ) | (15 | ) | (29 | ) | — | (594 | ) | |||||||||||
|
Investment in unconsolidated entities, December 31, 2010
|
$ | 93,768 | $ | 1,311 | $ | 3,138 | $ | — | $ | 98,217 | ||||||||||
|
Distributions in kind
|
(12,704 | ) | — | — | — | (12,704 | ) | |||||||||||||
|
Contributions to unconsolidated entities:
|
||||||||||||||||||||
|
Cash contributions (See Note 5)
|
— | — | — | 59,319 | 59,319 | |||||||||||||||
|
Contributions to unconsolidated entities for operations
|
13,889 | 25 | 170 | 4,937 | 19,021 | |||||||||||||||
|
Return of investments
|
(1,200 | ) | — | (260 | ) | (1,432 | ) | (2,892 | ) | |||||||||||
|
Equity in earnings:
|
||||||||||||||||||||
|
Equity in earnings (losses) from operations
|
9,693 | (30 | ) | 343 | 124 | 10,130 | ||||||||||||||
|
Amortization of excess investment
|
(550 | ) | (15 | ) | (29 | ) | — | (594 | ) | |||||||||||
|
Investment in unconsolidated entities, December 31, 2011
|
$ | 102,896 | $ | 1,291 | $ | 3,362 | $ | 62,948 | $ | 170,497 | ||||||||||
|
As of December 31,
|
Years ended December 31,
|
|||||||||||||||
|
Total
Assets
|
Partners’
Capital
|
Revenues
|
Net Income
|
|||||||||||||
|
2011
|
||||||||||||||||
|
Waskom
|
$ | 146,655 | $ | 126,863 | $ | 129,119 | $ | 19,385 | ||||||||
|
2010
|
||||||||||||||||
|
Waskom
|
$ | 122,057 | $ | , 107,508 | $ | 124,122 | $ | 20,762 | ||||||||
|
2009
|
||||||||||||||||
|
Waskom
|
$ | 79,604 | $ | 70,561 | $ | 71,044 | $ | 13,867 | ||||||||
|
(12)
|
LONG-TERM DEBT AND CAPITAL LEASES
|
|
December 31,
2011
|
December 31,
2010
|
|||||||
|
$200,000 Senior notes, 8.875% interest, net of unamortized discount of $2,192 and $2,543, respectively, issued March 2010 and due April 2018, unsecured **
|
$ | 197,808 | $ | 197,457 | ||||
|
$375,000 Revolving loan facility at variable interest rate (2.81%* weighted average at December 31, 2011), due April 2016 secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in the Partnership’s operating subsidiaries and equity method investees ***
|
250,000 | 163,000 | ||||||
|
$7,354 Note payable to bank, interest rate at 7.50%, maturity date of January 2017, secured by equipment
|
6,363 | 7,354 | ||||||
|
Capital lease obligations
|
6,031 | 6,172 | ||||||
|
Total long-term debt and capital lease obligations
|
460,202 | 373,983 | ||||||
|
Less current installments
|
1,261 | 1,121 | ||||||
|
Long-term debt and capital lease obligations, net of current installments
|
$ | 458,941 | $ | 372,862 | ||||
|
(13)
|
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
|
| Transaction Type |
Total
Volume
Per Month
|
Pricing Terms
|
Remaining Terms
of Contracts
|
Fair Value
|
|||
|
Mark to Market Derivatives:
:
|
|||||||
|
Natural Gasoline Swap
|
1,000 BBL
|
Fixed price of $90.20/bbl settled against WTI NYMEX average monthly closings
|
January 2012 to
December 2012
|
$ | (104 | ) | |
|
Natural Gasoline Swap
|
1,000 BBL
|
Fixed price of $2.34/gal settled against Mont Belvieu Non-TET OPIS Average
|
January 2012 to
December 2012
|
(13 | ) | ||
| Total commodity swaps not designated as hedging instruments | $ | (117 | ) | ||||
|
Cash Flow Hedges
:
|
|||||||
|
Natural Gas Swap
|
10,000 Mmbtu
|
Fixed price of $4.87/Mmbtu settled against IF_ANR_LA first of the month posting
|
January 2012 to
December 2012
|
200 | |||
|
Natural Gas Swap
|
20,000 Mmbtu
|
Fixed price of $4.96/Mmbtu settled against IF_ANR_LA first of the month posting
|
January 2012 to
December 2012
|
422 | |||
|
Crude Oil Swap
|
2,000 BBL
|
Fixed price of $88.63/bbl settled against WTI NYMEX average monthly closings
|
January 2012 to
December 2012
|
(245 | ) | ||
|
Total commodity swaps designated as hedging instruments
|
$ | 377 | |||||
|
Total net fair value of commodity derivatives
|
$ | 260 | |||||
|
Fair Values of Derivative Instruments in the Consolidated Balance Sheet
|
||||||||||||||||||
|
Derivative Assets
|
Derivative Liabilities
|
|||||||||||||||||
|
Fair Values
|
Fair Values
|
|||||||||||||||||
|
December 31,
|
December 31,
|
|||||||||||||||||
|
Balance Sheet Location
|
2011
|
2010
|
Balance Sheet Location
|
2011
|
2010
|
|||||||||||||
|
Derivatives designated as hedging instruments:
|
Current Assets:
|
Current Liabilities:
|
||||||||||||||||
|
Interest rate contracts
|
Fair value of derivatives
|
$ | — | $ | — |
Fair value of derivatives
|
$ | — | $ | — | ||||||||
|
Commodity contracts
|
Fair value of derivatives
|
622 | 201 |
Fair value of derivatives
|
245 | 230 | ||||||||||||
| 622 | 201 | 245 | 230 | |||||||||||||||
|
Non-current Assets:
|
Non-current Liabilities:
|
|||||||||||||||||
|
Interest rate contracts
|
Fair value of derivatives
|
— | — |
Fair value of derivatives
|
— | — | ||||||||||||
|
Commodity contracts
|
Fair value of derivatives
|
— | — |
Fair value of derivatives
|
— | 171 | ||||||||||||
| — | — | — | 171 | |||||||||||||||
|
Total derivatives designated as hedging instruments
|
$ | 622 | $ | 201 | $ | 245 | $ | 401 | ||||||||||
|
Derivatives not designated as hedging instruments:
|
Current Assets:
|
Current Liabilities:
|
||||||||||||||||
|
Interest rate contracts
|
Fair value of derivatives
|
$ | — | $ | 1,941 |
Fair value of derivatives
|
$ | — | $ | — | ||||||||
|
Commodity contracts
|
Fair value of derivatives
|
— | — |
Fair value of derivatives
|
117 | 51 | ||||||||||||
| — | 1,941 | 117 | 51 | |||||||||||||||
|
Non-current Assets:
|
Non-current Liabilities:
|
|||||||||||||||||
|
Interest rate contracts
|
Fair value of derivatives
|
— | — |
Fair value of derivatives
|
— | 3,930 | ||||||||||||
|
Commodity contracts
|
Fair value of derivatives
|
— | — |
Fair value of derivatives
|
— | — | ||||||||||||
| — | — | — | 3,930 | |||||||||||||||
|
Total derivatives not designated as hedging instruments
|
$ | — | $ | 2,142 | $ | 117 | $ | 3,981 | ||||||||||
|
Effect of Derivative Instruments on the Consolidated Statement of Operations
For the Years Ended December 31, 2011, 2010 and 2009
|
||||||||||||||||||||||||||||||||||||||
|
Effective Portion
|
Ineffective Portion and Amount
Excluded from Effectiveness Testing
|
|||||||||||||||||||||||||||||||||||||
|
Amount of Gain or (Loss)
Recognized in OCI on Derivatives
|
Location of Gain or (Loss) Reclassified from Accumulated OCI into Income
|
Amount of Gain or (Loss)
Reclassified from Accumulated
OCI into Income
|
Location of Gain or (Loss) Recognized in Income on Derivatives
|
Amount of Gain or (Loss)
Recognized in Income on
Derivatives
|
||||||||||||||||||||||||||||||||||
|
2011
|
2010
|
2009
|
2011
|
2010
|
2009
|
2011
|
2010
|
2009
|
||||||||||||||||||||||||||||||
|
Derivatives designated as hedging instruments:
|
||||||||||||||||||||||||||||||||||||||
|
Interest rate contracts
|
$ | — | (241 | ) | $ | (1,854 | ) |
Interest Expense
|
$ | (18 | ) | $ | (4,210 | ) | $ | (7,345 | ) |
Interest
Expense
|
$ | — | $ | — | $ | — | ||||||||||||||
|
Commodity contracts
|
1,011 | 143 | 14 |
Natural Gas
Services Revenues
|
1,785 | 547 | 2,667 |
Natural Gas
Services Revenues
|
37 | 70 | (21 | ) | ||||||||||||||||||||||||||
|
Total derivatives designated as hedging instruments
|
$ | 1,011 | $ | (98 | ) | $ | (1,840 | ) | $ | 1,767 | $ | (3,663 | ) | $ | (4,678 | ) | $ | 37 | $ | 70 | $ | (21 | ) | |||||||||||||||
|
(14)
|
RELATED PARTY TRANSACTIONS
|
|
|
·
|
providing terminalling, refining, processing, distribution and midstream logistical services for hydrocarbon products and by-products;
|
|
|
·
|
providing marine and other transportation of hydrocarbon products and by-products; and
|
|
|
·
|
manufacturing and marketing fertilizers and related sulfur-based products.
|
|
|
·
|
the ownership and/or operation on our behalf of any asset or group of assets owned by us or our affiliates;
|
|
|
·
|
any business operated by Martin Resource Management, including the following:
|
|
|
o
|
providing land transportation of various liquids,
|
|
|
o
|
distributing fuel oil, sulfuric acid, marine fuel and other liquids,
|
|
|
o
|
providing marine bunkering and other shore-based marine services in Alabama, Louisiana, Mississippi and Texas,
|
|
|
o
|
operating a crude oil gathering business in Stephens, Arkansas,
|
|
|
o
|
operating an underground NGL storage facility in Arcadia, Louisiana,
|
|
|
o
|
building and marketing sulfur processing equipment, and
|
|
|
o
|
developing an underground natural gas storage facility in Arcadia, Louisiana;
|
|
|
·
|
any business that Martin Resource Management acquires or constructs that has a fair market value of less than $5.0 million;
|
|
|
·
|
any business that Martin Resource Management acquires or constructs that has a fair market value of $5.0 million or more if the Partnership has been offered the opportunity to purchase the business for fair market value, and the Partnership declines to do so with the concurrence of the conflicts committee; and
|
|
|
·
|
any business that Martin Resource Management acquires or constructs where a portion of such business includes a restricted business and the fair market value of the restricted business is $5.0 million or more and represents less than 20% of the aggregate value of the entire business to be acquired or constructed; provided that, following completion of the acquisition or construction, the Partnership will be provided the opportunity to purchase the restricted business.
|
|
Revenues:
|
2011
|
2010
|
2009
|
|||||||||
|
Terminalling and storage
|
$ | 54,211 | $ | 46,823 | $ | 19,998 | ||||||
|
Marine transportation
|
23,478 | 28,194 | 19,370 | |||||||||
|
Product sales:
|
||||||||||||
|
Natural gas services
|
7,196 | 7,686 | 238 | |||||||||
|
Sulfur services
|
8,151 | 7,146 | 5,445 | |||||||||
|
Terminalling and storage
|
214 | 166 | 155 | |||||||||
| 15,561 | 14,998 | 5,838 | ||||||||||
| $ | 93,250 | $ | 90,015 | $ | 45,206 | |||||||
|
Cost of products sold:
|
||||||||||||
|
Natural gas services
|
$ | 106,312 | $ | 79,321 | $ | 56,914 | ||||||
|
Sulfur services
|
18,314 | 16,061 | 12,583 | |||||||||
|
Terminalling and storage
|
195 | 298 | 287 | |||||||||
| $ | 124,821 | $ | 95,680 | $ | 69,784 | |||||||
|
Operating expenses
|
||||||||||||
|
Marine transportation
|
$ | 29,870 | $ | 26,730 | $ | 20,464 | ||||||
|
Natural gas services
|
2,673 | 2,245 | 1,491 | |||||||||
|
Sulfur services
|
6,573 | 5,271 | 4,496 | |||||||||
|
Terminalling and storage
|
20,018 | 15,040 | 10,833 | |||||||||
| $ | 59,134 | $ | 49,286 | $ | 37,284 | |||||||
|
Selling, general and administrative:
|
||||||||||||
|
Marine transportation
|
$ | 65 | $ | — | $ | — | ||||||
|
Natural gas services
|
5,311 | 4,729 | 1,116 | |||||||||
|
Sulfur services
|
2,704 | 2,398 | 2,504 | |||||||||
|
Indirect overhead allocation, net of reimbursement
|
4,772 | 3,791 | 3,542 | |||||||||
| $ | 12,852 | $ | 10,918 | $ | 7,162 | |||||||
|
(15)
|
PARTNERS’ CAPITAL
|
|
(16)
|
GAIN ON DISPOSAL OF ASSETS
|
|
(17)
|
STANOLIND TANK DAMAGE
|
|
(18)
|
INCOME TAXES
|
|
2011
|
2010
|
2009
|
||||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | 11 | $ | — | $ | (311 | ) | |||||
|
State
|
713 | 932 | 609 | |||||||||
| 724 | 932 | 298 | ||||||||||
|
Deferred:
|
||||||||||||
|
Federal
|
(139 | ) | (415 | ) | 294 | |||||||
| $ | 585 | $ | 517 | $ | 592 | |||||||
|
(19)
|
BUSINESS SEGMENTS
|
|
Operating
Revenues
|
Intersegment
Eliminations
|
Operating
Revenues
After
Eliminations
|
Depreciation
and
Amortization
|
Operating
Income
(Loss) after
Eliminations
|
Capital
Expenditures
|
|||||||||||||||||||
|
Year ended December 31, 2011:
|
||||||||||||||||||||||||
|
Terminalling and storage
|
$ | 156,420 | $ | (4,414 | ) | $ | 152,006 | $ | 18,983 | $ | 13,074 | $ | 43,795 | |||||||||||
|
Natural gas services
|
733,087 | — | 733,087 | 6,090 | 7,356 | 1,904 | ||||||||||||||||||
|
Sulfur services
|
275,044 | — | 275,044 | 6,725 | 34,595 | 16,158 | ||||||||||||||||||
|
Marine transportation
|
83,971 | (7,035 | ) | 76,936 | 13,159 | (6,485 | ) | 12,137 | ||||||||||||||||
|
Indirect selling, general, and administrative
|
— | — | — | — | (8,864 | ) | — | |||||||||||||||||
|
Total
|
$ | 1,248,522 | $ | (11,449 | ) | $ | 1,237,073 | $ | 44,957 | $ | 39,676 | $ | 73,994 | |||||||||||
|
Year ended December 31, 2010:
|
||||||||||||||||||||||||
|
Terminalling and storage
|
$ | 119,270 | $ | (4,354 | ) | $ | 114,916 | $ | 16,650 | $ | 14,256 | $ | 6,996 | |||||||||||
|
Natural gas services
|
554,482 | — | 554,482 | 5,023 | 5,616 | 1,645 | ||||||||||||||||||
|
Sulfur services
|
165,078 | — | 165,078 | 6,262 | 20,166 | 7,107 | ||||||||||||||||||
|
Marine transportation
|
82,635 | (4,993 | ) | 77,642 | 12,721 | 6,524 | 2,159 | |||||||||||||||||
|
Indirect selling, general, and administrative
|
— | — | — | — | (6,386 | ) | — | |||||||||||||||||
|
Total
|
$ | 921,465 | $ | (9,347 | ) | $ | 912,118 | $ | 40,656 | $ | 40,176 | $ | 17,907 | |||||||||||
|
Year ended December 31, 2009:
|
||||||||||||||||||||||||
|
Terminalling and storage
|
$ | 109,513 | $ | (4,219 | ) | $ | 105,294 | $ | 15,717 | $ | 17,899 | $ | 18,404 | |||||||||||
|
Natural gas services
|
408,989 | (7 | ) | 408,982 | 4,527 | 5,666 | 5,010 | |||||||||||||||||
|
Sulfur services
|
79,631 | (2 | ) | 79,629 | 6,151 | 13,776 | 7,909 | |||||||||||||||||
|
Marine transportation
|
72,103 | (3,623 | ) | 68,480 | 13,111 | 3,156 | 4,523 | |||||||||||||||||
|
Indirect selling, general, and administrative
|
— | — | — | — | (6,077 | ) | — | |||||||||||||||||
|
Total
|
$ | 670,236 | $ | (7,851 | ) | $ | 662,385 | $ | 39,506 | $ | 34,420 | $ | 35,846 | |||||||||||
|
Year Ended December 31,
|
||||||||||||
|
2011
|
2010
|
2009
|
||||||||||
|
Operating income
|
$ | 39,676 | $ | 40,176 | $ | 34,420 | ||||||
|
Equity in earnings of unconsolidated entities
|
9,536 | 9,792 | 7,044 | |||||||||
|
Interest expense
|
(24,518 | ) | (33,716 | ) | (18,995 | ) | ||||||
|
Other, net
|
233 | 287 | 326 | |||||||||
|
Income taxes
|
(585 | ) | (517 | ) | (592 | ) | ||||||
|
Net income
|
$ | 24,342 | $ | 16,022 | $ | 22,203 | ||||||
|
2011
|
2010
|
|||||||
|
Total assets:
|
||||||||
|
Terminalling and storage
|
$ | 231,764 | $ | 188,234 | ||||
|
Natural gas services
|
411,632 | 314,815 | ||||||
|
Sulfur services
|
162,289 | 138,224 | ||||||
|
Marine transportation
|
143,424 | 144,205 | ||||||
|
Total assets
|
$ | 949,109 | $ | 785,478 | ||||
|
(20)
|
QUARTERLY FINANCIAL INFORMATION
|
|
(
Unaudited)
|
||||||||||||||||
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
|||||||||||||
|
(Dollar in thousands, except per unit amounts)
|
||||||||||||||||
|
2011
|
||||||||||||||||
|
Revenues
|
$ | 283,036 | $ | 292,205 | $ | 316,309 | $ | 345,523 | ||||||||
|
Operating Income
|
13,511 | 10,566 | 8,128 | 7,471 | ||||||||||||
|
Equity in earnings of unconsolidated entities
|
2,376 | 2,793 | 1,784 | 2,583 | ||||||||||||
|
Net income
|
7,322 | 8,770 | 5,399 | 2,851 | ||||||||||||
|
Net income per limited partner unit
|
$ | 0.31 | $ | 0.37 | $ | 0.20 | $ | 0.06 | ||||||||
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
|||||||||||||
|
(Dollar in thousands, except per unit amounts)
|
||||||||||||||||
|
2010
|
||||||||||||||||
|
Revenues
|
$ | 242,676 | $ | 211,944 | $ | 195,387 | $ | 262,141 | ||||||||
|
Operating Income
|
7,563 | 9,102 | 7,703 | 15,808 | ||||||||||||
|
Equity in earnings of unconsolidated entities
|
2,176 | 2,342 | 2,951 | 2,323 | ||||||||||||
|
Net income
|
1,771 | 3,075 | 4,636 | 6,540 | ||||||||||||
|
Net income per limited partner unit
|
$ | 0.04 | $ | 0.10 | $ | 0.19 | $ | 0.30 | ||||||||
|
(21)
|
COMMITMENTS AND CONTINGENCIES
|
|
(22)
|
CONSOLIDATING FINANCIAL STATEMENTS
|
|
(23)
|
SUBSEQUENT EVENTS
|
|
Name
|
Age
|
Position with the General Partner
|
||
|
Ruben S. Martin
|
60
|
President, Chief Executive Officer and Director
|
||
|
Robert D. Bondurant
|
53
|
Executive Vice President and Chief Financial Officer
|
||
|
Randall L. Tauscher
|
46
|
Executive Vice President and Chief Operating Officer
|
||
|
Wesley M. Skelton
|
64
|
Executive Vice President, Chief Administrative Officer and Controller
|
||
|
Donald R. Neumeyer
|
64
|
Executive Vice President
|
||
|
Chris Booth
|
42
|
Vice President, General Counsel and Secretary
|
||
|
C. Scott Massey
|
59
|
Director
|
||
|
Howard Hackney
|
72
|
Director
|
||
|
Joe N. Averett, Jr.
|
69
|
Director
|
||
|
Charles H. Still
|
69
|
Director
|
||
|
Byron R. Kelley
|
64
|
Advisory Director
|
|
|
•
an equivalent number of shares of Martin Resource Management, or
|
|
|
•
cash based on the latest valuation of the shares of common stock of Martin Resource Management held by the ESOP.
|
|
Name and
Principal Position
|
Year
|
Salary ($)
|
Bonus ($)
|
Total Compensation
|
||||||||||
|
Ruben S. Martin President and Chief Executive Officer
|
2011
|
$ | 124,371 | $ | - | $ | 124,371 | |||||||
|
2010
|
$ | 100,099 | $ | - | $ | 100,099 | ||||||||
|
2009
|
$ | 91,579 | $ | - | $ | 91,579 | ||||||||
|
Robert D. Bondurant Executive Vice President and Chief Financial Officer
|
2011
|
$ | 125,761 | $ | - | $ | 125,761 | |||||||
|
2010
|
$ | 53,857 | $ | - | $ | 53,857 | ||||||||
|
2009
|
$ | 40,972 | $ | - | $ | 40,972 | ||||||||
|
Randall L. Tauscher Executive Vice President and Chief Operating Officer
|
2011
|
$ | 210,548 | $ | - | $ | 210,548 | |||||||
|
2010
|
$ | 163,644 | $ | 107,500 | $ | 271,144 | ||||||||
|
2009
|
$ | 242,282 | $ | 120,000 | $ | 363,282 | ||||||||
|
Wesley M. Skelton Executive Vice President, Controller and Chief Administrative Officer
|
2011
|
$ | 124,371 | $ | - | $ | 124,371 | |||||||
|
2010
|
$ | 117,404 | $ | - | $ | 117,404 | ||||||||
|
2009
|
$ | 118,544 | $ | - | $ | 118,544 | ||||||||
|
Donald R. Neumeyer Executive Vice President
|
2011
|
$ | 75,221 | $ | - | $ | 75,221 | |||||||
|
2010
|
$ | 52,653 | $ | - | $ | 52,653 | ||||||||
|
2009
|
$ | 44,296 | $ | - | $ | 44,296 | ||||||||
|
Chris H. Booth Vice President, General Counsel and Secretary
|
2011
|
$ | 88,814 | $ | - | $ | 88,814 | |||||||
|
2010
|
$ | 86,830 | $ | - | $ | 86,830 | ||||||||
|
2009
|
$ | 82,225 | $ | - | $ | 82,225 | ||||||||
|
Name
|
Fees Earned Paid in
Cash ($)
|
Stock
Awards ($)
(1)(2)
|
Total ($)
|
|||||||||
|
Ruben S. Martin
|
N/A | N/A | N/A | |||||||||
|
C. Scott Massey
|
$ | 50,000 | $ | 50,875 ¹ | $ | 100,875 | ||||||
|
Howard Hackney
|
$ | 50,000 | $ | 50,875 ¹ | $ | 100,875 | ||||||
|
Joe N. Averett, Jr.
|
$ | 50,000 | $ | 50,875 ¹ | $ | 100,875 | ||||||
|
Charles H. “Hank” Still
|
$ | 50,000 | $ | 50,875 ¹ | $ | 100,875 | ||||||
|
Byron R. Kelley
|
$ | 37,500 | $ | 50,875² | $ | 88,375 | ||||||
|
(1)
|
On May 2, 2011, the Partnership issued 1,250 restricted common units to each of four non-employee directors, C. Scott Massey, Howard Hackney, Joe N. Averett, Jr., and Charles H. “Hank” Still, under our long-term incentive plan. These restricted common units vest in equal installments of 312.5 units on January 24, 2012, 2013, 2014 and 2015, respectively. In calculating the fair value of the award, we multiplied the closing price of our common units on the NASDAQ on the date of grant, May 2, 2011, by the number of restricted common units granted to each director.
|
|
(2)
|
On May 2, 2011, we issued 1, 250 restricted common units to a non-employee advisory director, Byron R. Kelley, under our long-term incentive plan . These restricted common units vest in equal installments of 312.5 units on January 24, 2012, 2013, 2014 and 2015, respectively. In calculating the fair value of the award, we multiplied the closing price of our common units on the NASDAQ on the date of grant, May 2, 2011, by the number of restricted common units granted to the advisory director.
|
|
/s/ Howard Hackney
|
|
Howard Hackney, Committee Chair
|
|
/s/ Joe N. Averett, Jr.
|
|
Joe N. Averett Jr.
|
|
/s/ C. Scott Massey
|
|
C. Scott Massey
|
|
/s/ Charles H. Still
|
|
Charles H. Still
|
|
Name of Beneficial Owner(1)
|
Common Units
Beneficially
Owned
|
Percentage of
Common Units
Beneficially
Owned(2)
|
||||||
|
Martin Resource Management Corporation(3)
|
6,593,267 | 28.5 | % | |||||
|
Martin Resource LLC(3)
|
5,703,823 | 24.7 | % | |||||
|
Cross Oil Refining & Marketing Inc.(3)
|
889,444 | 3.8 | % | |||||
|
Scott D. Martin(4)
|
6,607,054 | 28.6 | % | |||||
|
Keeneland Capital LLC
|
6,593,267 | 28.5 | % | |||||
|
KCM LLC
|
6,593,267 | 28.5 | % | |||||
|
Ruben S. Martin(5)
|
6,650,808 | 28.8 | % | |||||
|
Donald R. Neumeyer
|
4,900 | — | ||||||
|
Wesley M. Skelton
|
4,612 | — | ||||||
|
Robert D. Bondurant
|
13,065 | — | ||||||
|
Chris Booth
|
2,198 | — | ||||||
|
Randall Tauscher
|
9,235 | — | ||||||
|
C. Scott Massey(6)(7)
|
10,500 | — | ||||||
|
Howard Hackney(6)
|
6,250 | — | ||||||
|
Joe N. Averett, Jr.(6)
|
4,250 | — | ||||||
|
Charles H. Still(6)
|
3,050 | — | ||||||
| Byron R. Kelley(6) | 1,250 | — | ||||||
|
All directors and executive officers as a group (11 persons)(8)
|
6,710,117 | 29.0 | % | |||||
|
(1)
|
The address for Martin Resource Management Corporation and all of the individuals listed in this table, unless otherwise indicated, is c/o Martin Midstream Partners L.P., 4200 Stone Road, Kilgore, Texas 75662.
|
|
(2)
|
The percent of class shown is less than one percent unless otherwise noted.
|
|
(3)
|
Martin Resource Management is the owner of Martin Resource LLC and Cross Oil Refining & Marketing Inc., and as such may be deemed to beneficially own the common units held by Martin Resource LLC and Cross Oil Refining & Marketing Inc. The 5,703,823 common units beneficially owned by Martin Resource Management through its ownership of Martin Resource LLC have been pledged as security to a third party to secure payment for a loan made by such third party. The 889,444 common units beneficially owned by Martin Resource Management through its ownership of Cross Oil Refining & Marketing Inc. have been pledged as security to a third party to secure payment for a loan made by such third party.
|
|
(4)
|
Includes 6,593,267 common units beneficially owned by Martin Resource Management Corporation through its ownership of Martin Resource LLC and Cross Oil Refining & Marketing, Inc. Scott D. Martin beneficially owns securities in Martin Resource Management representing approximately 27.6% of the voting stock thereof. As a result, Scott D. Martin may be deemed to be the beneficial owner of the common units and the subordinated units owned by Martin Resource Management.
|
|
(5)
|
Includes 6,593,267 common units beneficially owned by Martin Resource Management Corporation through its ownership of Martin Resource LLC and Cross Oil Refining & Marketing, Inc. Ruben S. Martin beneficially owns securities in Martin Resource Management representing approximately 23.6% of the voting stock thereof and serves as its Chairman of the Board and President. As a result, Ruben S. Martin may be deemed to be the beneficial owner of the common units and the subordinated units owned by Martin Resource Management.
|
|
(6)
|
On May 2, 2011, we issued 1, 250 restricted common units to a non-employee advisory director. These units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015.
|
|
(7)
|
Mr. Massey may be deemed to be the beneficial owner of 500 common units held by his wife.
|
|
(8)
|
The total for all directors and executive officers as a group includes the common units directly owned by such directors and executive officers as well as the common units beneficially owned by Martin Resource Management as Ruben S. Martin may be deemed to be the beneficial owner thereof.
|
|
Beneficial Ownership of
Common Stock
|
||||||||
|
Name of Beneficial Owner(1)
|
Number of
Shares
|
Percent of
Outstanding
|
||||||
|
Martin Resource Management Corporation Employee Stock Ownership Trust (2)
|
1,922.00 | 17.4 | % | |||||
|
CNRT LLC (3)
|
2,266.67 | 20.5 | % | |||||
|
RSM III Investments, Ltd. (4).
|
2,266.67 | 20.5 | % | |||||
|
Ruben S. Martin III Dynasty Trust (5)
|
640.00 | 5.8 | % | |||||
|
SKM Partnership, Ltd. (6)
|
2,560.00 | 23.2 | % | |||||
|
KCM LLC(13)(14)
|
4,472.00 | 40.5 | % | |||||
|
Keeneland Capital LLC(15)
|
4,472.00 | 40.5 | % | |||||
|
Scott D. Martin (6) (7)
|
3,049.00 | 27.6 | % | |||||
|
Martin Transport, Inc. (7)
|
40.00 | * | ||||||
|
Ruben S. Martin (3) (7) (8)
|
2,601.00 | 23.6 | % | |||||
|
Wesley M. Skelton (2) (10)(11) (12)
|
2,030.00 | 18.4 | % | |||||
|
Robert D. Bondurant (10) (11) (12)
|
200.00 | 1.8 | % | |||||
|
Donald R. Neumeyer (10) (11) (12)
|
116.00 | 1.1 | % | |||||
|
Randall L. Tauscher (10)(12)
|
85.00 | * | ||||||
|
Executive officers and directors as a group (5 individuals)
|
5,032.00 | 45.6 | % | |||||
|
(1)
|
The business address of each shareholder, director and executive officer of Martin Resource Management Corporation is c/o Martin Resource Management Corporation, 4200 Stone Road, Kilgore, Texas 75662.
|
|
(2)
|
Wesley M. Skelton is a co-trustee of the Martin Resource Management Corporation Employee Stock Ownership Trust and exercises shared control over the voting and disposition of the securities owned by this trust. As a result, he may be deemed to be the beneficial owner of the securities held by such trust; thus, the number of shares of common stock reported herein as beneficially owned by him includes the 1,922 shares owned by such trust. Mr. Skelton disclaims beneficial ownership of these 1,922 shares.
|
|
(3)
|
Ruben S. Martin is the president of RSM III Management Corp., which is the general partner of RSM III Investments Ltd., which is the sole member of CNRT LLC. Courtney Stovall and Robin Martin, as managers of CNRT LLC exercise control over the voting of the securities owned by this entity. However, as a result of his position with the general partner of the sole member of this entity, Ruben S. Martin may be deemed to be the beneficial owner of the securities held by such entity; thus, the number of shares of common stock reported herein as beneficially owned by such individual includes the 2,266.67 shares owned by such entity.
|
|
(4)
|
RSM III Investments Ltd. is the sole member of CNRT LLC and, as such, may be deemed to be the beneficial owner of the securities owned by CNRT LLC.
|
|
(5)
|
Bill Bankston is the trustee of the Ruben S. Martin III Dynasty Trust and exercises control over the voting and disposition of the securities owned by the trust. As a result, he may be deemed to be the beneficial owner of the securities held by the trust. These 640 shares have been pledged as security to a third party to secure payment for a loan made by such third party.
|
|
(6)
|
Scott D. Martin is the beneficial owner of the general partner of SKM Partnership, Ltd. and exercises control over the voting and disposition of the securities owned by this entity. As a result, he may be deemed to be the beneficial owner of the securities held by such entity; thus, the number of shares of common stock reported herein as beneficially owned by such individual includes the 2,560 shares owned by such entity.
|
|
(7)
|
Ruben S. Martin beneficially owns securities in Martin Resource Management representing approximately 23.6% of the voting stock thereof and serves as its Chairman of the Board and President. Scott D. Martin beneficially owns securities in Martin Resource Management representing approximately 27.6% of the voting stock thereof. Martin Transport, Inc. is a wholly owned subsidiary of Martin Resource Management. As a result, Ruben S. Martin may be deemed to be the beneficial owner of the securities held by Martin Transport, Inc.; thus, the number of shares of common stock reported herein as beneficially owned by Ruben S. Martin includes the 40 shares owned by Martin Transport, Inc.
|
|
(8)
|
Ruben S. Martin directly owns 294.33 shares of common stock.
|
|
(9)
|
Scott D. Martin directly owns 489 shares of common stock.
|
|
(10)
|
Messrs. Neumeyer, Skelton, Bondurant and Tauscher each have the right to acquire 30, 30, 50, and 50 shares, respectively, by virtue of options issued under Martin Resource Management’s nonqualified stock option plan.
|
|
(11)
|
Messrs. Neumeyer, Skelton and Bondurant own securities in Martin Resource Management Corporation of 36, 28 and 100 shares of common stock, respectively, obtained by the exercise of options issued under Martin Resource Management ’s nonqualified stock option plan.
|
|
(12)
|
Messrs. Neumeyer, Skelton, Bondurant and Tauscher own securities in Martin Resource Management of 50, 50, 50 and 35, restricted common shares, respectively, representing shares by virtue of restricted stock issued under Martin Resource Management’s 2007 Long-Term Incentive Plan. Twenty five percent of these shares have vested and have been reissued without restriction.
|
|
(13)
|
KCM LLC owns 1,423 shares of Martin Resource Management and holds options to purchase additional shares from Scott D. Martin; thus, the number of shares of common stock reported herein as beneficially owned by KCM LLC includes the 489 shares owned by Scott D. Martin.
|
|
(14)
|
KCM LLC owns 1,423 shares of Martin Resource Management and holds options to purchase additional shares from SKM Partnership Ltd.; thus, the number of shares of common stock reported herein as beneficially owned by KCM LLC includes the 2,560 shares owned by such entity.
|
|
(15)
|
Keeneland Capital LLC is the sole member of KCM LLC and, as such, may be deemed to be the beneficial owner of the securities owned by KCM LLC.
|
|
Number of
securities to be
issued upon exercise
of outstanding
options, Warrants
and rights
|
Weighted-average
exercise price of
outstanding options,
warrants and rights
|
Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a))
|
||||||||||
|
Plan Category
|
(a)
|
(b)
|
(c)
|
|||||||||
|
Equity compensation plans approved by security holders
|
N/A | N/A | N/A | |||||||||
|
Equity compensation plans not approved by security holders(1)
|
0 | $ | 0 | 694,650 | ||||||||
|
Total
|
0 | $ | 0 | 694,650 | ||||||||
|
(1)
|
Our general partner has adopted and maintains the Martin Midstream Partners L.P. Long-Term Incentive Plan. For a description of the material features of this plan, please see “Item 11. Executive Compensation – Employee Benefit Plans – Martin Midstream Partners L.P. Long-Term Incentive Plan”.
|
|
Formation Stage
|
|
|
The consideration received by our general partner and Martin Resource Management for the transfer of assets to us
|
·
4,253,362 subordinated units (All of the original 4,253,362 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. 850,672 subordinated units were converted on each of November 14, 2005, 2006, 2007 and 2008, respectively, and 850,674 subordinated units were converted on November 14, 2009)
|
|
·
2% general partner interest; and
·
the incentive distribution rights.
|
|
|
Operational Stage
|
|
|
Distributions of available cash to our general partner
|
We will generally make cash distributions 98% to our unitholders, including Martin Resource Management as holder of all of the subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level as a result of its incentive distribution rights.
|
|
Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual aggregate distribution of approximately $0.9 million on its 2.0% general partner interest.
|
|
|
Payments to our general partner and its affiliates
|
Martin Resource Management is entitled to reimbursement for all direct expenses it or our general partner incurs on our behalf. The direct expenses include the salaries and benefit costs employees of Martin Resource Management who provide services to us. Our general partner has sole discretion in determining the amount of these expenses. In addition to the direct expenses, Martin Resource Management is entitled to reimbursement for a portion of indirect general and administrative and corporate overhead expenses. Under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2011, 2010 and 2009, the Conflicts Committee of our general partner approved reimbursement amounts of $4.8, $3.8 and $3.5 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. Please read “Agreements — Omnibus Agreement” below.
|
|
Withdrawal or removal of our general partner
|
If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
|
|
Liquidation Stage
|
|
|
Liquidation
|
Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
|
|
·
|
providing terminalling and storage services for petroleum products and by-products;
|
|
·
|
providing marine transportation of petroleum products and by-products;
|
|
·
|
distributing NGLs; and
|
|
·
|
manufacturing and selling sulfur-based fertilizer products and other sulfur-related products.
|
|
·
|
the operation on our behalf of any asset or group of assets owned by us or our affiliates;
|
|
·
|
any business operated by Martin Resource Management, including the following:
|
|
·
|
providing land transportation of various liquids,
|
|
·
|
distributing fuel oil, asphalt, sulfuric acid, marine fuel and other liquids,
|
|
·
|
providing marine bunkering and other shore-based marine services in Alabama, Louisiana, Mississippi and Texas,
|
|
·
|
operating a crude oil gathering business in Stephens, Arkansas,
|
|
·
|
operating an underground NGL storage facility in Arcadia, Louisiana,
|
|
·
|
building and marketing of sulfur processing equipment,
|
|
·
|
developing an underground natural gas storage facilities in Arcadia, Louisiana, Perryville, Louisiana and Cadeville, Louisiana;
|
|
·
|
any business that Martin Resource Management acquires or constructs that has a fair market value of less than $5.0 million;
|
|
·
|
any business that Martin Resource Management acquires or constructs that has a fair market value of $5.0 million or more if we have been offered the opportunity to purchase the business for fair market value, and we decline to do so with the concurrence of our Conflicts Committee; and
|
|
·
|
any business that Martin Resource Management acquires or constructs where a portion of such business includes a restricted business and the fair market value of the restricted business is $5.0 million or more and represents less than 20% of the aggregate value of the entire business to be acquired or constructed; provided that, following completion of the acquisition or construction, we are provided the opportunity to purchase the restricted business.
|
|
2011
|
2010
|
|||||||
|
Audit fees
|
$ | 1,095,000(1) | $ | 1,122,800(1) | ||||
|
Audit related fees
|
16,809 | — | ||||||
|
Audit and audit related fees
|
1,111,809 | 1,122,800 | ||||||
|
Tax fees
|
142,930(2) | 117,730(2) | ||||||
|
All other fees
|
— | — | ||||||
|
Total fees
|
$ | 1,254,739 | $ | 1,240,530 | ||||
|
(1)
|
2011 and 2010 audit fees include fees for the annual integrated audit, the audit of Waskom Gas Processing Company and fees related to services in connection with transactions.
|
|
(2)
|
Tax fees are for services related to the review of our partnership K-1’s returns, and research and consultations on other tax related matters.
|
|
|
(1)
|
The following financial statements of Martin Midstream Partners L.P. and are included in Part II, Item 8:
|
|
|
(2)
|
Financial Statements of Waskom Gas Processing Company for the year ended December 31, 2011, an affiliate accounted for by the equity method, which constituted a significant subsidiary.
|
|
Martin Midstream Partners L.P.
|
|||
|
(Registrant)
|
|||
|
By:
|
Martin Midstream GP LLC
|
||
|
It’s General Partner
|
|||
|
Date: March 5, 2012
|
By:
|
/s/ Ruben S. Martin
|
|
|
Ruben S. Martin
|
|||
|
President and Chief Executive Officer
|
|||
|
Signature
|
Title
|
|
|
/s/ Ruben S. Martin
|
President, Chief Executive Officer and Director of Martin Midstream GP LLC (Principal Executive Officer)
|
|
|
Ruben S. Martin
|
||
|
/s/ Robert D. Bondurant
|
Executive Vice President and Chief Financial Officer of Martin Midstream GP LLC (Principal Financial Officer)
|
|
|
Robert D. Bondurant
|
||
|
/s/ Wesley M. Skelton
|
Executive Vice President, Chief Administrative Officer, Secretary and Controller of Martin Midstream GP LLC (Principal Accounting Officer)
|
|
|
Wesley M. Skelton
|
||
|
/s/ C. Scott Massey
|
Director of Martin Midstream GP LLC
|
|
|
C. Scott Massey
|
||
|
/s/ Howard Hackney
|
Director of Martin Midstream GP LLC
|
|
|
Howard Hackney
|
||
|
/s/ Joe N. Averett, Jr.
|
Director of Martin Midstream GP LLC
|
|
|
Joe N. Averett, Jr.
|
||
|
/s/ Charles H. Still
|
Director of Martin Midstream GP LLC
|
|
|
Charles H. Still
|
|
Exhibit
Number
|
Exhibit Name
|
|
3.1
|
Certificate of Limited Partnership of Martin Midstream Partners L.P. (the “Partnership”), dated June 21, 2002 (filed as Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
|
|
3.2
|
Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of November 25, 2009 (filed as Exhibit 10.1 to the Partnership’s Amendment to Current Report on Form 8-K/A, filed January 19, 2010, and incorporated herein by reference).
|
|
3.3
|
Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated January 31, 2011 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed February 1, 2011, and incorporated herein by reference).
|
|
3.4
|
Certificate of Limited Partnership of Martin Operating Partnership L.P. (the “Operating Partnership”), dated June 21, 2002 (filed as Exhibit 3.3 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
|
|
3.5
|
Amended and Restated Agreement of Limited Partnership of the Operating Partnership, dated November 6, 2002 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
|
|
3.6
|
Certificate of Formation of Martin Midstream GP LLC (the “General Partner”), dated June 21, 2002 (filed as Exhibit 3.5 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
|
|
3.7
|
Limited Liability Company Agreement of the General Partner, dated June 21, 2002 (filed as Exhibit 3.6 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 33-91706), filed July 1, 2002, and incorporated herein by reference).
|
|
3.8
|
Certificate of Formation of Martin Operating GP LLC (the “Operating General Partner”), dated June 21, 2002 (filed as Exhibit 3.7 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
|
|
3.9
|
Limited Liability Company Agreement of the Operating General Partner, dated June 21, 2002 (filed as Exhibit 3.8 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
|
|
4.1
|
Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).
|
|
4.2
|
Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed October 25, 2002, and incorporated herein by reference).
|
|
4.3
|
Indenture (including form of 8.875% Senior Note due 2018), dated as of March 26, 2010, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed March 26, 2010, and incorporated herein by reference).
|
|
4.4
|
Registration Rights Agreement, dated as of March 26, 2010, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (filed as Exhibit 4.2 to the Partnership’s Current Report on Form 8-K, filed March 26, 2010, and incorporated herein by reference).
|
|
10.1
|
Second Amended and Restated Credit Agreement, dated November 10, 2005, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders set forth therein (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed November 14, 2005, and incorporated herein by reference).
|
|
10.2
|
Second Amendment to Second Amended and Restated Credit Agreement, dated as of December 28, 2007, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., the financial institution parties to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed January 2, 2008, and incorporated herein by reference).
|
|
10.3
|
Third Amendment to Second Amended and Restated Credit Agreement, effective as of September 24, 2008, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., the financial institution parties to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed September 30, 2008, and incorporated herein by reference).
|
|
Exhibit
Number
|
Exhibit Name
|
|
10.4
|
Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of December 21, 2009, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline LLC, the financial institution parties to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed December 23, 2009, and incorporated herein by reference).
|
|
10.5
|
Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of January 14, 2010, among Martin Operating Partnership L.P., Martin Midstream Partners L.P., Martin Operating GP LLC, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., the financial institutions parties thereto, as lenders, and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed January 19, 2010, and incorporated herein by reference).
|
|
10.6
|
Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of March 26, 2010, among Martin Operating Partnership L.P., the Partnership, Martin Operating GP LLC, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., the financial institution parties to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed March 26, 2010, and incorporated herein by reference).
|
|
10.7
|
Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of April 15, 2011, among Martin Operating Partnership L.P., the Partnership, Martin Operating GP LLC, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline, LLC, the financial institutions party to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed April 21, 2011, and incorporated herein by reference).
|
|
10.8
|
Eighth Amendment to Second Amended and Restated Credit Agreement, dated as of September 7, 2011, among Martin Operating Partnership L.P., the Partnership, Martin Operating GP LLC, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline, LLC, the financial institutions party to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K/A, filed January 13, 2012, and incorporated herein by reference).
|
|
10.9
|
Ninth Amendment to Second Amended and Restated Credit Agreement, dated as of September 7, 2011, among Martin Operating Partnership L.P., the Partnership, Martin Operating GP LLC, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline, LLC, the financial institutions party to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q, filed November 7, 2011, and incorporated herein by reference).
|
|
10.10
|
Omnibus Agreement dated November 1, 2002, by and among Martin Resource Management, the General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
|
|
10.11
|
Amendment No. 1 to Omnibus Agreement, dated as of November 25, 2009, by and among Martin Resource Management, the General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, filed December 1, 2009, and incorporated herein by reference).
|
|
10.12
|
Motor Carrier Agreement dated January 1, 2006, by and between the Operating Partnership and Martin Transport, Inc. (filed as Exhibit 10.9 to the Partnership’s Annual Report on Form 10-K, filed March 2, 2011, and incorporated herein by reference).
|
|
Exhibit
Number
|
Exhibit Name
|
|
10.13
|
Contract for Marine Transportation dated January 1, 2006, by and between the Operating Partnership and Midstream Fuel Service, L.L.C. (filed as Exhibit 10.10 to the Partnership’s Annual Report on Form 10-K, filed March 2, 2011, and incorporated herein by reference).
|
|
10.14
|
Product Storage Agreement dated November 1, 2002, by and between Martin Underground Storage, Inc. and the Operating Partnership (filed as Exhibit 10.8 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
|
|
10.15
|
Marine Fuel Agreement dated November 1, 2002, by and between Martin Fuel Service LLC and the Operating Partnership (filed as Exhibit 10.9 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
|
|
10.16†
|
Martin Midstream Partners L.P. Long-Term Incentive Plan (filed as Exhibit 10.11 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
|
|
10.17†
|
Martin Midstream Partners L.P. Amended and Restated Long-Term Incentive Plan (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed January 26, 2006, and incorporated herein by reference).
|
|
10.18†
|
Form of Restricted Common Unit Award Notice (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed January 26, 2006, and incorporated herein by reference).
|
|
10.19
|
Assignment and Assumption of Lease and Sublease dated November 1, 2002, by and between the Operating Partnership and Martin Gas Sales LLC (“MGSLLC”) (filed as Exhibit 10.12 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
|
|
10.20
|
Purchaser Use Easement, Ingress-Egress Easement, and Utility Facilities Easement dated November 1, 2002, by and between MGSLLC and the Operating Partnership (filed as Exhibit 10.13 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
|
|
10.21
|
Asset Purchase Agreement by and among the Partnership, the Operating Partnership and Tesoro Marine Services, L.L.C., dated October 27, 2003 (filed as Exhibit 10.1 to the Partnership’s Amendment No. 1 to Current Report on Form 8-K (SEC File No. 000-50056), filed January 23, 2004, and incorporated herein by reference).
|
|
10.22
|
Purchase Agreement by and among the Operating Partnership, Prism Gas Systems I, L.P., Natural Gas Partners V, L.P., Robert E. Dunn, William J. Diehnelt, Gene A. Adams, Philip D. Gettig, Sharon C. Taylor and Scott A. Southard, dated September 6, 2005 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed September 6, 2005, and incorporated herein by reference).
|
|
10.23
|
Amended and Restated Terminal Services Agreement by and between the Operating Partnership and Martin Fuel Service LLC (“MFSLLC”), dated October 27, 2004 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed October 28, 2004, and incorporated herein by reference).
|
|
10.24
|
Transportation Services Agreement by and between the Operating Partnership and MFSLLC, dated December 23, 2003 (filed as Exhibit 10.3 to the Partnership’s Amendment No. 1 to Current Report on Form 8-K (SEC File No. 000-50056), filed January 23, 2004, and incorporated herein by reference).
|
|
10.25
|
Lubricants and Drilling Fluids Terminal Services Agreement by and between the Operating Partnership and MFSLLC, dated December 23, 2003 (filed as Exhibit 10.4 to the Partnership’s Amendment No. 1 to Current Report on Form 8-K (SEC File No. 000-50056), filed January 23, 2004, and incorporated herein by reference).
|
|
10.26†
|
Martin Resource Management Corporation Purchase Plan for Units of Martin Midstream Partners L.P. (filed as Exhibit 10.1 to the Partnership’s registration statement on Form S-8 (SEC File No. 333-140152), filed January 23, 2007, and incorporated herein by reference).
|
|
10.27
|
Stock Purchase Agreement, dated April 27, 2007, by and among Woodlawn Pipeline Co., Inc., Lantern Resources, L.P., David P. Deison and Prism Gas Systems I, L.P. (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed May 2, 2007, and incorporated herein by reference).
|
|
10.28
|
Asset Purchase Agreement, dated April 27, 2007, by and among Peak Gas Gathering L.P. and Prism Gas Systems I, L.P. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed May 2, 2007, and incorporated herein by reference).
|
|
10.29
|
Form of Indemnification Agreement (filed as Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q, filed November 6, 2008, and incorporated herein by reference).
|
|
Exhibit
Number
|
Exhibit Name
|
|
10.30
|
Amended and Restated Contribution Agreement, dated as of November 25, 2009, by and among the Operating Partnership, Cross Oil Refining & Marketing, Inc., Martin Resource Management and the Partnership (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed December 1, 2009, and incorporated herein by reference).
|
|
10.31
|
Tolling Agreement, dated as of November 25, 2009, by and between the Operating Partnership and Cross Oil Refining & Marketing, Inc. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed December 1, 2009, and incorporated herein by reference).
|
|
10.32
|
Amended and Restated Common Unit Purchase Agreement, dated as of November 24, 2009, by and between the Partnership and Martin Resource Management (filed as Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, filed December 1, 2009, and incorporated herein by reference).
|
|
10.33
|
Commitment Increase and Joinder Agreement dated December 6, 2011 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed December 6, 2011, and incorporated herein by reference).
|
|
10.34
|
Limited Liability Company Agreement of Redbird Gas Storage LLC dated May 27, 2011 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K/A, filed January 13, 2012, and incorporated herein by reference).
|
|
10.35
|
Amended and Restated Limited Liability Company Agreement of Redbird Gas Storage LLC dated September 7, 2011 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K/A, filed January 13, 2012, and incorporated herein by reference).
|
|
18.1
|
KPMG Preferability Letter on Change in Annual Date for Goodwill and Other Intangibles Impairment Testing Date (filed as Exhibit 18.1 to the Partnership’s Quarterly Report on Form 10-Q, filed November 7, 2011, and incorporated herein by reference).
|
|
List of Subsidiaries.
|
|
|
Consent of KPMG LLP.
|
|
|
Consent of KPMG LLP.
|
|
|
Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 9.06 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
|
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 9.06 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
|
|
|
101
|
Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011, formatted in Extensible Business Reporting Language: (1) the Consolidated Balance Sheets; (2) the Consolidated Statements of Income; (3) the Consolidated Statements of Cash Flows; (4) the Consolidated Statements of Capital; (5) the Consolidated Statements of Other Comprehensive Income; and (6) the Notes to Consolidated Financial Statements, tagged as blocks of text.
|
|
*
|
Filed or furnished herewith.
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†
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As required by Item 15(a)(3) of Form 10-K, this exhibit is identified as a compensatory plan or arrangement.
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Waskom Gas Processing Company
Consolidated Financial Statements December 31, 2011 and 2010 and for each of the years in the three-year period ended December 31, 2011 (with Independent Auditors’ Report thereon).
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2011
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2010
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|||||||
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ASSETS
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||||||||
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CURRENT ASSETS:
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||||||||
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Cash
|
$ | 757,494 | $ | 961,067 | ||||
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Accounts receivable
|
1,473,935 | 946,206 | ||||||
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Accounts receivable—partners
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18,241,163 | 10,707,976 | ||||||
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Inventories
|
423,474 | 503,449 | ||||||
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Prepaid expenses
|
26,224 | 24,064 | ||||||
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Total current assets
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20,922,290 | 13,142,762 | ||||||
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PROPERTY AND EQUIPMENT:
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||||||||
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Gas plant asset and gas gathering equipment
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157,072,005 | 133,744,130 | ||||||
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Other fixed assets
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746,743 | 746,743 | ||||||
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Accumulated depreciation and amortization
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(32,336,265 | ) | (25,826,835 | ) | ||||
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Net property and equipment
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125,482,483 | 108,664,038 | ||||||
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NON-CURRENT ASSETS:
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||||||||
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Other non-current assets
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250,000 | 250,000 | ||||||
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TOTAL
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$ | 146,654,773 | $ | 122,056,800 | ||||
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LIABILITIES AND PARTNERS’ EQUITY
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||||||||
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CURRENT LIABILITIES:
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||||||||
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Accounts payable and accrued liabilities
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$ | 14,934,725 | $ | 8,824,740 | ||||
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Accounts payable—partners
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4,057,864 | 4,978,625 | ||||||
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Total current liabilities
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18,992,589 | 13,803,365 | ||||||
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LONG-TERM LIABILITIES—Asset retirement obligation
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799,527 | 744,991 | ||||||
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COMMITMENTS AND CONTINGENCIES
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||||||||
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PARTNERS’ CAPITAL
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126,862,657 | 107,508,444 | ||||||
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TOTAL
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$ | 146,654,773 | $ | 122,056,800 | ||||
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2011
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2010
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2009
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||||||||||
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OPERATING REVENUES:
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||||||||||||
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Natural gas processing and other revenues
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$ | 39,618,717 | $ | 36,297,801 | $ | 23,421,165 | ||||||
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Natural gas liquid sales
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88,654,517 | 86,911,925 | 47,623,953 | |||||||||
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Gain/(loss) on disposal of assets
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845,567 | 912,004 | (847 | ) | ||||||||
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Total operating revenues
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129,118,801 | 124,121,730 | 71,044,271 | |||||||||
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OPERATING COSTS AND EXPENSES:
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||||||||||||
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Cost of sales - natural gas liquids
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92,705,171 | 87,159,671 | 46,645,393 | |||||||||
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Operating costs
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10,126,797 | 9,375,703 | 6,420,633 | |||||||||
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Depreciation and amortization
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6,849,262 | 6,597,686 | 4,000,412 | |||||||||
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Total operating costs and expenses
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109,681,230 | 103,133,060 | 57,066,438 | |||||||||
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OPERATING INCOME BEFORE TAXES
|
19,437,571 | 20,988,670 | 13,977,833 | |||||||||
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Income tax expense
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53,008 | 226,589 | 110,712 | |||||||||
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NET INCOME
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$ | 19,384,563 | $ | 20,762,081 | $ | 13,867,121 | ||||||
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Total
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||||
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Partners'
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||||
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Capital
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||||
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BALANCE
—
December 31, 2008
|
67,729,787 | |||
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Cash contributions for capital expenditures
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8,310,458 | |||
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Cash distributions in excess of working capital
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(6,394,002 | ) | ||
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Cash distributions
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(1,300,000 | ) | ||
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Distributions in-kind
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(11,652,566 | ) | ||
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Net income
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13,867,121 | |||
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BALANCE
—
December 31, 2009
|
$ | 70,560,798 | ||
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Cash contributions for capital expenditures
|
7,471,259 | |||
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Cash contributions for investment in Waskom Midstream LLC
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40,000,000 | |||
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Cash distributions in excess of working capital
|
(4,702,415 | ) | ||
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Cash distributions
|
(4,200,000 | ) | ||
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Distributions in-kind
|
(22,383,279 | ) | ||
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Net income
|
20,762,081 | |||
|
BALANCE
—
December 31, 2010
|
$ | 107,508,444 | ||
|
Cash contributions for capital expenditures
|
32,209,322 | |||
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Cash distributions in excess of working capital
|
(4,432,461 | ) | ||
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Cash distributions
|
(2,400,000 | ) | ||
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Distributions in-kind
|
(25,407,211 | ) | ||
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Net income
|
19,384,563 | |||
|
BALANCE
—
December 31, 2011
|
$ | 126,862,657 | ||
|
2011
|
2010
|
2009
|
||||||||||
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OPERATING ACTIVITIES:
|
||||||||||||
|
Net income
|
$ | 19,384,563 | $ | 20,762,081 | $ | 13,867,121 | ||||||
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
||||||||||||
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Depreciation and amortization
|
6,849,262 | 6,597,686 | 4,000,412 | |||||||||
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Distributions in-kind to partners
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(25,407,211 | ) | (22,383,279 | ) | (11,652,566 | ) | ||||||
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Loss/(Gain) on sale of asset
|
(845,567 | ) | (912,004 | ) | 847 | |||||||
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Changes in operating assets and liabilities:
|
||||||||||||
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Accounts receivable
|
(527,729 | ) | (768,174 | ) | 1,172,489 | |||||||
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Accounts receivable - partners
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(7,533,187 | ) | (1,334,484 | ) | 983,218 | |||||||
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Inventory
|
79,975 | (35,077 | ) | (4,798 | ) | |||||||
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Prepaid expenses
|
(2,160 | ) | (24,064 | ) | 3,989 | |||||||
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Accounts payable and accrued liabilites
|
6,330,191 | 2,132,514 | (354,716 | ) | ||||||||
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Accounts payable - partners
|
(920,761 | ) | 3,134,610 | (1,932,840 | ) | |||||||
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Net cash provided by (used in) operating activities
|
(2,592,624 | ) | 7,169,809 | 6,083,157 | ||||||||
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INVESTING ACTIVITIES:
|
||||||||||||
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Additions to property and equipment
|
(25,489,809 | ) | (7,277,746 | ) | (8,773,336 | ) | ||||||
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Acquisitions, net of cash required
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- | (40,000,000 | ) | - | ||||||||
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Proceeds from sale/disposal of assets
|
2,502,000 | 2,477,000 | 708,449 | |||||||||
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Net cash used in investing activities
|
(22,987,809 | ) | (44,800,746 | ) | (8,064,887 | ) | ||||||
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FINANCING ACTIVITIES:
|
||||||||||||
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Contributions from partners
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32,209,322 | 47,471,259 | 8,310,458 | |||||||||
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Distrubutions to partners
|
(6,832,462 | ) | (8,902,415 | ) | (7,694,002 | ) | ||||||
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Net cash provided by financing activities
|
25,376,860 | 38,568,844 | 616,455 | |||||||||
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NET INCREASE (DECREASE) IN CASH
|
(203,573 | ) | 937,907 | (1,365,274 | ) | |||||||
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CASH—Beginning of year
|
961,067 | 23,160 | 1,388,434 | |||||||||
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CASH—End of year
|
$ | 757,494 | $ | 961,067 | $ | 23,160 | ||||||
|
SUPPLEMENTAL CASH FLOW DISCLOSURES:
|
||||||||||||
|
Taxes paid
|
$ | 196,554 | $ | 112,371 | $ | 221,201 | ||||||
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NON-CASH:
|
||||||||||||
|
Addition to asset retirement obligation
|
$ | - | $ | - | $ | 122,777 | ||||||
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1.
|
NATURE OF BUSINESS
|
|
2.
|
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|
|
Years
|
||||
|
Gas gathering equipment
|
10 | |||
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Gas plant
|
20 | |||
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Furniture and fixtures
|
1 | |||
|
Computer equipment
|
3 | |||
|
Computer software
|
3 | |||
|
3.
|
RELATED-PARTY TRANSACTIONS
|
|
4.
|
ACQUISITION
|
|
5.
|
COMMITMENTS AND CONTINGENCIES
|
|
6.
|
SUBSEQUENT EVENT
|
No information found
* THE VALUE IS THE MARKET VALUE AS OF THE LAST DAY OF THE QUARTER FOR WHICH THE 13F WAS FILED.
| FUND | NUMBER OF SHARES | VALUE ($) | PUT OR CALL |
|---|
| DIRECTORS | AGE | BIO | OTHER DIRECTOR MEMBERSHIPS |
|---|
No information found
No Customers Found
No Suppliers Found
Price
Yield
| Owner | Position | Direct Shares | Indirect Shares |
|---|