Item 1B.
Unresolved Staff Comments
None.
A description of our properties is contained in “Item 1. Business” and is incorporated herein by reference.
We believe we have satisfactory title to our assets. Some of the easements, rights-of-way, permits, licenses or similar documents relating to the use of the properties that have been transferred to us in connection with our initial public offering and the assets we acquired in our acquisitions, required the consent of third parties, which in some cases is a governmental entity. We believe we have obtained sufficient third-party consents, permits and authorizations for the transfer of assets necessary for us to operate our business in all material respects. With respect to any third-party consents, permits or authorizations that have not been obtained, we believe the failure to obtain these consents, permits or authorizations will not have a material adverse effect on the operation of our business. Title to our property may be subject to encumbrances, including liens in favor of our secured lender. We believe none of these encumbrances materially detract from the value of our properties or our interest in these properties or materially interfere with their use in the operation of our business.
Item 3.
Item 3.
Legal Proceedings
From time to time, we are subject to certain legal proceedings, claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity. A description of our legal proceedings is included in “Item 8. Financial Statements and Supplementary Data, Note 22. Commitments and Contingencies”, and is incorporated herein by reference.
Item 4.
Item 4.
Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5.
Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Our common units are traded on the NASDAQ under the symbol “MMLP.” As of March 3, 2014 there were approximately 220 holders of record and approximately 25,400 beneficial owners of our common units. The following table sets forth the high and low sale prices of our common units for the periods indicated, based on the daily composite listing of stock transactions for the NASDAQ and cash distributions declared per common units during those periods:
Fiscal 2013:
Fiscal 2012:
On March 3, 2014, the last reported sales price of our common units as reported on the NASDAQ was $42.73 per unit.
In November 2012, in connection with our public offering of 3,450,000 common units, our general partner contributed $2.2 million in cash to us in order to maintain its 2% general partner interest in us.
In January 2012, in connection with our public offering of 2,645,000 common units, our general partner contributed $2.0 million in cash to us in order to maintain its 2% general partner interest in us.
Within 45 days after the end of each quarter, we distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations. Our distributions are effectively made 98% to unitholders and 2% to our general partner, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved. Distributions to our general partner increase to 15%, 25% and 50% based on incremental distribution thresholds as set forth in our partnership agreement. On October 2, 2012, our general partner executed Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership (“the Partnership Agreement”). The Partnership Agreement Amendment provides that our general partner, currently the holder of the incentive distribution rights, shall forego the next $18.0 million in incentive distributions that it would otherwise be entitled to receive. As of March 3, 2014, the amount of incentive distributions the general partner has foregone is $11.9 million.
Our ability to distribute available cash is contractually restricted by the terms of our credit facility. Our credit facility contains covenants requiring us to maintain certain financial ratios. We are prohibited from making any distributions to unitholders if the distribution would cause a default or an event of default, or a default or an event of default exists, under our credit facility. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Description of Our Credit Facility.”
Item 6.
Item 6.
Selected Financial Data
The following table sets forth selected financial data and other operating data of the Partnership for the years ended December 31, 2013, 2012, 2011, 2010 and 2009 and is derived from the audited consolidated financial statements of the Partnership.
The following selected financial data are qualified by reference to and should be read in conjunction with the Partnership's Consolidated Financial Statements and Notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this document.
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States (“U.S.”) Gulf Coast region. Our four primary business lines include:
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Terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants;
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Natural gas liquids distribution services and natural gas storage;
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Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution; and
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Marine transportation services for petroleum products and by-products.
The petroleum products and by-products we collect, transport, store and market are produced primarily by major and independent oil and gas companies who often turn to third parties, such as us, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. We operate primarily in the U.S. Gulf Coast region. This region is a major hub for petroleum refining, natural gas gathering and processing, and support services for the exploration and production industry.
We were formed in 2002 by Martin Resource Management, a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of December 31, 2013, Martin Resource Management owned 19.1% of our total outstanding common limited partner units. Furthermore, Martin Resource Management controls Martin Midstream GP LLC (“MMGP”), our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC (“Holdings”), the sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentive distribution rights. Martin Resource Management directs our business operations through its ownership interests in and control of our general partner.
We entered into an omnibus agreement dated November 1, 2002, with Martin Resource Management (the “Omnibus Agreement”) that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and our use of certain of Martin Resource Management’s trade names and trademarks. Under the terms of the Omnibus Agreement, the employees of Martin Resource Management are responsible for conducting our business and operating our assets.
Martin Resource Management has operated our business since 2002. Martin Resource Management began operating our natural gas services business in the 1950s and our sulfur business in the 1960s. It began our marine transportation business in the late 1980s. It entered into our fertilizer and terminalling and storage businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base through expansions and strategic acquisitions.
Recent Developments
We believe one of the rationales driving investment in master limited partnerships, including us, is the opportunity for distribution growth offered by the partnerships. Such distribution growth is a function of having access to liquidity in the financial markets used for incremental capital investment (development projects and acquisitions) to grow distributable cash flow.
We continually adjust our business strategy to focus on maximizing liquidity, maintaining a stable asset base which generates fee based revenues not sensitive to commodity prices, and improving profitability by increasing asset utilization and 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. Over the next two years, we plan to increase expansion capital expenditures primarily in our Terminalling and Storage and Natural Gas Services segments.
Recent Acquisitions
Marine Transportation Equipment Purchase. On September 30, 2013, we acquired two previously leased inland tank barges from Martin Resource Management for $7.1 million. This transaction was funded with borrowings under our revolving credit facility.
Sulfur Production Facility. On August 5, 2013, we purchased a plant nutrient sulfur production facility in Cactus, Texas for $4.1 million. This transaction was funded with borrowings under our revolving credit facility.
NL Grease, LLC. On June 13, 2013, we acquired certain assets of NL Grease, LLC (“NLG”) for approximately $12.1 million. NLG is a Kansas City, Missouri based grease manufacturer that specializes in private-label packaging of commercial and industrial greases. This transaction was funded with borrowings under our revolving credit facility.
Martin Energy Trading LLC. During March 2013, we acquired 100% of the preferred interests in Martin Energy Trading LLC (“MET”), a subsidiary of Martin Resource Management, for $15.0 million. This transaction was funded with borrowings under our revolving credit facility.
NGL Marine Equipment Purchase. On February 28, 2013, we purchased from affiliates of Florida Marine Transporters, Inc., six liquefied petroleum gas (“LPG”) pressure barges and two commercial push boats (“Florida Marine Assets”) for approximately $50.8 million. This transaction was funded with borrowings under our revolving credit facility.
Talen's Marine & Fuel LLC. On December 31, 2012, we acquired all of the outstanding membership interests in Talen's Marine & Fuel LLC (“Talen's”) from QEP Marine Fuel Investment, LLC and QEP Marine Fuel Holdings, Inc. (collectively referred to as “Quintana Energy Partners”) for $103.4 million, subject to certain post-closing adjustments. Simultaneous with the acquisition, we sold certain working capital-related assets to Martin Energy Services LLC (“MES”), a wholly-owned subsidiary of Martin Resource Management for $56.0 million, reducing our investment in Talen's to $47.4 million. This transaction was funded with borrowings under our revolving credit facility. In conjunction with its purchase of certain working capital-related assets, MES entered into various service agreements with Talen's pursuant to which we provide certain terminalling and marine services to MES.
Other Developments
Sale of general partner interest. On August 30, 2013, Martin Resource Management completed the sale of a 49% non-controlling voting interest (50% economic interest) in Holdings, the newly-formed sole member of MMGP, the general partner of the Partnership, to certain affiliated investment funds managed by Alinda Capital Partners (“Alinda”). Upon closing the transaction, Alinda appointed two representatives to serve on the board of directors of the general partner of the Partnership.
Debt Financing Activities
Amendment to Revolving Credit Facility. On March 28, 2013, we made certain strategic amendments to our credit facility which, among other things, increased our borrowing capacity from $400.0 million to $600.0 million and extended the maturity date of the facility from April 15, 2016 to March 28, 2018.
Issuance of 2021 Senior Unsecured Notes. On February 11, 2013, we completed a private placement of $250.0 million in aggregate principal amount of 7.250% senior unsecured notes due 2021 to qualified institutional buyers under Rule 144A. We received proceeds of approximately $245.1 million, after deducting initial purchasers' discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under our revolving credit facility. On July 1, 2013, we filed a registration statement on Form S-4 with the Securities and Exchange Commission (“SEC”) to exchange the notes for registered 7.250% senior unsecured notes due February 2021. The exchange offer was completed on July 31, 2013.
For a more detailed discussion regarding our credit facility, see “Description of Our Long-Term Debt” within this Item.
Subsequent Events
Redemption of 2018 Senior Unsecured Notes. On February 28, 2014, we announced that we will exercise a full redemption of the 2018 senior unsecured notes pursuant to the indenture, on or about April 1, 2014 at an aggregate redemption value of $182.8 million. We expect to fund the redemption under borrowings from our revolving credit facility.
Amendment to Revolving Credit Facility. On February 18, 2014, we increased the maximum amount of borrowings under our revolving credit facility from $600.0 million to $637.5 million by utilizing the accordion feature of our revolving credit facility.
Quarterly Distribution. On January 23, 2014, we declared a quarterly cash distribution of $0.785 per common unit for the fourth quarter of 2013, or $3.14 per common unit on an annualized basis, which was paid on February 14, 2014 to unitholders of record as of February 7, 2014.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based on the historical consolidated financial statements included elsewhere herein. We prepared these financial statements in conformity with United States generally accepted accounting principles (“U.S. GAAP” or “GAAP”). The preparation of these financial statements required us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We based our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Our results may differ from these estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Changes in these estimates could materially affect our financial position, results of operations or cash flows. You should also read Note 2, “Significant Accounting Policies” in Notes to Consolidated Financial Statements. The following table evaluates the potential impact of estimates utilized during the periods ended December 31, 2013 and 2012:
Our Relationship with Martin Resource Management
Martin Resource Management directs our business operations through its ownership and control of our general partner and under the Omnibus Agreement. In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2013, 2012 and 2011, the conflicts committee of our general partner (“Conflicts Committee”) approved reimbursement amounts of $10.6 million, $7.6 million and $4.8 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.
We are required to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. Martin Resource Management also licenses certain of its trademarks and trade names to us under the Omnibus Agreement.
We are both an important supplier to and customer of Martin Resource Management. Among other things, we sell sulfuric acid and provide marine transportation and terminalling and storage services to Martin Resource Management. We
purchase land transportation services, underground storage services, and marine fuel from Martin Resource Management. All of these services and goods are purchased and sold pursuant to the terms of a number of agreements between us and Martin Resource Management.
For a more comprehensive discussion concerning the Omnibus Agreement and the other agreements that we have entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions, and Director Independence - Agreements.”
How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements other than our financial statements prepared in accordance with U.S. GAAP to analyze our performance. These include: (1) net income before interest expense, income tax expense, and depreciation and amortization (“EBITDA”), (2) adjusted EBITDA and (3) distributable cash flow. Our management views these measures as important performance measures of core profitability for our operations and the ability to generate and distribute cash flow, and as key components of our internal financial reporting. We believe investors benefit from having access to the same financial measures that our management uses.
EBITDA and Adjusted EBITDA. Certain items excluded from EBITDA and adjusted EBITDA are significant components in understanding and assessing an entity's financial performance, such as cost of capital and historic costs of depreciable assets. We have included information concerning EBITDA and adjusted EBITDA because they provide investors and management with additional information to better understand the following: financial performance of our assets without regard to financing methods, capital structure or historical cost basis; our operating performance and return on capital as compared to those of other similarly situated entities; and the viability of acquisitions and capital expenditure projects. Our method of computing adjusted EBITDA may not be the same method used to compute similar measures reported by other entities. The economic substance behind our use of adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our unit holders.
Distributable Cash Flow. Distributable cash flow is a significant performance measure used by our management and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships because the value of a unit of such an entity is generally determined by the unit's yield, which in turn is based on the amount of cash distributions the entity pays to a unitholder.
EBITDA, adjusted EBITDA and distributable cash flow should not be considered alternatives to, or more meaningful than, net income, cash flows from operating activities, or any other measure presented in accordance with U.S. GAAP. Our method of computing these measures may not be the same method used to compute similar measures reported by other entities.
Non-GAAP Financial Measures
The following table reconciles the non-GAAP financial measurements used by management to our most directly comparable GAAP measures for the years ended December 31, 2013, 2012, and 2011, which represents EBITDA, Adjusted EBITDA and Distributable Cash Flow from continuing operations.
Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow
Results of Operations
The results of operations for the years ended December 31, 2013, 2012, and 2011 have been derived from our consolidated financial statements.
We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues. The following table sets forth our operating revenues and operating income by segment for the years ended December 31, 2013, 2012, and 2011.
Our consolidated results of operations are presented on a comparative basis below. There are certain items of income and expense which we do not allocate on a segment basis. These items, including equity in earnings (loss) of unconsolidated entities, interest expense, and indirect selling, general and administrative expenses, are discussed after the comparative discussion of our results within each segment.
The Natural Gas Services segment information below excludes the discontinued operations of our natural gas gathering and processing assets (as described in Item 8, Note 5 and collectively referred to as the “Prism Assets”) for all periods.
Terminalling and Storage Segment
Comparative Results of Operations for the Twelve Months Ended December 31, 2013 and 2012
Services revenues. Services revenue increased primarily due to $17.7 million attributable to our new crude terminal in Corpus Christi, Texas, which was placed into service in May 2012. In addition, $5.2 million of the increase is due to revenues generated by our Talen's acquisition on December 31, 2012. The remaining increase is primarily due to increased throughput at the Smackover refinery.
Products revenues. An 8% increase in sales volumes at our blending and packaging facilities resulted in a $10.7 million positive impact on product revenues. Product sales volumes from our shore-based terminals decreased 7%, resulting in $5.6 million reduction in product revenues. The average sales price at our blending and packaging facilities decreased 5%, resulting in a $7.8 million decrease in product revenues. The average sales price at our shore-based terminals decreased 4%, resulting in a $3.3 million decrease in product revenues.
Cost of products sold. An 8% increase in sales volumes at our blending and packaging facilities resulted in a $9.4 million increase in cost of products sold, which was partially offset by a 7% decrease in sales volumes at our shore-based terminals, resulting in a $5.2 million decrease in cost of products sold. Decreased average cost at our blending and packaging facilities of 8% resulted in a decrease of $10.0 million in cost of products sold. Decreased average cost at our shore-based terminals of 5% resulted in a decrease of $3.9 million in cost of products sold.
Operating expenses. Increased expenses at our specialty terminals accounted for $6.9 million of the total increase, primarily attributable to the Corpus Christi crude terminal. Our shore-based terminal expenses increased $1.7 million primarily due to the acquisition of the Talen's terminals. In addition, $7.1 million of the increase is attributable to the Smackover refining assets, primarily as a result of increased utilities and repairs and maintenance expense.
Selling, general and administrative expenses. The decrease in selling, general and administrative expenses is primarily related to decreased advertising expense in our blending and packaging operations.
Depreciation and amortization. The increase in depreciation and amortization is due to the impact of recent capital expenditures.
Other operating income (loss). The increase in other operating income (loss) is primarily attributable to a gain in 2013 on an involuntary conversion resulting from a tank fire that occurred in the third quarter of 2011.
Comparative Results of Operations for the Twelve Months Ended December 31, 2012 and 2011
Services revenues. Services revenue increased primarily due to additional revenue of $8.6 million attributable to our new crude terminal in Corpus Christi, Texas, which was placed into service in the second quarter of 2012. In addition, $3.8 million of the increase is due to revenues generated by the Sunoco Pipeline which was placed into service in the fourth quarter of 2011.
Products revenues. A 9% increase in sales volumes at our blending and packaging facilities resulted in a $12.4 million positive impact on product revenues. Product sales volumes from our shore-based terminals decreased 3%, resulting in $2.4 million reduction in product revenues. The average sales price at our blending and packaging facilities increased 6%, resulting in a $7.6 million increase in product revenues. The average sales price at our shore-based terminals increased 11%, resulting in an $8.2 million increase in product revenues.
Cost of products sold. A 9% increase in sales volumes at our blending and packaging facilities resulted in an $11.1 million increase in cost of products sold, which was partially offset by a 3% decrease in sales volumes from at our shore-based terminals, resulting in a $2.3 million decrease in cost of products sold. Increased average cost at our blending and packaging facilities of 5%, resulted in an increase of $5.7 million in cost of products sold. Increased average cost at our shore-based terminals of 10%, resulted in an increase of $7.3 million in cost of products sold.
Operating expenses. Increased expenses for the specialty terminals accounted for $2.7 million of the total increase, primarily attributable to the Corpus Christi crude terminal. In addition, $3.5 million of the increase is related to the Smackover refining assets, primarily attributable to the Sunoco pipeline.
Selling, general and administrative expenses. Selling, general and administrative expenses increased primarily due to increased advertising expense in our blending and packing operations.
Depreciation and amortization. The increase in depreciation and amortization is due to the impact of recent capital expenditures.
Other operating loss. Other operating loss represents losses on the disposal of property, plant and equipment.
Natural Gas Services Segment
Comparative Results of Operations for the Twelve Months Ended December 31, 2013 and 2012
Revenues. The marine transportation revenue is attributable to our acquisition of the Florida Marine Assets on February 28, 2013. Natural gas services sales volumes increased 26%, positively impacting revenues $200.4 million, primarily as a result of us entering the Louisiana butane market during April 2012. Our NGL average sales price per barrel decreased $3.42, or 5%, resulting in an offsetting decrease to revenues of $41.3 million.
Cost of products sold. Our average cost per barrel decreased $4.08, or 6%. Our margins increased $0.67 per barrel during the period, primarily related to increased margins resulting from our entrance into the Louisiana butane market in April 2012.
Operating expenses. Operating expenses increased primarily as a result of outside towing, tankerman, and fuel expenses associated with the newly acquired Florida Marine Assets of $1.5 million, higher property and liability premiums of $0.3 million, and increased pipeline maintenance expenses of $0.2 million.
Selling, general and administrative expenses. Selling, general and administrative expenses decreased primarily as a result of the reserve for an uncollectible customer receivable in 2012 of $0.7 million and the recovery of an uncollectible customer receivable in 2013 of $0.3 million. These decreases were partially offset by increased compensation expense of $0.3 million and increased property tax expense of $0.1 million.
Depreciation and amortization. Depreciation and amortization increased as a result of the acquisition of the Florida Marine Assets during the first quarter of 2013.
Comparative Results of Operations for the Twelve Months Ended December 31, 2012 and 2011
Revenues. Natural gas services sales volumes increased 54%, positively impacting revenues $288.0 million, primarily as a result of us entering the Louisiana butane market during April 2012. Our NGL average sales price per barrel decreased $9.44, or 12%, resulting in an offsetting decrease to revenues of $74.2 million.
Cost of products sold. Our average cost per barrel decreased $9.79, or 12%. Our margins increased $0.36 per barrel during the period, primarily related to increased margins resulting from our entrance into the Louisiana butane market in April 2012.
Operating expenses. Operating expenses increased primarily as a result of increased pipeline maintenance expenses of $0.2 million and increased compensation expense of $0.2 million.
Selling, general and administrative expenses. Selling, general and administrative expenses increased primarily as a result of increased compensation expense of $1.4 million and an increase in bad debt expense of $0.7 million.
Depreciation and amortization. Depreciation and amortization remained consistent from year to year.
Sulfur Services Segment
Comparative Results of Operations for the Twelve Months Ended December 31, 2013 and 2012
Revenues. The increase in service revenue is attributable to increased contract rates. Product revenue declined $28.3 million as a result of a 12% decrease in sales volumes. The volume reduction was primarily related to the conversion of a buy/sell contract with a major customer to a fee-based handling contract. Additionally, product revenues decreased $20.4 million due to an 8% decline in sales prices where our sulfur products saw a decrease in sales prices of 14% and our fertilizer products saw a decrease in sales prices of 3%.
Cost of products sold. A 12% decrease in sales volumes reduced cost of products sold by $22.3 million. An 8% decrease in prices reduced our cost by an additional $14.9 million. Margin per ton decreased $4.32, or 10%, resulting in a decline in gross margin of $11.5 million, primarily attributable to the decline in market prices discussed above. Also contributing to the decline in the gross margin of our fertilizer business was significant downtime attributable to plant turnarounds at our Plainview and Neches production facilities. Costs associated with these turnarounds were $1.2 million higher than the same period of 2012.
Operating expenses. Our operating expenses decreased due to $0.8 million less in outside towing expenses offset by increased compensation expense of $0.6 million.
Selling, general and administrative expenses. Selling, general and administrative expenses increased as a result of increased compensation expense.
Depreciation and amortization. The increase in depreciation and amortization is due to the impact of recent capital expenditures.
Other operating loss. Other operating loss represents losses on the disposal of property, plant and equipment in 2012.
Comparative Results of Operations for the Twelve Months Ended December 31, 2012 and 2011
Revenues. The increase in service revenue is attributable to increased contract rates. The volume reduction was primarily related to the conversion of a buy/sell contract with a major customer to a fee-based handling contract. Revenue declined $44.0 million as a result of a 15% decrease in sales volumes. Offsetting this was an increase of $30.2 million due to an 11% increase in sales price where our sulfur products saw an increase in sales prices of 2% and our fertilizer products saw an increase in sales prices of 9%.
Cost of products sold. A 15% decrease in volumes reduced cost of products sold by $34.4 million. Offsetting this was an increase in prices of 4%, increasing products costs by $9.7 million. Margin per ton increased $13.83, or 47%, resulting in an increase in gross margin of $11.0 million, primarily attributable to an increase in market prices related to our fertilizer products.
Operating expenses. Our operating expenses decreased primarily as a result of lower outside towing expenses of $1.8 million and $0.4 million in lower workers compensation claims. These decreases were offset by an increase of $0.3 million in marine fuel expense.
Selling, general and administrative expenses. Selling, general and administrative expenses increased as a result of increased compensation expense.
Depreciation and amortization. The increase in depreciation and amortization is due to the impact of recent capital expenditures.
Other operating income (loss). Other operating income (loss) decreased primarily from a $1.4 million gain on termination of a rail services agreement and $0.7 million business interruption recovery, both of which occurred in 2011.
Marine Transportation Segment
Comparative Results of Operations for the Twelve Months Ended December 31, 2013 and 2012
Inland Revenues. An $11.2 million increase in inland revenues is primarily attributable to $8.4 million from the Talen's acquisition and $3.1 million from the Florida Marine Assets.
Offshore Revenues. Revenue from offshore operations increased $0.4 million due to an increase in utilization. Ancillary revenue, primarily fuel, decreased $1.0 million.
Operating expenses. Operating expenses increased $9.0 million as a result of costs and expenses associated with the acquisitions of the Talen's and Florida Marine Assets.
Selling, general and administrative expenses. Selling, general and administrative expenses increased primarily as a result of the 2012 period including the recovery of a previously uncollectible customer receivable.
Depreciation and amortization. Depreciation and amortization decreased as a result of the disposal of equipment, offset by increases in depreciable assets related to recent capital expenditures.
Other operating income (loss). Other operating income (loss) increased as a result of gains recognized on the disposal of equipment.
Comparative Results of Operations for the Twelve Months Ended December 31, 2012 and 2011
Inland Revenues. Revenue from inland operations decreased $2.8 million due to a decrease in utilization. Ancillary revenue, primarily fuel, increased $0.4 million.
Offshore Revenues. Revenue from offshore operations increased $5.5 million due to an increase in utilization. Ancillary revenue, primarily fuel, increased $1.8 million.
Operating expenses. The increase in operating expenses is due to increased fuel costs of $2.4 million, compensation expense of $1.6 million, claims expense of $0.4 million, assist tugs of $0.3 million, and a write-off of supplies inventory of $1.2 million. Offsetting these increases are decreases in outside towing of $1.3 million and barge lease expense of $1.0 million.
Selling, general and administrative expenses. Selling, general and administrative expenses decreased as a result of the collection of a previously reserved customer receivable of $2.1 million and a $0.4 million decrease in bad debt expense in 2012.
Depreciation and amortization. Depreciation and amortization decreased as a result of the disposal of equipment, offset by increases in depreciable assets related to recent capital expenditures.
Other operating loss. Other operating loss represents losses on asset dispositions.
Equity in Earnings (Loss) of Unconsolidated Entities
Equity in loss of Cardinal Gas Storage Partners LLC (“Cardinal”) increased principally due to the recognition of an impairment charge, of which our portion was $54.1 million of impairment related to the long-lived assets of Monroe Gas Storage Company, LLC (“Monroe”), a subsidiary of Cardinal. In addition, 2013 includes a one-time charge for incentive payments resulting from the completion of Cadeville Gas Storage, LLC (“Cadeville”) and Perryville Gas Storage, LLC (“Perryville”) ahead of schedule and under budget. The 2013 period also includes a one-time charge for employee severance costs related to the discontinuation of Cardinal's gas consulting business. The aggregate impact of these one-time charges to us was $1.8 million. Improved Cardinal results of operations attributable to the completion of the Cadeville and Perryville projects partially offset the negative impact of these items. A $2.2 million milestone payment is included in Cardinal's equity in loss in the twelve months ended December 31, 2012. No milestone payments were received in 2013.
Equity in earnings of MET represents dividends on our 100% investment in its preferred interests. The MET investment was acquired in March 2013.
The $0.4 million decrease in equity in loss of Caliber Gathering, LLC (“Caliber”) is attributable to Caliber's decline in earnings for the twelve months ended December 31, 2013. The Caliber investment was acquired in June 2012 and sold in November 2013.
The Pecos Valley Producer Services LLC (“Pecos Valley”) investment was sold in August 2012.
Equity in loss of Cardinal decreased $3.8 million. A $2.2 million milestone payment is included in Cardinal's equity in earnings in the twelve months ended December 31, 2012. No milestone payments were received in 2011. The remaining increase in equity in earnings of Cardinal is attributable to improved results of operations in 2012.
Initial equity in earnings (loss) of Caliber and Pecos Valley Producer were recorded in June 2012. The Caliber and Pecos Valley investments were sold in November 2013 and August 2012, respectively.
Interest Expense
Comparative Components of Interest Expense for the Twelve Months Ended December 31, 2013 and 2012
Comparative Components of Interest Expense for the Twelve Months Ended December 31, 2012 and 2011
Indirect Selling, General and Administrative Expenses
The increase in indirect selling, general and administrative expenses for both 2013 and 2012 is primarily a result of higher allocated overhead expenses from Martin Resource Management as a result of increased time spent on Partnership activities.
Martin Resource Management allocates to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. GAAP also permits other methods for allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocation for these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income.
Under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The Conflicts Committee approved the following reimbursement amounts:
The amounts reflected above represent our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.
Liquidity and Capital Resources
General
Our primary sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures are cash flows generated by our operations and access to debt and equity markets, both public and private. We have recently completed several transactions that have improved our liquidity position, helping fund our acquisitions and organic growth projects. In February 2013, we received net proceeds of $245.1 million from a private placement of senior unsecured notes. Under the registration rights agreement related to this issuance, we filed with the SEC a registration statement to exchange these notes for substantially identical notes that are registered under the Securities Act, and completed the exchange offer on July 31, 2013. We made certain strategic amendments under our revolving credit facility, including most recently in February 2014 when we increased our maximum borrowing capacity from $600.0 million to $637.5 million utilizing the accordion feature of our revolving credit facility.
As a result of these financing activities, discussed in further detail below, management believes that expenditures for our current capital projects will be funded with cash flows from operations, current cash balances and our current borrowing capacity under the expanded revolving credit facility. However, it may be necessary to raise additional funds to finance our future capital requirements.
Our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will also depend upon our future operating performance, which is subject to certain risks. Please read “Item 1A. Risk Factors - Risks related to Our Business” for a discussion of such risks.
Debt Financing Activities
On February 18, 2014, we increased the maximum amount of borrowings and letters of credit under our revolving credit facility from $600.0 million to $637.5 million utilizing the accordion feature of our revolving credit facility.
On March 28, 2013, we amended and restated our revolving credit facility to (i) increase the maximum amount of borrowings and letters of credit under our revolving credit facility from $400.0 million to $600.0 million, (ii) extend the maturity date of all amounts outstanding under our revolving credit facility from April 15, 2016 to March 28, 2018, (iii) decrease the applicable interest rate margin on committed revolver loans under our revolving credit facility as described in more detail below, (iv) adjust the financial covenants as described in more detail below, (v) increase the maximum allowable amount of additional outstanding indebtedness of the borrower and us and certain of our subsidiaries as described in more detail below, and (vi) adjust the commitment fee incurred on the unused portion of the loan facility as described in more detail below.
On February 11, 2013, we completed a private placement of $250.0 million in aggregate principal amount of 7.250% senior unsecured notes due 2021 to qualified institutional buyers under Rule 144A. We received proceeds of approximately $245.1 million, after deducting initial purchasers' discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under our revolving credit facility. On July 1, 2013, we filed a registration statement on Form S-4 with the SEC to exchange the Notes for registered 7.250% senior unsecured notes due February 2021. The exchange offer was completed on July 31, 2013.
On May 24, 2012, we redeemed $25.0 million of our senior unsecured notes from various holders using proceeds of our January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under our revolving credit facility. On February 28, 2014, we announced that we will exercise a full redemption of the remaining amount of the 2018 senior unsecured notes pursuant to the indenture, on or about April 1, 2014 at an aggregate redemption value of $182.8 million. We expect to fund the redemption under borrowings from our revolving credit facility.
Equity Offerings
On November 26, 2012, we completed a public offering of 3,450,000 common units at a price of $31.16 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses were $102.8 million. Our general partner contributed $2.2 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. All of the net proceeds were used to reduce our outstanding indebtedness.
On January 25, 2012, we completed a public offering of 2,645,000 common units at a price of $36.15 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 2,645,000 common units, net of underwriters’ discounts, commissions and offering expenses were $91.4 million. Our general partner contributed $2.0 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. All of the net proceeds were used to reduce our outstanding indebtedness.
Due to the foregoing, we believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements and anticipated maintenance capital expenditures in 2014.
Finally, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks. Please read “Item 1A. Risk Factors - Risks Relating to Our Business” for a discussion of such risks.
Cash Flows - Twelve Months Ended December 31, 2013 Compared to Twelve Months Ended December 31, 2012
The following table details the cash flow changes between the twelve months ended December 31, 2013 and 2012:
Net cash provided by operating activities increased for the year ended December 31, 2013 primarily due to an $76.8 million favorable variance in working capital. This change resulted principally from a reduction in accounts and other receivables attributable to the timing of cash receipts from customers in our Natural Gas Services segment.
The increase in cash used in investing activities for the year ended December 31, 2013 is attributable to $275.0 million of proceeds from the 2012 sale of the Prism Assets. Additionally, 2012 includes $56.0 million of proceeds from the sale of acquired assets to Martin Resource Management. The lack of sales proceeds in 2013 was partially offset by a $150.7 million decrease in acquisition expenditures.
Net cash provided by financing activities increased for the year ended December 31, 2013 as a result of: (i) $168.0 million increase in net proceeds from long-term debt (borrowings less repayments), which includes $250.0 million from the issuance of 7.250% Senior Notes; (ii) $142.1 million of cash used in 2012 related to assets purchased from Martin Resource Management; (iii) the lack of proceeds from public offerings in 2013; and (iv) higher cash distributions and debt issuance costs of $8.1 million and $8.9 million, respectively, in 2013.
Cash Flows - Twelve Months Ended December 31, 2012 Compared to Twelve Months Ended December 31, 2011
The following table details the cash flow changes between the twelve months ended December 31, 2012 and 2011:
Net cash provided by operating activities decreased for the year ended December 31, 2012 compared to the prior year period primarily due to a $61.6 million unfavorable variance in working capital. Working capital negatively affected cash provided by operating activities in 2012 principally due to the increase in accounts and other receivables from higher revenues in our Natural Gas Services segment. Working capital positively affected cash provided by operating activities in 2011 due to decreases in accounts and other receivables, product exchange receivables and inventories caused by price increases principally in our Natural Gas Services and Sulfur Services segments being funded through larger increases in trade and other accounts payable, product exchange payables and due to affiliates.
Net cash used in investing activities decreased for the year ended December 31, 2012 due to a $285.5 million increase in cash provided by discontinued operations resulting from the $275.0 million in proceeds from the 2012 sale of the Prism assets. In addition, investments in unconsolidated entities decreased $58.5 million in 2012. Also positively impacting 2012 was $56.0 million of proceeds from the sale of acquired assets. Partially offsetting these positive changes were increased acquisition and capital expenditures of $207.8 million and $16.4 million, respectively, in 2012.
Net cash provided by (used in) financing activities decreased for the year ended December 31, 2012 due to: (i) increased expenditures of $122.4 million related to assets purchased from Martin Resource Management; (ii) $66.0 million decrease in net proceeds from long-term debt (borrowings less repayments); (iii) $33.0 million increase in funding of investments in unconsolidated entities; and (iv) $12.0 million of increased cash distributions. Positively impacting cash flow from financing activities was an increase in proceeds from public offerings of $123.8 million.
Capital Expenditures
Our operations require continual investment to upgrade or enhance operations and to ensure compliance with safety, operational, and environmental regulations. Our capital expenditures consist primarily of:
•maintenance capital expenditures made to maintain existing assets and operations;
•expansion capital expenditures to acquire assets to grow our business, to expand existing facilities, such as projects that increase operating capacity, or to reduce operating costs; and
•plant turnaround costs made at our refinery to perform maintenance, overhaul and repair operations and to inspect, test and replace process materials and equipment.
The following table summarizes maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented:
Expansion capital expenditures were made primarily in our Terminalling and Storage segment during the three and twelve months ended December 31, 2013. Within our Terminalling and Storage segment, expenditures were made primarily at our Corpus Christi crude terminal, Smackover refinery, and certain smaller organic growth projects ongoing in our specialty terminalling operations. Maintenance capital expenditures were made primarily in our Terminalling and Storage, Marine Transportation, and Sulfur Services segments to maintain our existing assets and operations during the three and twelve months ended December 31, 2013.
Expansion capital expenditures were made primarily in our Terminalling and Storage, Marine Transportation, and Sulfur Services segments during the three and twelve months ended December 31, 2012. Within our Terminalling and Storage segment, expenditures were made primarily at our Corpus Christi crude terminal and Smackover refinery. Within our Marine Transportation segment, expenditures were made to upgrade certain assets in the inland fleet. Within our Sulfur Services segment, expenditures were made to expand operations at our Neches prilling facility. Maintenance capital expenditures were made primarily in our Terminalling and Storage and Sulfur Services segments to maintain our existing assets and operations
during the three and twelve months ended December 31, 2012. For the twelve months ended December 31, 2012, plant turnaround costs include refinery turnaround expenditures at our Smackover refinery.
Capital Resources
Historically, we have generally satisfied our working capital requirements and funded our capital expenditures with cash generated from operations and borrowings. We expect our primary sources of funds for short-term liquidity will be cash flows from operations and borrowings under our credit facility.
As of December 31, 2013, we had $658.7 million of outstanding indebtedness, consisting of outstanding borrowings of $423.7 million (net of unamortized discount) in senior unsecured notes and $235.0 million under our revolving credit facility.
Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2013, is as follows (dollars in thousands):
¹Interest commitments are estimated using our current interest rates for the respective credit agreements over their remaining terms.
Letter of Credit. At December 31, 2013, we had outstanding irrevocable letters of credit in the amount of $0.1 million, which were issued under our revolving credit facility.
Off Balance Sheet Arrangements. We do not have any off-balance sheet financing arrangements.
Description of Our Long-Term Debt
2021 Senior Notes
We and Martin Midstream Finance Corp., a subsidiary of us (collectively, the “Issuers”), entered into (i) an Indenture, dated as of February 11, 2013 (the “2021 Indenture”) among the Issuers, certain subsidiary guarantors (the “2021 Guarantors”) and Wells Fargo Bank, National Association, as trustee (the “2021 Trustee”) and (ii) a Registration Rights Agreement, dated as of February 11, 2013 (the “2021 Registration Rights Agreement”), among the Issuers, the 2021 Guarantors and Wells Fargo Securities, LLC, RBC Capital Markets, LLC, RBS Securities Inc., SunTrust Robinson Humphrey, Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of a group of initial purchasers, in connection with a private placement to eligible purchasers of $250.0 million in aggregate principal amount of the Issuers' 7.250% senior unsecured notes due 2021 (the “2021 Notes”).
Interest and Maturity. On February 11, 2013, the Issuers issued the 2021 Notes pursuant to the 2021 Indenture in a transaction exempt from registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The 2021 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside
the United States pursuant to Regulation S under the Securities Act. The 2021 Notes will mature on February 15, 2021. The interest payment dates are February 15 and August 15, beginning on August 15, 2013.
Optional Redemption. Prior to February 15, 2016, the Issuers have the option on any one or more occasions to redeem up to 35% of the aggregate principal amount of the 2021 Notes issued under the 2021 Indenture, at a redemption price of 107.250% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date of the 2021 Notes with the proceeds of certain equity offerings. Prior to February 15, 2017, the Issuers may on any one or more occasions redeem all or a part of the 2021 Notes at the redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. On or after February 15, 2017, the Issuers may on any one or more occasions redeem all or a part of the 2021 Notes at the redemption prices (expressed as percentages of principal amount) equal to 103.625% for the twelve-month period beginning on February 15, 2017, 101.813% for the twelve-month period beginning on February 15, 2018 and 100.00% for the twelve-month period beginning on February 15, 2019 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2021 Notes.
Certain Covenants. The 2021 Indenture restricts our ability and the ability of certain of our subsidiaries to: (i) sell assets including equity interests in our subsidiaries; (ii) pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries; (x) enter into sale and leaseback transactions; or (xi) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If the 2021 Notes achieve an investment grade rating from each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the 2021 Indenture) has occurred and is continuing, many of these covenants will terminate.
Events of Default. The 2021 Indenture provides that each of the following is an Event of Default: (i) default for 30 days in the payment when due of interest on the 2021 Notes; (ii) default in payment when due of the principal of, or premium, if any, on the 2021 Notes; (iii) failure by us to comply with certain covenants relating to asset sales, repurchases of the 2021 Notes upon a change of control and mergers or consolidations; (iv) failure by us for 180 days after notice to comply with our reporting obligations under the Securities Exchange Act of 1934; (v) failure by us for 60 days after notice to comply with any of the other agreements in the 2021 Indenture; (vi) default under any mortgage, indenture or instrument governing any indebtedness for money borrowed or guaranteed by us or any of our restricted subsidiaries, whether such indebtedness or guarantee now exists or is created after the date of the 2021 Indenture, if such default: (a) is caused by a payment default; or (b) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of the indebtedness, together with the principal amount of any other such indebtedness under which there has been a payment default or acceleration of maturity, aggregates $20.0 million or more, subject to a cure provision; (vii) failure by us or any of our restricted subsidiaries to pay final judgments aggregating in excess of $20.0 million, which judgments are not paid, discharged or stayed for a period of 60 days; (viii) except as permitted by the 2021 Indenture, any subsidiary guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force or effect, or any 2021 Guarantor, or any person acting on behalf of any Guarantor, denies or disaffirms its obligations under its subsidiary guarantee; and (ix) certain events of bankruptcy, insolvency or reorganization described in the 2021 Indenture with respect to the Issuers or any of our restricted subsidiaries that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary of us. Upon a continuing Event of Default, the 2021 Trustee, by notice to the Issuers, or the holders of at least 25% in principal amount of the then outstanding 2021 Notes, by notice to the Issuers and the 2021 Trustee, may declare the 2021 Notes immediately due and payable, except that an Event of Default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Issuers, any restricted subsidiary of us that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of us, will automatically cause the 2021 Notes to become due and payable.
2021 Registration Rights Agreement. Under the 2021 Registration Rights Agreement, the Issuers and the 2021 Guarantors filed with the SEC a registration statement to exchange the 2021 Notes for substantially identical notes that are registered under the Securities Act, and completed the exchange offer on July 31, 2013.
2018 Senior Notes
The Issuers entered into (i) a Purchase Agreement, dated as of March 23, 2010 (the “2018 Purchase Agreement”), by and among the Issuers, certain subsidiary guarantors (the “2018 Guarantors”) and Wells Fargo Securities, LLC, RBC Capital Markets Corporation and UBS Securities, LLC, as representatives of a group of initial purchasers (collectively, the “2018 Initial Purchasers”), (ii) an Indenture, dated as of March 26, 2010 (the “2018 Indenture”), among the Issuers, the 2018 Guarantors and
Wells Fargo Bank, National Association, as trustee (the “2018 Trustee”) and (iii) a Registration Rights Agreement, dated as of March 26, 2010 (the “2018 Registration Rights Agreement”), among the Issuers, the 2018 Guarantors and the 2018 Initial Purchasers, in connection with a private placement to eligible purchasers of $200 million in aggregate principal amount of the Issuers’ 8.875% senior unsecured notes due 2018 (the “2018 Notes”). We completed the aforementioned 2018 Notes offering on March 26, 2010 and received proceeds of approximately $197.2 million, after deducting initial purchaser discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under our revolving credit facility.
2018 Indenture
Interest and Maturity. On March 26, 2010, the Issuers issued the 2018 Notes pursuant to the 2018 Indenture in a transaction exempt from registration requirements under the Securities Act. The 2018 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the U.S. pursuant to Regulation S under the Securities Act. The 2018 Notes will mature on April 1, 2018. The interest payment dates are April 1 and October 1.
Optional Redemption. Prior to April 1, 2013, the Issuers have the option on any one or more occasions to redeem up to 35% of the aggregate principal amount of the 2018 Notes issued under the 2018 Indenture at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date of the 2018 Notes with the proceeds of certain equity offerings. Prior to April 1, 2014, the Issuers may on any one or more occasions redeem all or a part of the 2018 Notes at the redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. On or after April 1, 2014, the Issuers may on any one or more occasions redeem all or a part of the 2018 Notes at redemption prices (expressed as percentages of principal amount) equal to 104.438% for the twelve-month period beginning on April 1, 2014, 102.219% for the 12-month period beginning on April 1, 2015 and 100.00% for the 12-month period beginning on April 1, 2016, and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2018 Notes.
On April 24, 2012 we notified the 2018 Trustee of our intention to exercise a partial redemption of the our 2018 Notes pursuant to the 2018 Indenture. On May 24, 2012, we redeemed $25.0 million of the 2018 Notes from various holders using proceeds of our January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under our revolving credit facility. On February 28, 2014, we announced that we will exercise a full redemption of the 2018 senior unsecured notes pursuant to the indenture, on or about April 1, 2014 at an aggregate redemption value of $182.8 million. We expect to fund the redemption under borrowings from our revolving credit facility.
Certain Covenants. The 2018 Indenture restricts our ability and the ability of certain of our subsidiaries to: (i) sell assets including equity interests in its subsidiaries; (ii) pay distributions on, redeem or repurchase its units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from its restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries; (x) enter into sale and leaseback transactions; or (xi) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If the 2018 Notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the 2018 Indenture) has occurred and is continuing, many of these covenants will terminate.
Events of Default. The 2018 Indenture provides that each of the following is an Event of Default: (i) default for 30 days in the payment when due of interest on the 2018 Notes; (ii) default in payment when due of the principal of, or premium, if any, on the 2018 Notes; (iii) our failure to comply with certain covenants relating to asset sales, repurchases of the 2018 Notes upon a change of control and mergers or consolidations; (iv) our failure, for 180 days after notice, to comply with its reporting obligations under the Securities Exchange Act of 1934; (v) our failure, for 60 days after notice, to comply with any of the other agreements in the 2018 Indenture; (vi) default under any mortgage, indenture or instrument governing any indebtedness for money borrowed or guaranteed by us or any of our restricted subsidiaries, whether such indebtedness or guarantee now exists or is created after the date of the 2018 Indenture, if such default: (a) is caused by a payment default; or (b) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of the indebtedness, together with the principal amount of any other such indebtedness under which there has been a payment default or acceleration of maturity, aggregates $20 million or more, subject to a cure provision; (vii) our or any of our restricted subsidiaries failure to pay final judgments aggregating in excess of $20 million, which judgments are not paid, discharged or stayed for a period of 60 days; (viii) except as permitted by the 2018 Indenture, any subsidiary guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force or effect, or any Guarantor, or any person acting on behalf of any Guarantor, denies or disaffirms its obligations under its subsidiary guarantee; and (ix) certain events of bankruptcy, insolvency or reorganization described in the 2018 Indenture with respect to the Issuers or any of our restricted subsidiaries that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a
significant subsidiary of us. Upon a continuing Event of Default, the 2018 Trustee, by notice to the Issuers, or the holders of at least 25% in principal amount of the then outstanding 2018 Notes, by notice to the Issuers and the 2018 Trustee, may declare the 2018 Notes immediately due and payable, except that an Event of Default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Issuers, any restricted subsidiary of us that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of us, will automatically cause the 2018 Notes to become due and payable.
2018 Registration Rights Agreement. Under the 2018 Registration Rights Agreement, the Issuers and the 2018 Guarantors filed with the SEC a registration statement to exchange the 2018 Notes for substantially identical notes that are registered under the Securities Act. We exchanged the 2018 Notes for registered 8.875% senior unsecured notes due April 2018.
Revolving Credit Facility
On November 10, 2005, we entered into a $225.0 million multi-bank credit facility, which has subsequently been amended multiple times. On March 28, 2013, we amended and restated our credit facility to (i) increase the maximum amount of borrowings and letters of credit under the credit facility from $400.0 million to $600.0 million, (ii) extend the maturity date of all amounts outstanding under the credit facility from April 15, 2016 to March 28, 2018, (iii) decrease the applicable interest rate margin on committed revolver loans under the credit facility as described in more detail below, (iv) adjust the financial covenants as described in more detail below, (v) increase the maximum allowable amount of additional outstanding indebtedness of the borrower and us and certain of its subsidiaries as described in more detail below, and (vi) adjust the commitment fee incurred on the unused portion of the loan facility as described in more detail below. The most recent amendment to our revolving credit facility occurred on February 18, 2014 when we increased our maximum amount of borrowings to $637.5 million utilizing the accordion feature of our revolving credit facility.
As of December 31, 2013, we had $235.0 million outstanding under the revolving credit facility and $0.1 million of letters of credit issued, leaving a maximum available to be borrowed under our credit facility for future revolving credit borrowings and letters of credit of $364.9 million. Subject to the financial covenants contained in our credit facility and based on our existing EBITDA (as defined in our credit facility) calculations, as of December 31, 2013, we have the ability to incur approximately $83.6 million of that amount.
The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. During the year ended December 31, 2013, the level of outstanding draws on our credit facility has ranged from a low of $40.0 million to a high of $298.0 million.
The credit facility is guaranteed by substantially all of our subsidiaries. Obligations under the credit facility are secured by first priority liens on substantially all of our assets and those of the guarantors, including, without limitation, inventory, accounts receivable, bank accounts, marine vessels, equipment, fixed assets and the interests in our subsidiaries and certain of our equity method investees.
We may prepay all amounts outstanding under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The credit facility requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, equity issuances and debt incurrences.
Indebtedness under the credit facility bears interest at our option at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. We pay a per annum fee on all letters of credit issued under the credit facility, and we pay a commitment fee per annum on the unused revolving credit availability under the credit facility. The letter of credit fee, the commitment fee and the applicable margins for our interest rate vary quarterly based on our leverage ratio (as defined in the credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows:
The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for LIBOR borrowings at December 31, 2013 is 3.00%.
The credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The maximum permitted leverage ratio is 5.25 to 1.00. The maximum permitted senior leverage ratio (as defined in the credit facility but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00. The minimum interest coverage ratio (as defined in the credit facility but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) is 2.50 to 1.00.
In addition, the credit facility contains various covenants, which, among other things, limit our and our subsidiaries’ ability to: (i) grant or assume liens; (ii) make investments (including investments in our joint ventures) and acquisitions; (iii) enter into certain types of hedging agreements; (iv) incur or assume indebtedness; (v) sell, transfer, assign or convey assets; (vi) 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; (vii) change the nature of our business; (viii) engage in transactions with affiliates; (ix) enter into certain burdensome agreements; (x) make certain amendments to the Omnibus Agreement and our material agreements; (xi) make capital expenditures; and (xii) permit our joint ventures to incur indebtedness or grant certain liens.
The credit facility contains customary events of default, including, without limitation, (i) failure to pay any principal, interest, fees, expenses or other amounts when due; (ii) failure to meet the quarterly financial covenants; (iii) 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; (iv) the failure of any representation or warranty to be materially true and correct when made; (v) our or any of our subsidiaries’ default under other indebtedness that exceeds a threshold amount; (vi) bankruptcy or other insolvency events involving us or any of our subsidiaries; (vii) judgments against us or any of our subsidiaries, in excess of a threshold amount; (viii) certain ERISA events involving us or any of our subsidiaries, in excess of a threshold amount; (ix) a change in control (as defined in the credit facility); and (x) the invalidity of any of the loan documents or the failure of any of the collateral documents to create a lien on the collateral.
The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls our general partner, the lenders under the credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under our credit facility if it is deemed to have a material adverse effect on us.
If an event of default relating to bankruptcy or other insolvency events occurs with respect to us or any of our subsidiaries, all indebtedness under our credit facility will immediately become due and payable. If any other event of default exists under our credit facility, the lenders may terminate their commitments to lend us money, accelerate the maturity of the indebtedness outstanding under the credit facility and exercise other rights and remedies. In addition, if any event of default exists under our credit facility, the lenders may commence foreclosure or other actions against the collateral.
As of March 3, 2014, our outstanding indebtedness includes $240.0 million under our credit facility.
We are subject to interest rate risk on our credit facility due to the variable interest rate and may enter into interest rate swaps to reduce this variable rate risk.
Seasonality
A substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and fertilizers, which fluctuate in part based on winter and spring weather conditions. The demand for NGLs is strongest during the winter heating season and the refinery blending season. The demand for fertilizers is strongest during the early spring planting season. However, our Terminalling and Storage and Marine Transportation segments and the molten sulfur business are typically not impacted by seasonal fluctuations. A significant portion of our net income is derived from our terminalling and storage, sulfur and marine transportation businesses. Therefore, we do not expect that our overall net income will be impacted by seasonality factors. However, extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact our Terminalling and Storage and Marine Transportation segments.
Impact of Inflation
Inflation did not have a material impact on our results of operations in 2013, 2012 or 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies. In the future, increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot provide assurance that we will be able to pass along increased operating expenses to our customers.
Environmental Matters
Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during 2013, 2012 or 2011.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 3.21% as of December 31, 2013. As of March 3, 2014, we had total indebtedness outstanding under our credit facility of $240.0 million, all of which was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on December 31, 2013, the impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $2.4 million annually.
We are not exposed to changes in interest rates with respect to our senior unsecured notes as these obligations are fixed rate. The estimated fair value of the senior unsecured notes was approximately $443.8 million as of December 31, 2013, based on market prices of similar debt at December 31, 2013. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in approximately an $14.2 million decrease in fair value of our long-term debt at December 31, 2013.
Item 8.
Item 8.
Financial Statements and Supplementary Data
The following financial statements of Martin Midstream Partners L.P. (Partnership) are listed below:
Report of Independent Registered Public Accounting Firm
The Board of Directors
Martin Midstream GP LLC:
We have audited the accompanying consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, changes in capital, and cash flows for each of the years in the three-year period ended December 31, 2013. These financial statements are the responsibility of Martin Midstream’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (U.S.). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2013 and 2012 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (U.S.), Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 3, 2014 expressed an unqualified opinion on the effectiveness of Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting.
/s/ KPMG LLP
Dallas, Texas
March 3, 2014
Report of Independent Registered Public Accounting Firm on Internal Controls
The Board of Directors
Martin Midstream GP LLC:
We have audited Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Martin Midstream’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting in Item 9A(b). Our responsibility is to express an opinion on Martin Midstream’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (U.S.). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Martin Midstream Partners L.P. and subsidiaries maintained, in all respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (U.S.), the consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, changes in capital, and cash flows for each of the years in the three-year period ended December 31, 2013, and our report dated March 3, 2013 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Dallas, Texas
March 3, 2014
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
See accompanying notes to consolidated financial statements.
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit amounts)
*Related Party Transactions Shown Below
See accompanying notes to consolidated financial statements.
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit amounts)
*Related Party Transactions Included Above
See accompanying notes to consolidated financial statements.
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit amounts)
See accompanying notes to consolidated financial statements.
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
See accompanying notes to consolidated financial statements.
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL
(Dollars in thousands)
See accompanying notes to consolidated financial statements.
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
See accompanying notes to consolidated financial statements.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
(1)
Organization and Description of Business
Martin Midstream Partners L.P. (the “Partnership”) is a publicly traded limited partnership with a diverse set of operations focused primarily in the United States “U.S.” Gulf Coast region. Its four primary business lines include: terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants; natural gas services, including liquids distribution services and natural gas storage; sulfur and sulfur-based products processing, manufacturing, marketing and distribution; and marine transportation services for petroleum products and by-products.
The petroleum products and by-products the Partnership collects, transports, stores and distributes are produced primarily by major and independent oil and gas companies who often turn to third parties, such as the Partnership, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, the Partnership's primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. The Partnership operates primarily in the U.S. Gulf Coast region, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the oil and gas exploration and production industry.
In 2011, the Partnership and Martin Resource Management Corporation (“Martin Resource Management” or “Parent”) formed Redbird Gas Storage LLC (“Redbird”), a natural gas storage joint venture to invest in Cardinal Gas Storage Partners LLC (“Cardinal”). Cardinal is a joint venture between Redbird and Energy Capital Partners (“ECP”) that is focused on the development, construction, operation and management of natural gas storage facilities across northern Louisiana and Mississippi. The Partnership now owns 100% of the Class A and Class B equity interests in Redbird. As of December 31, 2013 and 2012, Redbird owned an unconsolidated 42.21% and 41.28% interest in Cardinal, respectively. This investment is accounted for by the equity method.
On August 30, 2013, Martin Resource Management completed the sale of a 49% non-controlling voting interest (50% economic interest) in MMGP Holdings, LLC (“Holdings”), a newly-formed sole member of Martin Midstream GP LLC (“MMGP”), the general partner of the Partnership, to certain affiliated investment funds managed by Alinda Capital Partners (“Alinda”). Upon closing the transaction, Alinda appointed two representatives to serve on the board of directors of the general partner of the Partnership.
(2)
Significant Accounting Policies
(a) Principles of Presentation and Consolidation
The consolidated financial statements include the financial statements of the Partnership and its wholly-owned subsidiaries and equity method investees. In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. In addition, the Partnership evaluates its relationships with other entities to identify whether they are variable interest entities under certain provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”), 810-10 and to assess whether it is the primary beneficiary of such entities. If the determination is made that the Partnership is the primary beneficiary, then that entity is included in the consolidated financial statements in accordance with ASC 810-10. No such variable interest entities exist as of December 31, 2013 or 2012.
As discussed in Note 5, on July 31, 2012, the Partnership completed the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets. These assets, along with additional gathering and processing assets discussed in Note 5 are collectively referred to as the “Prism Assets.” The Partnership has presented the results of operations and cash flows of the Prism Assets as discontinued operations for the years ended December 31, 2012 and 2011.
On October 2, 2012, the Partnership, which owned 10.74% of the Class A interests and 100% of the Class B interests, acquired all of the remaining Class A interests in Redbird from Martin Underground Storage, Inc. (“MUS”), a subsidiary of Martin Resource Management. Redbird was formed by the Partnership and Martin Resource Management in 2011 to invest in Cardinal.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
On October 2, 2012, the Partnership acquired from Cross Oil Refining and Marketing, Inc. (“Cross”), a wholly-owned subsidiary of Martin Resource Management, certain specialty lubricant product blending and packaging assets (“Blending and Packaging Assets”).
The acquisitions of the Redbird Class A interests and the Blending and Packaging Assets were considered a transfer of net assets between entities under common control. The acquisitions of the Redbird Class A interests and the Blending and Packaging Assets are recorded at amounts based on the historical carrying value of these assets at October 2, 2012, and the Partnership is required to update its historical financial statements to include the activities of the Redbird Class A interests and the Blending and Packaging Assets as of the date of common control. The Partnership’s accompanying historical financial statements have been retrospectively updated to reflect the effects on financial position, cash flows and results of operations attributable to the activities of the Redbird Class A interests and the Blending and Packaging Assets as if the Partnership owned these assets for the periods presented. Net income attributable to the Redbird Class A interests and the activities of the Blending and Packaging Assets for periods prior to the Partnership’s acquisition of the assets is not allocated to the general and limited partners for purposes of calculating net income per limited partner unit. See Note 16.
Certain expense reclassifications were made to the Partnership's Consolidated Statements of Operations for the years ended December 31, 2012 and 2011 in order to conform to the current presentation.
(b) Product Exchanges
The Partnership enters into product exchange agreements with third parties, whereby the Partnership agrees to exchange natural gas liquids (“NGLs”) and sulfur with third parties. The Partnership records the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”) method. Product exchanges with the same counterparty are entered into in contemplation of one another and are combined. The net amount related to location differentials is reported in “Product sales” or “Cost of products sold” in the Consolidated Statements of Operations.
(c) Inventories
Inventories are stated at the lower of cost or market. Cost is determined by using the FIFO method for all inventories except lubricants and lubricants packaging inventories. Lubricants and lubricants packaging inventories cost is determined using standard cost, which approximates actual cost, computed on a FIFO basis.
(d) Revenue Recognition
Terminalling and Storage - Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate. For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility. When lubricants and drilling fluids are sold by truck or rail, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.
Natural Gas Services - NGL distribution revenue is recognized when product is delivered by truck to the Partnership's NGL customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, the Partnership recognizes NGL distribution revenue when the customer receives the product from either the storage facility or pipeline.
Sulfur Services - Revenue from sulfur product sales is recognized when the customer takes title to the product. Revenue from sulfur services is recognized as deliveries are made during each monthly period.
Marine Transportation - Revenue is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip.
(e) Equity Method Investments
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The Partnership uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus the Partnership’s share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. Under certain provisions of ASC 350-20, related to goodwill, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of ASC 323-10, which relates to the equity method of accounting for investments in common stock. No portion of the net income from these entities is included in the Partnership’s operating income.
In December 2013, Cardinal recorded a $129,384 impairment charge related to long-lived assets of its Monroe Gas Storage Company, LLC ("Monroe"). This amount represents the carrying value of the assets in excess of their fair value. The impairment resulted from the weaker than anticipated results of operations of Monroe. The Partnership's share of this charge was $54,053 and is included in “Equity in loss of unconsolidated entities” in the Consolidated Statement of Operations for the year ended December 31, 2013. The Partnership evaluated its remaining investment in Cardinal and determined that no additional impairment was necessary.
The Partnership owns 100% of the Class A and Class B equity interests in Redbird. Redbird, as of December 31, 2013 and 2012, owned a 42.21% and 41.28% interest in Cardinal, respectively.
The Partnership owns 100% of the preferred interests in Martin Energy Trading LLC (“MET”), a subsidiary of Martin Resource Management.
The Partnership sold its unconsolidated 50% interest in Caliber Gathering, LLC (“Caliber”) during 2013. See Note 10.
The Partnership's subsidiary, legal name of Prism Gas Systems I, L.P. (“Prism Gas”), owned unconsolidated 50% interests in three investees, which were sold in 2012. See Note 5.
Each of these interests is accounted for under the equity method of accounting.
(f) Property, Plant, and Equipment
Owned property, plant, and equipment is stated at cost, less accumulated depreciation. Owned buildings and equipment are depreciated using straight-line method over the estimated lives of the respective assets.
Equipment under capital leases is stated at the present value of minimum lease payments less accumulated amortization. Equipment under capital leases is amortized on a straight line basis over the estimated useful life of the asset.
Routine maintenance and repairs are charged to operating expense while costs of betterments and renewals are capitalized. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts, and the difference between net book value of the asset and proceeds from disposition is recognized as gain or loss.
(g) Goodwill and Other Intangible Assets
Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. The Partnership is required to identify its reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. The Partnership is required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, the Partnership would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired.
All four of the Partnership's “reporting units”, terminalling and storage, natural gas services, sulfur services and marine transportation, contain goodwill.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The Partnership has performed the annual impairment tests as of August 31, 2013, 2012, and 2011, and determined fair value in each reporting unit based on the weighted average of two valuation techniques: (i) the discounted cash flow method and (ii) the guideline public company method. At August 31, 2013, 2012, and 2011, the estimated fair value of each of the four reporting units was in excess of its carrying value, resulting in no impairment.
No triggering events occurred that would cause the Partnership to perform an impairment test at either December 31, 2013 or 2012.
Significant changes in these estimates and assumptions could materially affect the determination of fair value for each reporting unit which could give rise to future impairment. Changes to these estimates and assumptions can include, but may not be limited to, varying commodity prices, volume changes and operating costs due to market conditions and/or alternative providers of services.
(h) Debt Issuance Costs
Debt issuance costs relating to the Partnership’s revolving credit facility and senior unsecured notes are deferred and amortized over the terms of the debt arrangements.
In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership incurred debt issuance costs of $9,114, $204 and $3,588 in the years ended December 31, 2013, 2012 and 2011, respectively.
Due to a reduction in the number of lenders under the Partnership’s multi-bank credit agreement, $502, $0 and $494 of the existing debt issuance costs were determined not to have continuing benefit and were expensed during 2013, 2012 and 2011, respectively. Remaining unamortized deferred issuance costs are amortized over the term of the revised debt arrangement.
Amortization of debt issuance costs, which is included in interest expense, totaled $3,700, $3,290 and $3,755 for the years ended December 31, 2013, 2012 and 2011, respectively. Accumulated amortization amounted to $5,270 and $6,014 at December 31, 2013 and 2012, respectively.
(i) Impairment of Long-Lived Assets
In accordance with ASC 360-10, long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell and are no longer depreciated. The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet. The Partnership has not identified any triggering events in 2013, 2012 or 2011 that would require an assessment for impairment of long-lived assets.
(j) Asset Retirement Obligations
Under ASC 410-20, which relates to accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, the Partnership records an Asset Retirement Obligation (“ARO”) at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset. The Partnership’s fixed assets include land, buildings, transportation equipment, storage equipment, marine vessels and operating equipment.
(k) Derivative Instruments and Hedging Activities
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
In accordance with certain provisions of ASC 815-10 related to accounting for derivative instruments and hedging activities, all derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.
Derivative instruments not designated as hedges are marked to market with all market value adjustments being recorded in the Consolidated Statements of Operations. As of December 31, 2013, the Partnership did not have any hedging instruments outstanding. Fair value changes associated with the Partnership's hedges have been recorded in accumulated other comprehensive income (“AOCI”) as a component of equity during 2012 and 2011.
(l) Comprehensive Income
Comprehensive income includes net income and other comprehensive income. Other comprehensive income for the Partnership includes unrealized gains and losses on derivative financial instruments. In accordance with ASC 815-10, the Partnership records deferred hedge gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income.
(m) Use of Estimates
Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the U.S. Actual results could differ from those estimates.
(n) Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses are incurred by Martin Resource Management and allocated to the Partnership to cover costs of centralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services. Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services. Under an omnibus agreement with Martin Resource Management, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2013, 2012 and 2011, the conflicts committee of the Partnership's general partner (“Conflicts Committee”) approved reimbursement amounts of $10,621, $7,593 and $4,771, respectively, reflecting the Partnership's allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.
(o) Environmental Liabilities and Litigation
The Partnership’s policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
(p) Accounts Receivable and Allowance for Doubtful Accounts.
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing accounts receivable.
(q) Deferred Catalyst Costs
The cost of the periodic replacement of catalysts is deferred and amortized over the catalyst’s estimated useful life, which ranges from 24 to 36 months.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
(r) Deferred Turnaround Costs
The Partnership capitalizes the cost of major turnarounds and amortizes these costs over the estimated period to the next turnaround, which ranges from 24 to 36 months.
(s) Income Taxes
With respect to the Partnership’s taxable subsidiary (Woodlawn Pipeline Co., Inc.) and the Blending and Packaging Assets prior to the date of acquisition from Cross, income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
As discussed further in Note 19, the assets of the Partnership's taxable subsidiary Woodlawn Pipeline Co., Inc were disposed of on July 31, 2012. The entity was dissolved on December 31, 2012.
(3)
Recent Accounting Pronouncements
In February 2013, the FASB amended the provisions of ASC 220 related to AOCI, which does not change the current requirements for reporting net income or other comprehensive income in financial statements. The standard requires entities to provide information about the amounts reclassified out of AOCI by component. The entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income but only if the amount reclassified is required under United States Generally Accepted Accounting Principles (“U.S. GAAP”) to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This amended guidance was adopted by the Partnership effective January 1, 2013. As this new guidance only requires enhanced disclosure, adoption did not impact the Partnership's financial position or results of operations.
(4)
Acquisitions
Marine Transportation Equipment Purchase
On September 30, 2013, the Partnership acquired two previously leased inland tank barges from Martin Resource Management for $7,100. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these assets was recorded at the historical carrying value of the assets at the acquisition date. The Partnership recorded $6,799 to property, plant and equipment in the Marine Transportation segment and the excess of the purchase price over the carrying value of the assets of $301 was recorded as an adjustment to partners' capital. This transaction was funded with borrowings under the Partnership's revolving credit facility.
Sulfur Production Facility
On August 5, 2013, the Partnership acquired a plant nutrient sulfur production facility in Cactus, Texas for $4,118. The transaction was accounted for under the acquisition method of accounting in accordance with ASC 805 relating to business combinations. This transaction was funded by borrowings under the Partnership's revolving credit facility. Assets acquired and liabilities assumed were recorded in the Sulfur Services segment at fair value as follows:
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The Partnership's results of operations from these assets included revenues of $267 and a net loss of $284 for the year ended December 31, 2013.
NL Grease, LLC
On June 13, 2013, the Partnership acquired certain assets of NL Grease, LLC (“NLG”) for $12,148. NLG is a Kansas City, Missouri based grease manufacturer that specializes in private-label packaging of commercial and industrial greases. The transaction was accounted for under the acquisition method of accounting in accordance with ASC 805 relating to business combinations. This transaction was funded by borrowings under the Partnership's revolving credit facility. The assets acquired by the Partnership were recorded in the Terminalling and Storage segment at fair value of $12,148 in the following purchase price allocation:
The purchase price allocation resulted in the recognition of $5,113 in definite-lived intangible assets with no residual value, including $2,418 of technology, $2,218 attributable to a customer list, and $477 attributable to a non-compete agreement. The amounts assigned to technology, the customer list, and the non-compete agreement are amortized over the estimated useful life of ten years, three years, and five years, respectively. The weighted average life over which these acquired intangibles will be amortized is approximately six years.
The Partnership completed the purchase price allocation during the third quarter of 2013, which resulted in an adjustment to working capital from the preliminary purchase price allocation in the amount of $55.
The Partnership's results of operations included revenues of $7,875 and a net loss of $167 for the year ended December 31, 2013 related to the NLG acquisition.
NGL Marine Equipment Purchase
On February 28, 2013, the Partnership purchased from affiliates of Florida Marine Transporters, Inc. six liquefied petroleum gas pressure barges and two commercial push boats for approximately $50,801, of which the commercial push boats totaling $8,201 were allocated to property, plant and equipment in the Partnership's Marine Transportation segment and the six pressure barges totaling $42,600 were allocated to property, plant and equipment in the Partnership's Natural Gas Services segment. This transaction was funded with borrowings under the Partnership's revolving credit facility.
Talen's Marine & Fuel, LLC
On December 31, 2012, the Partnership acquired all of the outstanding membership interests in Talen's Marine & Fuel LLC (“Talen's”) from QEP Marine Fuel Investment, LLC and QEP Marine Fuel Holdings, Inc. (collectively referred to as “Quintana Energy Partners”) for $103,368, subject to certain post-closing adjustments, including the assumption of a note payable in the amount of $2,971. The transaction was accounted for under the acquisition method of accounting in accordance with ASC 805 relating to business combinations. Additionally, as required by ASC 805, the Partnership expensed acquisition related costs, of which $58 were recorded in selling, general and administrative expenses for the year ended December 31, 2013. Through this acquisition, the Partnership acquired certain terminalling facilities and other terminalling related assets located along the Texas and Louisiana gulf coast. This transaction was funded by borrowings under the Partnership's revolving credit facility. Simultaneous with the acquisition, the Partnership sold certain working capital-related assets and a customer relationship intangible asset to Martin Energy Services LLC (“MES”), a wholly-owned subsidiary of Martin Resource Management for $56,000. Due to the Talen's acquisition, MES entered into various service agreements with Talen's pursuant to which the Partnership provides certain terminalling and marine services to MES. The excess carrying value of the assets over the purchase price paid by Martin Resource Management at the sales date was $4,268 and was recorded as an adjustment to
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
partners' capital. The remaining net assets retained by the Partnership were recorded at fair value of $43,100 in the following purchase price allocation:
Goodwill recognized from the acquisition primarily relates to the expected contributions of the entity to the overall corporate strategy in addition to synergies and acquired workforce, which are not separable from goodwill.
The Partnership's results of operations included revenues of $5,226 and net income of $1,038 for the year ended December 31, 2013 related to the Talen's acquisition.
Lubricant Blending and Packaging Assets
On October 2, 2012, the Partnership purchased the Blending and Packaging Assets from Cross. The consideration consisted of $121,767 in cash at closing, plus a final net working capital adjustment of $907 paid in October of 2012. This transaction was funded by borrowings under the Partnership's revolving credit facility. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of the Blending and Packaging Assets was recorded at the historical carrying value of the assets at the acquisition date, which were as follows:
The excess purchase price over the historical carrying value of the assets at the acquisition date was $60,308 and was recorded as an adjustment to partners' capital.
Redbird Class A Interests
On October 2, 2012, the Partnership acquired from Martin Resource Management all of the remaining Class A interests in Redbird for $150,000 in cash. The Partnership began making Class A investments in Redbird during the fourth quarter of 2011. Prior to the transaction, the Partnership owned a 10.74% Class A interest and a 100% Class B interest in Redbird. This transaction was funded by borrowings under the Partnership's revolving credit facility. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these interests was recorded at the historical carrying value of the interests at the acquisition date. The Partnership recorded an investment in consolidated
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
entities of $68,233 and the excess of the purchase price over the carrying value of the Class A interests of $81,767 was recorded as an adjustment to partners' capital.
Redbird Class B Interests
On May 31, 2011, the Partnership acquired all of the Class B equity interests in Redbird for approximately $59,319. This amount was recorded as an investment in an unconsolidated entity. Concurrent with the closing of this transaction, Cardinal acquired all of the outstanding equity interests in Monroe as well as an option on development rights to an adjacent depleted reservoir facility. This transaction was funded by borrowings under the Partnership’s revolving credit facility.
Terminalling Facilities
On January 31, 2011, the Partnership acquired 13 shore-based marine terminalling facilities, one specialty terminalling facility and certain terminalling related assets from Martin Resource Management for $36,500. These assets are located across the Louisiana Gulf Coast. This transaction was funded by borrowings under the Partnership’s revolving credit facility.
These terminalling assets were acquired by Martin Resource Management in its acquisition of L&L Holdings, LLC (“L&L”) on January 31, 2011. During the second quarter of 2011, Martin Resource Management finalized the purchase price allocation for the acquisition of L&L, including the final determination of the fair value of the terminalling assets acquired by the Partnership. The Partnership recorded an adjustment in the amount of $19,685 to reduce property, plant and equipment and partners’ capital for the difference between the purchase price and the fair value of the terminalling assets acquired based on Martin Resource Management’s final purchase price allocation.
(5)
Discontinued Operations and Divestitures
On July 31, 2012, the Partnership completed the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas and other natural gas gathering and processing assets also owned by the Partnership to a subsidiary of CenterPoint Energy Inc. (NYSE: CNP) (“CenterPoint”). The Partnership received net cash proceeds from the sale of $273,269. The asset sale included the Partnership’s 50% operating interest in Waskom Gas Processing Company (“Waskom”). A subsidiary of CenterPoint owned the other 50% percent interest.
Additionally, on September 18, 2012, the Partnership completed the sale of its interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy, LLC (“PIPE”) to a private investor group for $1,530.
The Partnership classified the results of operations of the Prism Assets which were previously presented as a component of the Natural Gas Services segment, as discontinued operations in the Consolidated Statements of Operations for all periods presented.
The Prism Assets’ operating results, which are included in income from discontinued operations, were as follows:
1 Total revenues from third parties excludes intercompany revenues of $26,431, and $67,141 for the years ended December 31, 2012 and 2011, respectively.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
2 The Partnership recognized a gain on the sale of the Prism Assets of $61,848 in income from discontinued operations for the year ended December 31, 2012.
3 Represents equity in earnings of Waskom, Matagorda, and PIPE for the years ended December 31, 2012 and 2011.
(6)
Inventories
Components of inventories at December 31, 2013 and 2012 were as follows:
(7)
Property, Plant and Equipment
At December 31, 2013 and 2012, property, plant, and equipment consisted of the following:
Depreciation expense for the years ended December 31, 2013, 2012 and 2011 was $49,874, $40,724, and $37,869, respectively, which includes amortization of fixed assets under capital lease obligations of $233, $280 and $280, respectively. All capital lease obligations were retired in November 2013. Gross assets and accumulated amortization related to the assets under capital leases at December 31, 2012 were $7,764 and $955, respectively.
Additions to property, plant and equipment included in accounts payable at December 31, 2013 were $6,803.
(8) Goodwill and Other Intangibles
The following table represents the goodwill balance at December 31, 2012, changes during the year, and the resulting balances at December 31, 2013:
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
1 These changes represent the amounts allocated to goodwill as part of the purchase price accounting adjustments made during the completion of the Talen's purchase price allocation in 2013. See Note 4 for discussion of the Talen's acquisition.
Other intangible assets subject to amortization consist of covenants not-to-compete, customer lists, and technology-based assets.
The unamortized balance of other intangible assets, included in the Consolidated Balance Sheets as other assets, net, amounted to $4,158 and $198 at December 31, 2013 and 2012, respectively.
Aggregate amortization expense for intangible assets included in continuing operations was $1,153, $140, and $140, for the years ended December 31, 2013, 2012 and 2011, respectively, and accumulated amortization amounted to $2,353 and $1,200 at December 31, 2013 and 2012, respectively.
Estimated amortization expenses for the years subsequent to December 31, 2013 are as follows: 2014 - $1,435; 2015 - $816; 2016 - $461; 2017 - $349; 2018 - $273; subsequent years - $824.
(9) Leases
The Partnership has numerous non-cancelable operating leases primarily for terminal facilities and transportation and other equipment. The leases generally provide that all expenses related to the equipment are to be paid by the lessee. Management expects to renew or enter into similar leasing arrangements for similar equipment upon the expiration of the current lease agreements. The Partnership also has cancelable operating lease land rentals and outside marine vessel charters.
The Partnership’s future minimum lease obligations as of December 31, 2013 consist of the following:
Rent expense for continuing operating leases for the years ended December 31, 2013, 2012 and 2011 was $15,629, $15,801 and $19,280, respectively. The amount recognized in interest expense for capital leases was $796, $945, and $972 for the years ended December 31, 2013, 2012 and 2011, respectively. As discussed in Note 15, the Partnership's capital lease obligations were retired in November of 2013.
(10) Investments in Unconsolidated Entities and Joint Ventures
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
As discussed in detail in Note 5, the Partnership sold its 50% interests in Waskom, Matagorda, and PIPE in 2012. The equity in earnings associated with these investments during the periods owned is recorded in income from discontinued operations for the years ended December 31, 2012 and 2011.
On May 1, 2008, certain assets and liabilities were contributed to acquire a 50% ownership interest in Cardinal. In conjunction with this transaction, ECP contributed cash for a 50% ownership interest in Cardinal.
The initial carrying amount of the investment in Cardinal was less than the contributed underlying net assets. Of the basis difference, $1,250 relates to differences in the carrying value of fixed assets contributed as compared to amounts recorded by Cardinal, and is being amortized over 40 years, the approximate useful life of the underlying assets. Such amortization amounted to $31 for each of the three years ending December 31, 2013, 2012 and 2011. The remaining basis difference is a permanent difference that will be realized upon sale of the investment in Cardinal.
On May 24, 2011, Redbird was formed to hold membership interests in Cardinal. On May 27, 2011, initial contributions consisted of all of Martin Resource Management’s membership interests in Cardinal for 100% of the Class A interests in Redbird. Simultaneously, the Partnership acquired 100% of the Class B interests in Redbird for approximately $59,319. Concurrent with the closing of this transaction, Redbird contributed the cash to Cardinal which used the cash, along with a contribution from ECP, to acquire all of the outstanding equity interests in Monroe as well as an option on development rights to an adjacent depleted reservoir facility. As discussed in Notes 2 and 4, on October 2, 2012, the Partnership, acquired the remaining Class A interests in Redbird. As this acquisition is considered a transfer of net assets between entities under common control, the acquisition is recorded at the historical carrying value of these assets at that date. The Partnership is required to retrospectively update its historical financial statements to include the activities of the Class A interests in Redbird as of the date of common control. The Partnership's accompanying historical financial statements for the years ended December 31, 2012 and 2011 have been retrospectively updated to reflect the effects on financial position, cash flows and results of operations attributable to the Redbird Class A interests (including predecessor activities related to the amounts contributed to form Cardinal and Cardinal activities prior to the formation of Redbird) as if the Partnership owned these assets for these periods.
In December 2013, Cardinal recorded a $129,384 impairment charge related to long-lived assets of Monroe. This amount represents the carrying value of the assets in excess of their fair value. The impairment resulted from the weaker than anticipated results of operations of Monroe. The Partnership's share of this charge is $54,053 and is included in “Equity in loss of unconsolidated entities” in the Consolidated Statement of Operations for the year ended December 31, 2013. The Partnership evaluated its remaining investment in Cardinal and determined that no additional impairment was necessary.
As of December 31, 2013, Redbird owned an unconsolidated 42.21% interest in Cardinal.
During March 2013, the Partnership acquired 100% of the preferred interests in MET for $15,000.
During the second quarter of 2012, the Partnership acquired an unconsolidated 50% interest in Caliber and Pecos Valley Producer Services, LLC (“Pecos Valley”). The Partnership sold its interest in Caliber during the fourth quarter of 2013 for $750, resulting in a gain of $750 recorded in other, net in the Partnership's Consolidated Statements of Operations for the year ended December 31, 2013. The Partnership sold its interest in Pecos Valley during the third quarter of 2012 for $531, resulting in a gain of $486 recorded in other, net in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2012.
These investments are accounted for by the equity method.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The following tables summarize the components of the investment in unconsolidated entities on the Partnership’s Consolidated Balance Sheets and the components of equity in earnings of unconsolidated entities included in the Partnership’s Consolidated Statements of Operations:
1 For all periods presented, the financial information for Waskom, Matagorda, and PIPE is included on the Consolidated Statements of Operations and Cash Flows as discontinued operations.
Selected financial information for significant unconsolidated equity method investees is as follows:
As of December 31, 2013 and 2012, the Partnership’s interest in cash of the unconsolidated equity method investees was $3,703 and $1,265, respectively.
(11) Fair Value Measurements
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The Partnership uses a valuation framework based upon inputs that market participants use in pricing certain assets and liabilities. These inputs are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources. Unobservable inputs represent the Partnership's own market assumptions. Unobservable inputs are used only if observable inputs are unavailable or not reasonably available without undue cost and effort. The two types of inputs are further prioritized into the following hierarchy:
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 reflect the entity's own assumptions and are not corroborated by market data.
The following items are measured at fair value on a recurring and non-recurring basis at December 31, 2013 and 2012:
The Partnership is required to disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for these financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument:
•
Accounts and other receivables, trade and other accounts payable, accrued interest payable, other accrued liabilities, income taxes payable and due from/to affiliates: The carrying amounts approximate fair value due to the short maturity and highly liquid nature of these instruments, and as such these have been excluded from the table above.
•
Long-term debt including current portion: The carrying amount of the revolving credit facility approximates fair value due to the debt having a variable interest rate and is in Level 2. The estimated fair value of the senior unsecured notes is based on market prices of similar debt. The carrying amount of the note payable to bank as of December 31, 2012 is not deemed to be significantly different than the fair value. This note was retired during 2013.
(12) Derivative Instruments and Hedging Activities
The Partnership’s results of operations are materially impacted by changes in crude oil, natural gas and NGL prices and interest rates. In an effort to manage its exposure to these risks, the Partnership periodically enters into various derivative instruments, including commodity and interest rate hedges.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
(a) Commodity Derivative Instruments
The Partnership has from time to time used derivatives to manage the risk of commodity price fluctuation. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with potential commodity risk exposure. These hedging arrangements have been in the form of swaps for crude oil, natural gas and natural gasoline. In addition, the Partnership has focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.
Due to the sale of the Prism Assets during 2012, the Partnership terminated and settled all of its commodity derivative instruments during the second quarter of 2012. For the years ended December 31, 2012 and 2011, changes in the fair value of the Partnership’s derivative contracts were recorded in both earnings (income from discontinued operations) and in AOCI as a component of partners’ capital. As of December 31, 2013, the Partnership did not have any commodity derivative instruments outstanding.
(b) Impact of Commodity Cash Flow Hedges
Crude Oil. For the years ended December 31, 2012 and 2011, net gains and losses on swap hedge contracts increased crude revenue (included in income from discontinued operations) by $496 and $775, respectively.
Natural Gas. For the years ended December 31, 2012 and 2011, net gains and losses on swap hedge contracts increased gas revenue (included in income from discontinued operations) by $813 and $332, respectively.
Natural Gas Liquids. For the years ended December 31, 2012 and 2011, net gains and losses on swap hedge contracts increased liquids revenue (included in income from discontinued operations) by $1,066 and $254, respectively.
For information regarding fair value amounts and gains and losses on commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note.
(c) Impact of Interest Rate Derivative Instruments
The Partnership is exposed to market risks associated with interest rates. From time to time, the Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate debt and term loan credit facilities. As of December 31, 2013, the Partnership did not have any interest rate derivative instruments outstanding.
In August 2011, the Partnership terminated all of its existing interest swap agreements with an aggregate notional amount of $100,000, which it had entered to hedge its exposure to changes in the fair value of the 2018 senior unsecured notes. These interest rate swap contracts were not designated as fair value hedges and therefore, did not receive hedge accounting but were marked to market through earnings. A termination benefit of $2,800 was received on the early extinguishment of the interest rate swap agreements in August 2011.
The Partnership recognized increases in interest expense of $0 and $5,779 for the years ended December 31, 2012 and 2011, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate swaps and hedges.
For information regarding fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see “Tabular Presentation of Gains and Losses on Derivative Instruments and Related Hedged Items” below.
Tabular Presentation of Gains and Losses on Derivative Instruments and Related Hedged Items
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
(13) Related Party Transactions
As of December 31, 2013, Martin Resource Management owned 5,093,267 of the Partnership’s common units representing approximately 19.1% of the Partnership’s outstanding limited partnership units. Martin Resource Management controls the Partnership's general partner by virtue of its 51% voting interest in Holdings, the sole member of the Partnership's general partner. The Partnership’s general partner, MMGP, owns a 2% general partner interest in the Partnership and the Partnership’s incentive distribution rights (“IDRs”). The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership as of December 31, 2013, of approximately 19.1% of the Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’s management.
The following is a description of the Partnership’s material related party agreements:
Omnibus Agreement
Omnibus Agreement. The Partnership and its general partner are parties to an omnibus agreement dated November 1, 2002, with Martin Resource Management (the “Omnibus Agreement”) that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and the Partnership’s use of certain of Martin Resource Management’s trade names and trademarks. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.
Non-Competition Provisions. Martin Resource Management has agreed for so long as it controls the general partner of the Partnership, not to engage in the business of:
•
providing terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants;
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
•providing marine transportation of petroleum products and by-products;
•distributing NGLs; and
•manufacturing and selling sulfur-based fertilizer products and other sulfur-related products.
This restriction does not apply to:
•
the ownership and/or operation on the Partnership’s behalf of any asset or group of assets owned by it or its affiliates;
•
any business operated by Martin Resource Management, including the following:
◦
providing land transportation of various liquids;
◦
distributing fuel oil, sulfuric acid, marine fuel and other liquids;
◦
providing marine bunkering and other shore-based marine services in Alabama, Florida, Louisiana, Mississippi and Texas;
◦
operating a crude oil gathering business in Stephens, Arkansas;
◦
providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas;
◦
operating an underground NGL storage facility in Arcadia, Louisiana;
◦
operating an environmental consulting company;
◦
operating an engineering services company;
◦
supplying employees and services for the operation of the Partnership's business;
◦
operating a natural gas optimization business;
◦
operating, for its account and the Partnership's account, the docks, roads, loading and unloading facilities and other common use facilities or access routes at the Partnership's Stanolind terminal; and
◦
operating, solely for the Partnership's account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas and South Houston, Texas.
•
any business that Martin Resource Management acquires or constructs that has a fair market value of less than $5,000;
•
any business that Martin Resource Management acquires or constructs that has a fair market value of $5,000 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 $5,000 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.
Services. Under the Omnibus Agreement, Martin Resource Management provides the Partnership with corporate staff, support services, and administrative services necessary to operate the Partnership’s business. The Omnibus Agreement requires the Partnership to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on the Partnership’s behalf or in connection with the operation of the Partnership’s business. There is no monetary limitation on the amount the Partnership is required to reimburse Martin Resource Management for direct expenses. In addition to the direct
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
expenses, under the Omnibus Agreement, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.
Effective January 1, 2014, through December 31, 2014, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $12,535. The Partnership reimbursed Martin Resource Management for $10,621, $7,593, and $4,772 of indirect expenses for the years ended December 31, 2013, 2012, and 2011, respectively. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.
These indirect expenses are intended to cover the centralized corporate functions Martin Resource Management provides for the Partnership, such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions the Partnership shares with Martin Resource Management retained businesses. The provisions of the Omnibus Agreement regarding Martin Resource Management’s services will terminate if Martin Resource Management ceases to control the general partner of the Partnership.
Related Party Transactions. The Omnibus Agreement prohibits the Partnership from entering into any material agreement with Martin Resource Management without the prior approval of the Conflicts Committee. For purposes of the Omnibus Agreement, the term material agreements means any agreement between the Partnership and Martin Resource Management that requires aggregate annual payments in excess of then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read “Services” above.
License Provisions. Under the Omnibus Agreement, Martin Resource Management has granted the Partnership a nontransferable, nonexclusive, royalty-free right and license to use certain of its trade names and marks, as well as the trade names and marks used by some of its affiliates.
Amendment and Termination. The Omnibus Agreement may be amended by written agreement of the parties; provided, however, that it may not be amended without the approval of the Conflicts Committee if such amendment would adversely affect the unitholders. The Omnibus Agreement was first amended on November 25, 2009, to permit the Partnership to provide refining services to Martin Resource Management. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management. Such amendments were approved by the Conflicts Committee. The Omnibus Agreement, other than the indemnification provisions and the provisions limiting the amount for which the Partnership will reimburse Martin Resource Management for general and administrative services performed on its behalf, will terminate if the Partnership is no longer an affiliate of Martin Resource Management.
Motor Carrier Agreement
Motor Carrier Agreement. The Partnership is a party to a motor carrier agreement effective January 1, 2006 as amended, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Transport, Inc. operates its land transportation operations. Under the agreement, Martin Transport, Inc. agreed to transport the Partnership's NGLs as well as other liquid products.
Term and Pricing. The agreement has an initial term that expired in December 2007 but 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. The Partnership has the right to terminate this agreement at any time by providing 90 days prior notice. Under this agreement, Martin Transport, Inc. transports the Partnership’s NGL shipments as well as other liquid products. These rates are subject to any adjustments which are mutually agreed or in accordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the U.S. Department of Energy’s national diesel price list.
Indemnification. Martin Transport has indemnified us against all claims arising out of the negligence or willful misconduct of Martin Transport and its officers, employees, agents, representatives and subcontractors. We indemnified Martin Transport against all claims arising out of the negligence or willful misconduct of us and our officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin Transport and us, our indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligence or misconduct.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Marine Agreements
Marine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, which was amended January 1, 2007, under which the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. Effective each January 1, this agreement automatically renews for consecutive one year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then applicable term. The fees the Partnership charges Martin Resource Management are based on applicable market rates.
Marine Fuel. The Partnership is a party to an agreement with Martin Resource Management dated November 1, 2002 under which Martin Resource Management provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate in excess of the Platt’s U.S. Gulf Coast Index for #2 Fuel Oil. Under this agreement, the Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management.
Terminal Services Agreements
Diesel Fuel Terminal Services Agreement. The Partnership is a party to an agreement under which the Partnership provides terminal services to Martin Resource Management. This agreement was amended and restated as of October 27, 2004, and was set to expire in December 2006, but automatically renewed and will continue to automatically renew on a month-to-month basis until either party terminates the agreement by giving 60 days' written notice. The per gallon throughput fee the Partnership charges under this agreement may be adjusted annually based on a price index.
Miscellaneous Terminal Services Agreements. The Partnership is currently party to several terminal services agreements and from time to time the Partnership may enter into other terminal service agreements for the purpose of providing terminal services to related parties. Individually, each of these agreements is immaterial but when considered in the aggregate they could be deemed material. These agreements are throughput based with a minimum volume commitment. Generally, the fees due under these agreements are adjusted annually based on a price index.
Talen's Agreements. In connection with the Talen's acquisition, new agreements were executed, each with effective dates of December 31, 2012. Under the terms of these contracts, Talen's provides terminal services to Martin Resource Management. The terminal services agreements both have five-year terms and provide a per gallon throughput rate, which may be adjusted annually based on a price index.
Other Agreements
Cross Tolling Agreement. The Partnership is a party to an agreement with Cross, originally dated November 25, 2009, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The tolling agreement, which has subsequently been amended, has a 22 year term which expires November 25, 2031. Under this tolling agreement, Cross agreed to process a minimum of 6,500 barrels per day of crude oil at the facility at a fixed price per barrel. Any additional barrels are processed at a modified price per barrel. In addition, Cross agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.
Sulfuric Acid Sales Agency Agreement. The Partnership is party to a second amended and restated sulfuric acid sales agency agreement dated August 5, 2013, under which Martin Resource Management purchases and markets the sulfuric acid produced by the Partnership’s sulfuric acid production plant at Plainview, Texas, that is not consumed by the Partnership’s internal operations. This agreement, as amended, will remain in place until the Partnership terminates it by providing 180 days’ written notice. Under this agreement, the Partnership sells all of its excess sulfuric acid to Martin Resource Management. Martin Resource Management then markets such acid to third-parties and the Partnership shares in the profit of Martin Resource Management’s sales of the excess acid to such third parties.
Other Miscellaneous Agreements. From time to time the Partnership enters into other miscellaneous agreements with Martin Resource Management for the provision of other services or the purchase of other goods.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The tables below summarize the related party transactions that are included in the related financial statement captions on the face of the Partnership’s Consolidated Statements of Operations. The revenues, costs and expenses reflected in these tables are tabulations of the related party transactions that are recorded in the corresponding caption of the Consolidated Statements of Operations and do not reflect a statement of profits and losses for related party transactions.
The impact of related party revenues from sales of products and services is reflected in the Consolidated Statements of Operations as follows:
The impact of related party cost of products sold is reflected in the Consolidated Statements of Operations as follows:
The impact of related party operating expenses is reflected in the Consolidated Statements of Operations as follows:
The impact of related party selling, general and administrative expenses is reflected in the Consolidated Statements of Operations as follows:
(14)
Other Accrued Liabilities
At December 31, 2013 and 2012, components of other accrued liabilities consisted of the following:
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
(15) Long-Term Debt and Capital Leases
At December 31, 2013 and 2012, long-term debt consisted of the following:
1 Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for LIBOR borrowings at December 31, 2013 is 3.00%. The credit facility contains various covenants which limit the Partnership’s ability to make certain investments and acquisitions; enter into certain agreements; incur indebtedness; sell assets; and make certain amendments to the Omnibus Agreement. The Partnership is permitted to make quarterly distributions so long as no event of default exists.
2 Pursuant to the indenture under which the senior notes were issued, the Partnership has the option to redeem up to 35% of the aggregate principal amount at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest with the proceeds of certain equity offerings. On April 24, 2012, the Partnership notified the trustee of its intention to exercise a partial redemption of the Partnership’s senior notes pursuant to the indenture. On May 24, 2012, the Partnership redeemed $25,000 of the senior notes from various holders using proceeds of the Partnership’s January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under the Partnership’s revolving credit facility. In conjunction with the redemption, the Partnership incurred a debt prepayment premium in the amount of $2,219, which is included in the Consolidated Statement of Operations for the year ended December 31, 2012.
3 Effective March 28, 2013, the Partnership increased the maximum amount of borrowings and letters of credit available under the Credit Facility from $400,000 to $600,000 and extended the maturity date of the facility from April 2016 to March 2018.
4 On February 11, 2013, the Partnership completed a private placement of $250,000 in aggregate principal amount of 7.250% senior unsecured notes due 2021 to qualified institutional buyers under Rule 144A. The Partnership filed with the SEC a registration statement to exchange the 2021 Notes for substantially identical notes that are registered under the Securities Act, and completed the exchange offer on July 31, 2013.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
5 The 2018 and 2021 indentures restrict the Partnership’s ability to sell assets; pay distributions or repurchase units or redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; and consolidate, merge or transfer all or substantially all of its assets. Many of these covenants will terminate if the notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred.
6 In November of 2013, the Partnership retired the capital lease obligations with borrowings under the Partnership's revolving credit facility. In conjunction with the retirement, the Partnership incurred a debt prepayment premium in the amount of $272, which is included in the Consolidated Statement of Operations for the year ended December 31, 2013.
7 In October of 2013, the Partnership retired the note payable to bank with borrowings under the Partnership's revolving credit facility.
The Partnership paid cash interest in the amount of $33,038, $29,239, and $22,818 for the years ended December 31, 2013, 2012 and 2011, respectively. Capitalized interest was $1,096, $1,136, and $624 for the years ended December 31, 2013, 2012 and 2011, respectively.
(16) Partners' Capital
As of December 31, 2013, partners’ capital consisted of 26,625,026 common limited partner units, representing a 98% partnership interest and a 2% general partner interest. Martin Resource Management, through subsidiaries, owned 5,093,267 of the Partnership's common limited partnership units representing approximately 19.1% of the Partnership's outstanding common limited partnership units. MMGP, the Partnership's general partner, owns the 2% general partnership interest.
The partnership agreement of the Partnership (the “Partnership Agreement”) contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts.
Issuance of Common Units
On November 26, 2012, the Partnership completed a public offering of 3,450,000 common units at a price of $31.16 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses were $102,809. The Partnership's general partner contributed $2,194 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. All of the net proceeds were used to reduce outstanding indebtedness of the Partnership.
On January 25, 2012, the Partnership completed a public offering of 2,645,000 common units at a price of $36.15 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 2,645,000 common units, net of underwriters’ discounts, commissions and offering expenses were $91,361. The Partnership’s general partner contributed $1,951 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. All of the net proceeds were used to reduce outstanding indebtedness of the Partnership.
On February 9, 2011, the Partnership completed a public offering of 1,874,500 common units at a price of $39.35 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 1,874,500 common units, net of underwriters’ discounts, commissions and offering expenses were $70,330. The Partnership’s general partner contributed $1,505 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. All of the net proceeds were used to reduce outstanding indebtedness of the Partnership.
Incentive Distribution Rights
The Partnership’s general partner, MMGP, holds a 2% general partner interest and certain incentive distribution rights (“IDRs”) in the Partnership. IDRs are a separate class of non-voting limited partner interest that may be transferred or sold by the general partner under the terms of the Partnership Agreement, and represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution and any cumulative arrearages on common units once certain target
distribution levels have been achieved. The Partnership is required to distribute all of its available cash from operating surplus, as defined in the Partnership Agreement. On October 2, 2012, the Partnership Agreement was amended to provide that the general partner shall forego the next $18,000 in incentive distributions that it would otherwise be entitled to receive. No incentive distributions were allocated to the general partner from July 1, 2012 (which would have been payable to the general partner on November 14, 2012 for the third quarter of 2012 distribution) through December 31, 2013. As of December 31, 2013, the amount of incentive distributions the general partner has foregone is $9,647, resulting in an amount remaining of $8,353.
The target distribution levels entitle the general partner to receive 2% of quarterly cash distributions up to $0.55 per unit, 15% of quarterly cash distributions in excess of $0.55 per unit until all unitholders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit and 50% of quarterly cash distributions in excess of $0.75 per unit.
For the years ended December 31, 2013, 2012 and 2011, the general partner received $0, $2,857, and $4,901 in incentive distributions.
Distributions of Available Cash
The Partnership distributes all of its available cash (as defined in the Partnership Agreement) within 45 days after the end of each quarter to unitholders of record and to the general partner. Available cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less the amount of cash reserves its general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters, plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.
Net Income per Unit
The Partnership follows the provisions of the FASB ASC 260-10 related to earnings per share, which addresses the application of the two-class method in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions accounted for as equity distributions. Undistributed earnings are allocated to the general partner and limited partners utilizing the contractual terms of the Partnership Agreement. Distributions to the general partner pursuant to the IDRs are limited to available cash that will be distributed as defined in the Partnership Agreement. Accordingly, the Partnership does not allocate undistributed earnings to the general partner for the IDRs because the general partner's share of available cash is the maximum amount that the general partner would be contractually entitled to receive if all earnings for the period were distributed. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement. Additionally, as required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations.
For purposes of computing diluted net income per unit, the Partnership uses the more dilutive of the two-class and if-converted methods. Under the if-converted method, the weighted-average number of subordinated units outstanding for the period is added to the weighted-average number of common units outstanding for purposes of computing basic net income per unit and the resulting amount is compared to the diluted net income per unit computed using the two-class method. The following is a reconciliation of net income from continuing operations and net income from discontinued operations allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:
The Partnership allocates the general partner's share of earnings between continuing and discontinued operations as a proportion of net income from continuing and discontinued operations to total net income.
The weighted average units outstanding for basic net income per unit were 26,557,829, 23,361,551 and 19,545,427 for the years ended December 31, 2013, 2012 and 2011, respectively. All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented. All common unit equivalents were antidilutive for the year ended December 31, 2013 because the limited partners were allocated a net loss in this period. For diluted net income per unit, the weighted average units outstanding were increased by 3,018 and 1,278 for the years ended December 31, 2012 and 2011, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.
(17) Unit Based Awards
The Partnership recognizes compensation cost related to stock-based awards to employees in its consolidated financial statements in accordance with certain provisions of ASC 718. The Partnership recognizes compensation costs related to stock-based awards to directors under certain provisions of ASC 505-50-55 related to equity-based payments to non-employees. Amounts recognized in selling, general, and administrative expense in the consolidated financial statements with respect to these plans are as follows:
Long-Term Incentive Plans
The Partnership's general partner has a long term incentive plan for employees and directors of the general partner and its affiliates who perform services for the Partnership.
The plan consists of two components, restricted units and unit options. The plan currently permits the grant of awards covering an aggregate of 725,000 common units, 241,667 of which may be awarded in the form of restricted units and 483,333 of which may be awarded in the form of unit options. The plan is administered by the compensation committee of the general partner’s board of directors (“Compensation Committee”).
Restricted Units. A restricted unit is a unit that is granted to grantees with certain vesting restrictions. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. In addition, the restricted units will vest upon a change of control of the Partnership, the general partner or Martin Resource Management or if the general partner ceases to be an affiliate of Martin Resource Management. The Partnership intends the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and the Partnership will receive no remuneration for the units. The restricted units issued to directors generally vest in equal annual installments over a four-year period. Restricted units issued to employees generally cliff vest after three years of service.
The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the year ended December 31, 2013 is provided below:
A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2013, 2012 and 2011 is provided below:
As of December 31, 2013, there was $1,626 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.1 years.
Unit Options. The plan currently permits the grant of options covering common units. As of March 3, 2014, the Partnership has not granted any common unit options to directors or employees of the Partnership's general partner, or its affiliates. In the future, the Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine. Unit options will have an exercise price that, in the discretion of the Compensation Committee, may not be less than the fair market value of the units on the date of grant. In addition, the unit options will become exercisable upon a change in control of the Partnership's general partner, Martin Resource Management or if the general partner ceases to be an affiliate of Martin Resource Management or upon the achievement of specified financial objectives.
(18) Stanolind Tank Damage
During the third quarter of 2011, a single tank fire occurred at the Partnership’s Stanolind Terminal in Beaumont, Texas. This specific tank stores No. 6 oil for Martin Resource Management under a throughput agreement. The tank contained approximately 3,200 barrels of No. 6 oil at the time the incident occurred, all of which was the property of Martin Resource Management.
Physical damage to the Partnership’s asset caused by the fire as well as the related removal and recovery costs, are fully covered by the Partnership’s non-windstorm insurance policy subject to a deductible of $443, which has been expensed and included in “operating expenses” in the Consolidated Statements of Operations for the year ended December 31, 2011.
Insurance proceeds received as a result of the this claim were used to replace the tank. The proceeds received exceeded the net book value of the tank that was destroyed and the Partnership recognized a gain in the amount of $909 in “other operating income” the Consolidated Statements of Operations for the year ended December 31, 2013.
(19) Income Taxes
The operations of a partnership are generally not subject to income taxes because its income is taxed directly to its partners, except as discussed below.
The activities of the Blending and Packaging Assets prior to the acquisition by the Partnership were subject to federal and state income taxes. Accordingly, income taxes have been included in the Blending and Packaging Assets' operating results from January 1, 2010 through October 2, 2012. Related payables/receivables are included in “Due to affiliates” and “Other current assets”, respectively, in the Consolidated Balance Sheet.
Woodlawn, a subsidiary of the Partnership, was subject to income taxes due to its corporate structure. The assets of Woodlawn were sold July 31, 2012 and the corporation was liquidated December 31, 2012. Income tax expense related to Woodlawn is recorded in discontinued operations. A current federal income tax expense of $0, $8,681 and $11, related to the operation of the subsidiary, was recorded for the years ended December 31, 2013, 2012 and 2011, respectively.
The Partnership established deferred income taxes of $8,964 associated with book and tax basis differences of the acquired Woodlawn assets and liabilities at the date of acquisition. The basis differences related primarily to property, plant and equipment. A deferred tax benefit of $0, $7,657 and $139 related to the Woodlawn basis differences was recorded for the years ended December 31, 2013, 2012 and 2011, respectively. A deferred tax expense of $0, $402, and $622 related to the Cross basis differences was recorded for the years ended December 31, 2013, 2012 and 2011. No deferred tax liability related to these basis differences existed at December 31, 2013 and 2012, respectively. The deferred tax liability related to the Prism Assets was reversed upon the sale of those assets as discussed further in Note 5.
Effective January 1, 2007, the Partnership became subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the Consolidated Statements of Operations. The Texas margin tax restructured the state business tax by replacing the taxable capital and earned surplus components of the existing franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial. State income taxes attributable to the Texas margin tax of $753, $1,575 and $713 were recorded in income tax expense for the years ended December 31, 2013, 2012 and 2011, respectively.
A current income tax liability of $1,204, and $10,239 existed at December 31, 2013 and 2012, respectively.
The components of income tax expense from operations recorded for the years ended December 31, 2013, 2012 and 2011 are as follows:
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Total income tax expense was allocated to continuing and discontinued operations as follows:
Income tax expense from continuing operations:
Income tax expense (benefit) from discontinued operations:
Cash paid for income taxes was $9,789, $1,007, and $827 for the years ended December 31, 2013, 2012, and 2011, respectively.
(20) Business Segments
The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation, and sulfur services. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions.
The accounting policies of the operating segments are the same as those described in Note 2. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.
The Natural Gas Services segment information below excludes the discontinued operations of the Prism Assets for 2012 and 2011. See Note 5.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Revenues from two customers in the Natural Gas Services segment were $284,872, $294,508 and $258,542 for the years ended December 31, 2013, 2012 and 2011, respectively. Revenues from one customer in the Sulfur Services segment were $66,653, $87,820 and $111,172 for the years ended December 31, 2013, 2012 and 2011, respectively.
The Partnership's assets by reportable segment as of December 31, 2013 and 2012, are as follows:
(21) Quarterly Financial Information
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Consolidated Quarterly Income Statement Information
(22) Commitments and Contingencies
From time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership.
(23) Condensed Consolidating Financial Information
Martin Operating Partnership L.P. (the “Operating Partnership”), the Partnership’s wholly-owned subsidiary, has issued in the past, and may issue in the future, unconditional guarantees of senior or subordinated debt securities of the Partnership in the event that the Partnership issues such securities from time to time. The guarantees that have been issued are full, irrevocable and unconditional. In addition, the Operating Partnership may also issue senior or subordinated debt securities which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership.
Since December 31, 2012, the Partnership has added Redbird and MOP Midstream Holdings LLC as subsidiary guarantors to its outstanding senior unsecured notes and has transferred substantially all of Talen's assets to certain of the Partnership's other subsidiary guarantors. Therefore, the Partnership no longer presents condensed consolidating financial information for any non-subsidiary guarantors.
(24) Subsequent Events
Redemption of 2018 Senior Unsecured Notes. On February 28, 2014, the Partnership announced that it will exercise a full redemption of the 2018 senior unsecured notes pursuant to the indenture, on or about April 1, 2014 at an aggregate redemption value of $182,767. The Partnership expects to fund the redemption under borrowings from our revolving credit facility.
Amendment to Revolving Credit Facility. On February 18, 2014, the Partnership increased the maximum amount of borrowings under its revolving credit facility from $600,000 to $637,500 by utilizing the accordion feature of the Partnership's revolving credit facility.
.
Quarterly Distribution. On January 23, 2014, The Partnership declared a quarterly cash distribution of $0.785 per common unit for the fourth quarter of 2013, or $3.14 per common unit on an annualized basis, which was paid on February 14, 2014 to unitholders of record as of February 7, 2014.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.
Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures. In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of our general partner, carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15(d)-15(e) of the Exchange Act) as of December 31, 2013. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner concluded that our disclosure controls and procedures were effective as of December 31, 2013.
(b) Management’s Report on Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control - Integrated Framework (1992), our management concluded that our internal control over financial reporting was effective as of December 31, 2013. The effectiveness of our internal control over financial reporting as of December 31, 2013 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in their report appearing in “Item 8 - Financial Statements and Supplementary Data.”
There were no changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
Item 9B.
Item 9B.
Other Information
None
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance
Management of Martin Midstream Partners L.P.
Martin Midstream GP LLC, as our general partner, manages our operations and activities on our behalf. Our general partner was not elected by our unitholders and will not be subject to re-election in the future. Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. However, whenever possible, our general partner seeks to provide that our indebtedness or other obligations are non-recourse to our general partner.
Three directors of our general partner serve on a conflicts committee of the Partnership's general partner (“Conflicts Committee”) to review specific matters that the directors believe may involve conflicts of interest. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates and must meet the independence standards established by NASDAQ to serve on an audit committee of a board of directors; provided, however that a director with a family member who is a partner with a foreign affiliate in the international cooperative of our registered independent public accounting firm shall be deemed to meet such independence standards if such director meets all other independence standards of NASDAQ and the board of our general partner affirmatively determines that such family relationship will not impair such director's independent judgment as a member of the Conflicts Committee. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. The current members of our Conflicts Committee are outside directors, Joe N. Averett, Jr., C. Scott Massey and Charles H. Still, all of whom meet the independence standards established by NASDAQ, except as referenced above.
The Audit Committee reviews our external financial reporting, recommends engagement of our independent auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls. The current members of our Audit Committee are outside directors, C. Scott Massey, Byron R. Kelley and Charles H. Still, all of whom meet the independence standards established by NASDAQ.
The Compensation Committee oversees compensation decisions for the officers of our general partner as well as the compensation plans described below. The current members of our Compensation Committee are our outside directors, Joe N. Averett, Jr., C. Scott Massey, Byron R. Kelley and Charles H. Still.
The current members of our Nominating Committee are outside directors, Joe N. Averett, Jr, Byron R. Kelley and Charles H. Still.
We are managed and operated by the directors and officers of our general partner. All of our operational personnel are employees of Martin Resource Management. All of the officers of our general partner will spend a substantial amount of time managing the business and affairs of Martin Resource Management and its other affiliates. These officers may face a conflict regarding the allocation of their time between our business and the other business interests of Martin Resource Management. Our general partner intends to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.
Directors and Executive Officers of Martin Midstream GP LLC
The following table shows information for the directors and executive officers of our general partner. Directors and executive officers are elected for one-year terms.
Ruben S. Martin serves as President, Chief Executive Officer and a member of the board of directors of our general partner. Mr. Martin has served in such capacities since June 2002. Mr. Martin has served as President of Martin Resource Management since 1981 and has served in various capacities within the company since 1974. Mr. Martin holds a Bachelor of Science degree in industrial management from the University of Arkansas. Mr. Martin was selected to serve as a director on our general partner's board of directors due to his depth of knowledge of the Partnership, including its strategies, its operations, his business judgment and his position within the Partnership.
Robert D. Bondurant serves as Executive Vice President and Chief Financial Officer of our general partner. Mr. Bondurant has served in such capacities since June 2002. Mr. Bondurant joined Martin Resource Management in 1983 as Controller and subsequently was appointed Chief Financial Officer and a member of its board of directors in 1990. Mr. Bondurant served in the audit department at Peat Marwick, Mitchell and Co from 1980 to 1983. Mr. Bondurant holds a Bachelor of Business Administration degree in accounting from Texas A&M University and is a Certified Public Accountant, licensed in the State of Texas.
Randall L. Tauscher serves as Executive Vice President and Chief Operating Officer of our general partner. Mr. Tauscher has served in this capacity since August 2011. From November 2007 through July 2011, Mr. Tauscher served as Executive Vice President. Prior to joining Martin, Mr. Tauscher was employed by Koch Industries for over 18 years, most recently as Senior Vice President of the Koch Carbon Division. Mr. Tauscher earned a Bachelor of Business Administration degree from Kansas State University.
Wesley M. Skelton serves as Executive Vice President, Controller and Chief Administrative Officer of our general partner. Mr. Skelton has served in such capacities since June 2002. Mr. Skelton joined Martin Resource Management in 1981 and has served as Chief Administrative Officer since 1981 and a Director since 1990. Prior to joining Martin Resource Management, Mr. Skelton served as Treasurer of First Federal Savings & Loan, Marshall, Texas from January 1977 through January 1981 and was employed by Peat Marwick, Mitchell & Co. from August 1973 through January 1977. Mr. Skelton holds a Bachelor of Business Administration degree from the University of Texas and is a Certified Public Accountant licensed in the State of Texas.
Chris Booth serves as Executive Vice President, General Counsel and Secretary of our general partner. Mr. Booth has served as an officer of our general partner since February 2006. Mr. Booth joined Martin Resource Management in October 2005. Prior to joining Martin Resource Management, Mr. Booth was an attorney with the law firm of Mehaffy Weber located in Beaumont, Texas. Mr. Booth holds a Doctor of Jurisprudence degree and a Masters of Business Administration degree with a concentration in finance from the University of Houston. Additionally, Mr. Booth holds a Bachelor of Science degree in business management from LeTourneau University. Mr. Booth is an attorney licensed to practice in the State of Texas.
C. Scott Massey serves as a member of the board of directors of our general partner. Mr. Massey has served as a Director since June 2002. Mr. Massey has been self employed as a Certified Public Accountant since 1998. From 1977 to 1998, Mr. Massey worked for KPMG Peat Marwick, LLP in various positions, including, most recently, as a Partner in the firm's Tax Practice - Energy, Real Estate, Timber from 1986 to 1998. Mr. Massey received a Bachelor of Business Administration degree from the University of Texas at Austin and a Doctor of Jurisprudence degree from the University of Houston. Mr. Massey is a Certified Public Accountant, licensed in the states of Louisiana and Texas. Mr. Massey was selected
to serve as a director on our general partner's board of directors due to his extensive background in public accounting and taxation. Mr. Massey qualifies as an “audit committee financial expert” under the SEC guidelines.
Joe N. Averett, Jr. serves as a member of the board of directors of our general partner. Mr. Averett has served as a Director since June 2010. Mr. Averett has served on the board of directors of Penn Virginia Corporation and Capital One Mutual Funds. He was the President and Chief Executive Officer of Crystal Gas Storage, Inc., a provider of natural gas storage, from 1985 to 2003. Prior to joining Crystal Gas Storage, Inc., Mr. Averett was the Chief Financial Officer of P&O Falco, Inc. and Langham Petroleum. Mr. Averett was also the Treasurer and Chief Financing Officer for the Pennzoil Company. Mr. Averett has also served in Washington, D.C., as the United States Presidential Executive in the Treasury Department, Office of the Secretary, tasked with economic policy. Mr. Averett holds a Bachelor of Business Administration degree in finance from Texas A&M University. Mr. Averett was selected to serve as a director on our general partner's board of directors due to his extensive business experience.
Charles H. Still serves as a member of the Board of Directors of our general partner. Mr. Still has served as a Director since July 2011. Mr. Still was a partner in the law firm Kelly Hart & Hallman LLP from June 2008 until his retirement in December 2010. Prior to joining Kelly Hart & Hallman LLP in 2008, Mr. Still was an associate and partner in the law firm Fulbright & Jaworski L.L.P. from 1968 until his retirement in 2007. He was of counsel to Fulbright & Jaworski from January 1, 2009 to June 20, 2009 and again became of counsel to Fulbright & Jaworski on February 28, 2012, but that relationship ended December 31, 2013. Mr. Still is currently on the board of directors of Geospace Technologies Inc. Mr. Still holds a J.D. from the University of Texas School of Law and a B.B.A. in accounting from Texas Tech University. He served as an Adjunct Professor of Law at the University of Texas School of Law from 2007 through 2010.
Byron R. Kelley serves as a member of the board of directors of our general partner and also served as an Advisory Director from April 2011 to August 2012. On December 31, 2013, Mr. Kelley retired as CEO, President and a member of the board of directors of CVR Partners, LP, a chemical company engaged in the production of nitrogen based fertilizers and served in this position from June 2011 through December 2013. Prior to joining CVR Partners in June of 2011 he served as President, Chief Executive Officer and a member of the board of directors of Regency GP, LLC from April 2008 to November 2010. From 2004 through March of 2008, Mr. Kelley served as Senior Vice President and Group President of Pipeline and Field Services at CenterPoint Energy. Preceding his work at CenterPoint, Mr. Kelley served as Executive Vice President of Development, Operations and Engineering, and as President of El Paso Energy International. Mr. Kelley is a past member and Chairman of the board of directors of the Interstate National Gas Association and previously served as one of the association's representatives on the United States Natural Gas Council of America. Mr. Kelley received a Bachelor of Science degree in civil engineering from Auburn University. Mr. Kelley was selected to serve as a director on our general partner's board of directors due to his extensive corporate business experience.
Alexander W.F. Black serves as a member of the board of directors of our general partner. Mr. Black has served as a Director since September 2013. Mr. Black is a partner at Alinda Capital Partners, which he joined in 2008. Prior to joining Alinda, he was a senior director of Kroll Zolfo Cooper, LLC, a consulting firm based in New York. Mr. Black has been CEO, CFO or head of operations at several businesses in the United States and United Kingdom. Prior to that, he was an audit supervisor at Touche Ross & Co. He is a Chartered Engineer, Chartered Insolvency and Restructuring Advisor, and a Chartered Accountant. He has a BSc (Hons) degree from Exeter University, United Kingdom. Mr. Black was selected to serve as a director on our general partner's board of directors due to his affiliation with Alinda, his knowledge of the energy industry and his financial, business and operational experience.
Sean P. Dolan serves as a member of the board of directors of our general partner. Mr. Dolan has served as a Director since September 2013. Mr. Dolan is a Managing Director of Alinda Capital Partners, which he joined in 2009. Prior to joining Alinda, Mr. Dolan spent over 12 years with Citigroup Global Markets in investment banking primarily focused in the energy sector. Mr. Dolan received a bachelor's degree from Georgetown University. Mr. Dolan was selected to serve as a director on our general partner's board of directors due to his affiliation with Alinda, his knowledge of the energy industry and his financial and business expertise.
Independence of Directors
Messrs. Massey, Still, Averett, and Kelley qualify as “independent” in accordance with the published listing requirements of NASDAQ and applicable securities laws. The NASDAQ independence definition includes a series of objective tests, such as that the director is not an employee of us and has not engaged in various types of business dealings with us. In addition, as further required by the NASDAQ rules, the board of directors has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. In making these determinations, the directors reviewed
and discussed information provided by the directors and us with regard to each director's business and personal activities as they may relate to us and our management.
Board Meetings and Committees
From January 1, 2013 to December 31, 2013, the board of directors of our general partner held 14 meetings. All directors then in office attended each of these meetings, either in person, by teleconference or by videoconference with the exception of Byron R. Kelley, who was not in attendance at the meeting of the board of directors on the date of March 26, 2013, Joe N. Averett, Jr., who was not in attendance at the meeting of the board of directors on the date of August 18, 2013, and Sean Dolan, who was not in attendance at the meeting of the board of directors on the date of December 19, 2013. Additionally, the board of directors undertook action one time during 2013 without a meeting by acting through written unanimous consent. We have standing conflicts, audit, compensation and nominating committees of the board of directors of our general partner. The board of directors of our general partner appoints the members of the Audit, Compensation, Nominating and Conflicts Committees. Each member of the Audit Committee is an independent director in accordance with NASDAQ and applicable securities laws. Each of the board committees has a written charter approved by the board. Copies of each charter are posted on our website at www.martinmidstream.com under the “Corporate Governance” section. The current members of the committees, the number of meetings held by each committee from January 1, 2013 to December 31, 2013, and a brief description of the functions performed by each committee are set forth below:
Conflicts Committee (6 meetings). The members of the Conflicts Committee are Messrs. Averett (chairman), Massey and Still. All of the members of the Conflicts Committee attended all meetings of the committee for the period noted above. The primary responsibility of the Conflicts Committee is to review matters that the directors believe may involve conflicts of interest. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by NASDAQ; provided, however that a director with a family member who is a partner with a foreign affiliate in the international cooperative of our registered independent public accounting firm shall be deemed to meet such independence standards if such director meets all other independence standards of NASDAQ and the board of our general partner affirmatively determines that such family relationship will not impair such director's independent judgment as a member of the Conflicts Committee. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.
Audit Committee (4 meetings). Additionally, the Audit Committee undertook action one time during 2013 without a meeting by acting through written unanimous consent. The members of the Audit Committee are Messrs. Massey (chairman), Still and Kelley. All of the members attended all meetings of the Audit Committee for the period noted above. The primary responsibilities of the Audit Committee are to assist the board of directors in its general oversight of our financial reporting, internal controls and audit functions, and it is directly responsible for the appointment, retention, compensation and oversight of the work of our independent auditors. The members of the Audit Committee of the board of directors of our general partner each qualify as “independent” under standards established by the SEC for members of Audit Committees, and the Audit Committee includes at least one member who is determined by the board of directors to meet the qualifications of an “audit committee financial expert” in accordance with SEC rules, including that the person meets the relevant definition of an “independent” director. C. Scott Massey is the independent director who has been determined to be an audit committee financial expert. Unitholders should understand that this designation is a disclosure requirement of the SEC related to Mr. Massey's experience and understanding with respect to certain accounting and auditing matters. The designation does not impose on Mr. Massey any duties, obligations or liability that are greater than are generally imposed on him as a member of the Audit Committee and board of directors, and his designation as an audit committee financial expert pursuant to this SEC requirement does not affect the duties, obligations or liability of any other member of the Audit Committee or board of directors.
Compensation Committee (3 meetings). The members of the Compensation Committee are Messrs. Kelley (chairman), Massey, Still and Averett. All of the members attended all meetings of the Compensation Committee for the period noted above. The primary responsibility of the Compensation Committee is to oversee compensation decisions for the outside directors of our general partner and executive officers of our general partner (in the event they are to be paid by our general partner) as well as our long-term incentive plan.
Nominating Committee (1 meeting). The members of the nominating committee are Messrs. Still (chairman), Averett and Kelley. All of the members attended all meetings of the Compensation Committee for the period noted above. The primary responsibility of the nominating committee is to select and recommend nominees for election to the board of directors of our general partner.
Code of Ethics and Business Conduct
Our general partner has adopted a Code of Ethics and Business Conduct applicable to all of our general partner's employees (including any employees of Martin Resource Management who undertake actions with respect to us or on our behalf), including all officers, and including our general partner's independent directors, who are not employees of our general partner, with regard to their activities relating to us. The Code of Ethics and Business Conduct incorporate guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations. They also incorporate our expectations of our general partner's employees (including any employees of Martin Resource Management who undertake actions with respect to us or on our behalf) that enable us to provide accurate and timely disclosure in our filings with the Securities and Exchange Commission and other public communications. The Code of Ethics and Business Conduct is publicly available on our website under the “Corporate Governance” section (at www.martinmidstream.com). This website address is intended to be an inactive, textual reference only, and none of the material on this website is part of this report. If any substantive amendments are made to the Code of Ethics and Business Conduct or if we or our general partner grant any waiver, including any implicit waiver, from a provision of the code to any of our general partner's executive officers and directors, we will disclose the nature of such amendment or waiver on that website or in a report on Form 8-K.
Section 16(a) Beneficial Ownership Reporting Compliance
Our general partner's directors and officers and beneficial owners of more than 10% of a registered class of our equity securities are required to file reports of ownership and reports of changes in ownership with the SEC and NASDAQ. Directors, officers and beneficial owners of more than 10% of our equity securities are also required to furnish us with copies of all such reports that are filed. Based solely on our review of copies of such forms and amendments, we believe directors, officers and greater than 10% beneficial owners complied with all filing requirements during the year ended December 31, 2013, with the exception of the initial Form 3 for Sean P. Dolan and Alexander W.F. Black which were filed late.
Reimbursement of Expenses of our General Partner
Our general partner does not receive a management fee or other compensation for its management of our partnership. However, our general partner and its affiliates are reimbursed for expenses incurred on our behalf. All direct general and administrative expenses are charged to us as incurred. For the years ended December 31, 2013, 2012 and 2011, we reimbursed Martin Resource Management $177.1 million, $157.8 million and $142.0 million, respectively, for direct costs and expenses. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses.
Indirect general and administrative and corporate overhead costs relate to centralized corporate functions that we share with Martin Resource Management, including certain accounting, treasury, engineering, information technology, insurance, administration of employee benefit plans and other corporate services. In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2013, 2012 and 2011, the Conflicts Committee approved reimbursement amounts of $10.6 million, $7.6 million and $4.8 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.
Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Please read “Item 13. Certain Relationships and Related Transactions, and Director Independence - Agreements - Omnibus Agreement.”
Compensation Discussion and Analysis
Background
We are required to provide information regarding the compensation program in place as of December 31, 2013, for the CEO, CFO and the three other most highly-compensated executive officers of our general partner as reflected in the summary compensation table set forth below (the “Named Executive Officers”). This section should be read in conjunction with the detailed tables and narrative descriptions regarding compensation below.
We are a master limited partnership and have no employees. We are managed by the executive officers of our general partner. These executive officers are employed by Martin Resource Management, a private corporation that has significant operations that are separate from ours. The executive officers of our general partner are also the executive officers of Martin Resource Management and devote significant time to the management of Martin Resource Management’s operations. We reimburse Martin Resource Management for a portion of the indirect general and administrative expenses, including compensation expense relating to the service of these individuals that are allocated to us pursuant to the omnibus agreement between us and our general partner, as amended on October 1, 2012 (“Omnibus Agreement”). 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, 2013, 2012 and 2011, the conflicts committee of our general partner (“Conflicts Committee”) approved reimbursement amounts of $10.6 million, $7.6 million and $4.8 million, respectively, reflecting our allocable share of such expenses. Please see “Item 13. Certain Relationships and Related Transactions, and Director Independence - Agreements - Omnibus Agreement” for a discussion of the Omnibus Agreement.
Compensation Objectives
As we do not directly compensate the executive officers of our general partner, we do not have any set compensation programs. The elements of Martin Resource Management’s compensation program discussed below, along with Martin Resource Management’s other rewards, are intended to provide a total rewards package designed to yield competitive total cash compensation, drive performance and reward contributions in support of the businesses of Martin Resource Management and other Martin Resource Management affiliates, including us, for which the Named Executive Officers perform services. Although we bear an allocated portion of Martin Resource Management’s costs of providing compensation and benefits to the Named Executive Officers, we do not have control over such costs and do not establish or direct the compensation policies or practices of Martin Resource Management. During 2013, Martin Resource Management paid compensation based on the performance of Martin Resource Management but did not set any specific performance-based criteria and did not have any other specific performance-based objectives.
Elements of Compensation
Martin Resource Management’s executive officer compensation package includes a combination of annual cash, long-term incentive compensation and other compensation. Elements of compensation which the Named Executive Officers may be eligible to receive from Martin Resource Management consist of the following: (1) annual base salary; (2) discretionary annual cash awards; (3) awards pursuant to Martin Resource Management employee benefit plans and (4) where appropriate, other compensation, including limited perquisites.
Annual Base Salary. Base salary is intended to provide fixed compensation to the Named Executive Officers for their performance of core duties with respect to Martin Resource Management and its affiliates, including us, and to compensate for experience levels, scope of responsibility and future potential. Base salaries are not intended to compensate individuals for extraordinary performance or for above average company performance. The base salaries of the Named Executive Officers are reviewed on an annual basis, as well as at the time of promotion and other changes in responsibilities or market conditions.
Discretionary Annual Cash Awards. In addition to the annual base salary, the Named Executive Officers may be eligible to receive discretionary annual cash awards that, if awarded, are paid in a lump sum in the quarter following the end of the fiscal year. These cash awards are designed to provide the Named Executive Officers with competitive incentives to help drive performance and promote achievement of Martin Resource Management’s business objectives. Named Executive Officers may also be eligible to receive a cash award based upon their services provided to us in the event that any such Named Executive Officer has devoted a significant amount of their time to working for us. Any such award is determined in
accordance with the same methodologies as the discretionary annual cash awards for Martin Resource Management, as described below.
Employee Benefit Plan Awards. The Named Executive Officers may be eligible to receive awards pursuant to the Martin Midstream Partners L.P. Long-Term Incentive Plan and Martin Resource Management employee benefit plans. These employee benefit plan awards are designed to reward the performance of the Named Executive Officers by providing annual incentive opportunities tied to the annual performance of Martin Resource Management. In particular, these awards are provided to the Named Executive Officers in order to provide competitive incentives to these executives who can significantly impact performance and promote achievement of the business objectives of Martin Resource Management.
Other Compensation. Martin Resource Management generally does not pay for perquisites for any of the Named Executive Officers, other than general recreational activities at certain Martin Resource Management’s properties located in Texas, including aircraft. No perquisites are paid for services rendered to us. Martin Resource Management provides an executive life insurance policy and long term disability policy for the Named Executive Officers with the annual premiums being paid by Martin Resource Management. Martin Resource Management does not provide any greater allocation toward employee health insurance premiums than is provided for all other employees covered on the health benefits plan.
Compensation Methodology
The compensation policies and philosophy of Martin Resource Management govern the types and amount of compensation granted to each of the Named Executive Officers. The board of directors and Conflicts Committee do have responsibility for evaluating and determining the reasonableness of the total amount we are charged under the Omnibus Agreement for managerial, administrative and operational support, including compensation of the Named Executive Officers, provided by Martin Resource Management.
Our allocation for the costs incurred by Martin Resource Management in providing compensation and benefits to its employees who serve as the Named Executive Officers is governed by the Omnibus Agreement. In general, this allocation is based upon estimates of the relative amounts of time that these employees devote to the business and affairs of our general partner and to the business and affairs of Martin Resource Management. We bear substantially less than a majority of Martin Resource Management’s costs of providing compensation and benefits to the Named Executive Officers.
When setting compensation for the Named Executive Officers, the elements of compensation above are considered holistically to provide an appropriate combination of compensation. Annual base salaries are determined by the Compensation Committee of Martin Resource Management following an individual performance review of each Named Executive Officer. Further, Martin Resource Management, with the approval of Mr. Ruben Martin, the Chief Executive Officer of Martin Resource Management, normally reviews market data and relevant compensation surveys when setting base compensation and, when appropriate, engages compensation consultants. Except in the case of an exceptional amount of time devoted to us, discretionary annual cash awards are based on the performance of Martin Resource Management. Annual discretionary cash awards, if any, are calculated first by allocating a portion of Martin Resource Management’s earnings as determined by Martin Resource Management’s Compensation Committee for distribution to key employees of Martin Resource Management. Upon such allocation, Mr. Martin with input from appropriate business leaders determines the allocation and distribution of the bonus pool among such employees, including the Named Executive Officers. With respect to employee benefit plan awards, Mr. Martin makes a recommendation to the Compensation Committee of Martin Resource Management as to whether such awards should be awarded to any employees. Any such employee plan awards are then approved by the Compensation Committee and distributed to the employees, including Named Executive Officers, accordingly.
Any awards granted under our long-term incentive plan, which to date have consisted of the grant of restricted common units to the independent directors and employees of our general partner, are approved by the Compensation Committee.
The Named Executive Officers who serve on the compensation committee of Martin Resource Management play a role in setting the compensation as base salaries, discretionary annual cash awards and employee benefit awards are set by that committee. Current members of the Martin Resource Management compensation committee are Mr. Ruben Martin, Chief Executive Officer, Mr. Robert Bondurant, Chief Financial Officer, Mr. Randall Tauscher, Chief Operating Officer, Mr. Wesley Skelton, Chief Administrative Officer and Controller and Mrs. Melanie Mathews, Vice President-Human Resources. Further, as is explained above, Mr. Martin, as Chief Executive Officer, also has significant authority in setting base salaries, discretionary annual cash award allocations and amounts and employee benefit award distributions.
Determination of 2013 Compensation Amounts
During 2013, elements of all compensation paid to the Named Executive Officers by Martin Resource Management consisted of the following: (1) annual base salary; (2) discretionary annual cash awards; (3) awards pursuant to Martin Resource Management employee benefit plans; and (4) other compensation, including limited perquisites. With respect to the Named Executive Officers, they were paid an allocated portion of their base salaries.
Annual Base Salary. The portions of the annual base salaries paid by Martin Resource Management to the Named Executive Officers, which are allocable to us under our Omnibus Agreement with Martin Resource Management, are reflected in the summary compensation table below. Based upon the agreement of our general partner with Martin Resource Management, we have reimbursed Martin Resource Management for approximately 51.1% of the aggregate annual base salaries paid to the Named Executive Officers by Martin Resource Management during 2013. The foregoing agreement has been developed based on an assessment of the estimated percentage of the time spent by the Named Executive Officers managing our affairs, relative to the affairs of Martin Resource Management ranging from approximately 30% to 67%. Our Named Executive Officers are Mr. Ruben Martin, the President and Chief Executive Officer of our general partner, Mr. Robert Bondurant, an Executive Vice President and Chief Financial Officer of our general partner, Mr. Wesley Skelton, an Executive Vice President, Controller and Chief Administrative Officer of our general partner, Mr. Randall Tauscher, an Executive Vice President and Chief Operating Officer of our general partner and Mr. Chris Booth, the Executive Vice President, General Counsel and Secretary of our general partner. Annual base salaries of the Named Executive Officers were not increased during 2013 by Martin Resource Management.
Discretionary Annual Cash Awards. Discretionary annual cash awards paid to the Named Executive Officers which are allocable to us are reflected in the summary compensation table below.
Martin Midstream Partners L.P. Long-Term Incentive Plan
Our general partner has adopted the Martin Midstream Partners L.P. Long-Term Incentive Plan (“LTIP”) for employees and directors of our general partner and its affiliates who perform services for us. The LTIP was amended in January 2006 to clarify the Partnership’s ability to grant restricted common units under the LTIP and to remove provisions relating to grants of distribution equivalent rights and phantom units.
The LTIP consists of two components, restricted units and unit options. The LTIP currently permits the grant of awards covering an aggregate of 725,000 common units, 241,667 of which may be awarded in the form of restricted units and 483,333 of which may be awarded in the form of unit options. The plan is administered by the Compensation Committee of our general partner’s board of directors.
Our general partner’s board of directors or the Compensation Committee, in their discretion, may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made. Our general partner’s board of directors or the Compensation Committee also have the right to alter or amend the LTIP or any part of the plan from time to time, including increasing the number of units that may be reserved for issuance under the plan subject to any applicable unitholder approval. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.
Restricted Units. A restricted unit is a unit that is granted to grantees with certain vesting restrictions. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. A phantom unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine under the plan. The Compensation Committee will determine the period over which restricted units or phantom units granted to employees and directors will vest. The committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units or phantom units will vest upon a change of control of us, our general partner or Martin Resource Management or if our general partner ceases to be an affiliate of Martin Resource Management.
If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s restricted units or phantom units will be automatically forfeited unless, and to the extent, the Compensation Committee provides otherwise. Common units to be delivered upon the vesting of restricted units or phantom units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any affiliate of our general partner or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units or phantom units, the total number of common units outstanding will increase.
We intend the issuance of the common units upon vesting of the restricted units or phantom units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.
On April 29, 2013, we issued 1,500 restricted common units to each of our four independent directors under our LTIP. These restricted common units vest in equal installments of 375 units on January 24, 2014, 2015, 2016, and 2017.
On January 1, 2013, we issued 16,250 restricted common units to our Named Executive Officers which vest on January 1, 2016. The grant date fair value of these restricted units is reflected in the summary compensation table below.
On April 30, 2012, we issued 1,250 restricted common units to each of our four independent directors under our LTIP. These restricted common units vest in equal installments of 312.5 units on January 24, 2013, 2014, 2015, and 2016.
On May 2, 2011, we issued 1,250 restricted common units to a independent advisory director under our LTIP. These restricted common units vest in equal installments of 312.5 units on January 24, 2012, 2013, 2014 and 2015.
On February 28, 2011, we issued 1,250 restricted common units to each of four independent directors under our LTIP. These restricted common units vest in equal installments of 312.5 units on January 24, 2012, 2013, 2014 and 2015.
On August 2, 2010, we issued 1,500 restricted common units to each of two new independent, independent directors under our LTIP. These restricted common units vest in equal installments of 375 units and were fully vested on January 24, 2011, 2012, 2013 and 2014.
On May 3, 2010, we issued 1,000 restricted common units to each of our three independent, independent directors under our LTIP. These restricted common units vest in equal installments of 250 units and were fully vested on January 24, 2011, 2012, 2013 and 2014.
On August 3, 2009, we issued 1,000 restricted common units to each of its three independent, independent directors under its long-term incentive plan from treasury shares purchased by us in the open market for $78. These units vest in 25% increments beginning in January 2010 and were fully vested in January 2013.
On May 5, 2008, we issued 1,000 restricted common units to each of its three independent, independent directors under its long-term incentive plan from treasury shares purchased by us in the open market for $93. These units vest in 25% increments beginning in January 2009 and were fully vested in January 2012.
Unit Options. The LTIP currently permits the grant of options covering common units. As of March 3, 2014, we have not granted any common unit options to directors or employees of our general partner, or its affiliates. In the future, the Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the committee shall determine. Unit options will have an exercise price that, in the discretion of the committee, may not be less than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the Compensation Committee. In addition, the unit options will become exercisable upon a change in control of us, our general partner, Martin Resource Management or if our general partner ceases to be an affiliate of Martin Resource Management or upon the achievement of specified financial objectives.
Upon exercise of a unit option, our general partner will acquire common units in the open market or directly from us or any affiliate of our general partner or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will pay us the proceeds it received from the optionee.
Martin Resource Management Employee Benefit Plans
Martin Resource Management has employee benefit plans for its employees who perform services for us. The following summary of these plans is not complete but outlines the material provisions of these plans.
Martin Resource Management Purchase Plan for Units of Martin Midstream Partners L.P. Martin Resource Management maintains a purchase plan for our units to provide employees of Martin Resource Management and its affiliates who perform services for us the opportunity to acquire an equity interest in us through the purchase of our common units. Each individual employed by Martin Resource Management or an affiliate of Martin Resource Management that provides services to us is eligible to participate in the purchase plan. Enrollment in the purchase plan by an eligible employee will constitute a grant by Martin Resource Management to the employee of the right to purchase common units under the purchase plan. The right to purchase common units granted by the Company under the purchase plan is for the term of a purchase period.
During each purchase period, each participating employee may elect to make contributions to his bookkeeping account each pay period in an amount not less than one percent of his compensation and not more than fifteen percent of his compensation. The rate of contribution shall be designated by the employee at the time of enrollment. On each purchase date (the last day of such purchase period), units will be purchased for each participating employee at the fair market value of such units. The fair market value of the Units to be purchased during such purchase period shall mean the closing sales price of a unit on the purchase date.
Martin Resource Management Employee Stock Ownership Plans.
MRMC Employee Stock Ownership Plan. Martin Resource Management maintains an employee stock profit sharing plan that covers employees who satisfy certain minimum age and service requirements (“ESOP”). Under the terms of the ESOP, Martin Resource Management has the discretion to make contributions in an amount determined by its board of directors. Those contributions are allocated under the terms of the ESOP and invested primarily in the common stock of Martin Resource Management. Participants in the Martin ESOP become 100% vested upon completing six years of vesting service or upon their attainment of normal retirement age, permanent disability or death during employment. Any forfeitures of non-vested accounts may be used to pay administrative expenses and restore previous forfeitures of employees rehired before incurring five consecutive breaks-in-service. Any remaining forfeitures will be allocated to the accounts of employed participants. Participants are not permitted to make contributions including rollover contributions to the ESOP.
Martin Employees' Stock Profit Sharing Plan. Martin Resource Management maintains an employee profit sharing plan that covers employees who satisfied certain minimum age and service requirements but no Employee shall become eligible to participate in the Plan on or after January 1, 2013. This plan is referred to as the “Martin Employees' Stock Profit Sharing Plan". Under the terms of the plan, Martin Resource Management has the discretion to make contributions in an amount determined by its board of directors. Those contributions are allocated under the terms of the Martin Employees’ Stock Profit Sharing Plan and invested primarily in the common stock of Martin Resource Management. No contributions will be made to the Plan for any Plan Year commencing on or after January 1, 2013. The account balances of any participant who was employed by Martin Resource Management on December 31, 2012 shall be fully vested and non-forfeitable. This plan converted to an employee stock ownership plan on January 1, 2014.
Martin Resource Management 401(k) Profit Sharing Plan. Martin Resource Management maintains a profit sharing plan that covers employees who satisfy certain minimum age and service requirements. This profit sharing plan is referred to as the “401(k) Plan.” Eligible employees may elect to participate in the 401(k) Plan by electing pre-tax contributions up to 30% of their regular compensation and/or a portion of their discretionary bonuses. Matching contributions are made to the 401(k) Plan equal to 100% of the first 3% of eligible compensation, and 50% of the next 2% of eligible compensation. Martin Resource Management may make annual discretionary profit sharing contributions in an amount at the plan year end as determined by the board of directors of Martin Resource Management. Participants in the 401(k) Plan become 100% vested in matching contributions immediately and become vested in the discretionary contributions made for them upon completing five years of vesting service or upon their attainment of age 65, permanent disability or death during employment.
Martin Resource Management Non-Qualified Option Plan. In September 1999, Martin Resource Management adopted a stock option plan designed to retain and attract qualified management personnel, directors and consultants. Under the plan, Martin Resource Management is authorized to issue to qualifying parties from time to time options to purchase up to 2,000 shares of its common stock with terms not to exceed ten years from the date of grant and at exercise prices generally not less than fair market value on the date of grant. In November 2007, Martin Resource Management adopted an additional stock option plan designed to retain and attract qualified management personnel, directors and consultants. In December 2013, all outstanding options were exercised or redeemed in lieu of redemption. There are no outstanding options under this plan as of December 31, 2013.
Other Compensation
Martin Resource Management generally does not pay for perquisites for any of our named executive officers other than general recreational activities at certain Martin Resource Management’s properties located in Texas and use of Martin Resource Management vehicles, including aircraft.
SUMMARY COMPENSATION TABLE
The following table sets forth the compensation expense that was allocated to us for the services of the named executive officers for the years ended December 31, 2013, 2012 and 2011.
(1) Represents salary earned through date of resignation on October 31, 2012.
(2) The amounts shown represent the grant date fair value of awards computed in accordance with FASB ASC 718. See Note 17 included in Item 8 herein for the assumptions made in our valuation of such awards.
(3) Annual base salaries of the Named Executive Officers were not increased during 2013 by Martin Resource Management, although the allocated percentage of the Named Executive Officers annual base salaries increased.
Director Compensation
As a partnership, we are managed by our general partner. The board of directors of our general partner performs for us the functions of a board of directors of a business corporation. Directors of our general partner are entitled to receive total quarterly retainer fees of $16,250 each which are paid by the general partner. Martin Resource Management employees who are a member of the board of directors of our general partner do not receive any additional compensation for serving in such capacity. Officers of our general partner who also serve as directors will not receive additional compensation. All directors of our general partner are entitled to reimbursement for their reasonable out-of-pocket expenses in connection with their travel to and from, and attendance at, meetings of the board of directors or committees thereof. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.
The following table sets forth the compensation of our board members for the period from January 1, 2013 through December 31, 2013.
(1) On January 1, 2013, the Partnership issued 10,000 restricted common units to Ruben S. Martin, under our LTIP. These restricted common units vest in January 1, 2016. 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, January 1, 2013, by the number of restricted common units granted to this director.
(2) On April 29, 2013, the Partnership issued 1,500 restricted common units to each of four independent directors, C. Scott Massey, Joe N. Averett, Jr., Byron R. Kelley, and Charles H. “Hank” Still, under our LTIP. These restricted common units vest in equal installments of 375 units on January 24, 2014, 2015, 2016 and 2017, 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, April 29, 2013, by the number of restricted common units granted to each director.
COMPENSATION REPORT OF THE COMPENSATION COMMITTEE
The Compensation Committee of the general partner of Martin Midstream Partners L.P. has reviewed and discussed the Compensation Discussion and Analysis section of this report with management of the general partner of Martin Midstream Partners L.P. and, based on that review and discussions, has recommended that the Compensation Discussion and Analysis be included in this report.
Members of the Compensation Committee:
/s/ Byron R. Kelley
Byron R. Kelley, 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
Compensation Committee Interlocks and Insider Participation
Other than these independent directors, no other officer or employee of our general partner or its subsidiaries is a member of the Compensation Committee. Employees of Martin Resource Management, through our general partner, are the individuals who work on our matters.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth the beneficial ownership of our units as of March 3, 2014 held by beneficial owners of 5% or more of the units outstanding, by directors of our general partner, by each executive officer and by all directors and executive officers of our general partner as a group.
(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)
By virtue of its ownership of 81.4% of the outstanding common stock of Martin Resource Management Corporation (“Martin Resource Management”), the MRMC ESOP Trust (the “MRMC ESOP”) is the controlling shareholder of Martin Resource Management, and may be deemed to beneficially own the 5,093,267 MMLP Common Units held by Martin Resource LLC and Cross Oil Refining & Marketing Inc. Wilmington Trust Retirement and Institutional Services Company serves as trustee of the MRMC ESOP but all of its voting and investment decisions are directed by the board of directors of Martin Resource Management. The MRMC ESOP expressly disclaims beneficial ownership of the MMLP Common Units as voting and investment decisions are directed by the board of directors of Martin Resource Management.
(4)
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 4,203,823 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.
(5)
Includes 5,093,267 common units beneficially owned by Martin Resource Management 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 19.4% 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. Ruben S. Martin has pledged 38,000 of his common units to third parties to secure payment for loans.
(6)
Mr. Massey may be deemed to be the beneficial owner of 1,000 common units held by his wife.
(7)
In February 2014, we issued 6,400 restricted common units to independent directors under our long-term incentive plan. These restricted common units vest in equal installments of 400 units on January 24, 2015, 2016, 2017 and 2018.
In April 2013, we issued 6,000 restricted common units to independent directors under our long-term incentive plan. These restricted common units vest in equal installments of 375 units on January 24, 2014, 2015, 2016 and 2017.
In January 2013, we issued 16,250 restricted common units to our five executive officer under our long-term incentive plan. These units vest will vest in January 2016.
On April 30, 2012, we issued 1,250 restricted common units to each of five independent directors under our long-term incentive plan. These restricted common units vest in equal installments of 312.5 units on January 24, 2013, 2014 2015, and 2016.
On May 2, 2011, we issued 1, 250 restricted common units to a independent advisory director. These units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015.
On May 2, 2011, we issued 1,250 restricted common units to each of four independent directors. These units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015.
(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.
Martin Resource Management owns a 51% voting interest in the holding company that is the sole member of our general partner and, together with our general partner, owns approximately 19.1% of our outstanding common limited partner units as of March 3, 2014. The table below sets forth information as of March 3, 2014 concerning (i) each person owning beneficially in excess of 5% of common stock of Martin Resource Management, and (ii) the beneficial common stock ownership of (a) each director of Martin Resource Management, (b) each executive officer of Martin Resource Management, and (c) all such executive officers and directors of Martin Resource Management as a group. Except as indicated, each individual has sole voting and investment power over all shares listed opposite his or her name.
(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)
The MRMC ESOP owns 184,161.62 shares of common stock of Martin Resource Management. Wilmington Trust Retirement and Institutional Services Company serves as trustee of the MRMC ESOP but all of its voting and investment decisions related to the unallocated shares of common stock are directed by the board of directors of Martin Resource Management. Of the common stock held by the MRMC ESOP, 56,119 shares of common stock are allocated to participant accounts, and 128,043 shares of common stock are unallocated.
(3)
Wesley M. Skelton is a co-trustee of the Martin Employee Stock Ownership Trust which converted from a profit sharing plan known as the Martin Employees' Stock Profit Sharing Plan on January 1, 2014. Mr. Skelton 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 42,240 shares owned by such trust. Mr. Skelton disclaims beneficial ownership of these 42,240 shares.
The following table sets forth information regarding securities authorized for issuance under our equity compensation plans as of December 31, 2013:
Equity Compensation Plan Information
¹Our 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.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Martin Resource Management owns 5,093,267 of our common limited partnership units representing approximately 19.1% of our outstanding common limited partnership units as of March 3, 2014. Martin Resource Management controls Martin Midstream GP LLC, our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC, the sole member of our general partner. Our general partner owns a 2.0% general partner interest in us and all of our incentive distribution rights. Our general partner’s ability to manage and operate us and Martin Resource Management’s ownership of approximately 19.1% of our outstanding common limited partnership units effectively gives Martin Resource Management the ability to veto some of our actions and to control our management.
Distributions and Payments to the General Partner and its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Agreements
Omnibus Agreement
We and our general partner are parties to an omnibus agreement with Martin Resource Management (the “Omnibus Agreement”) that governs, among other things, potential competition and indemnification obligations among the parties to the
agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and our use of certain of Martin Resource Management’s trade names and trademarks. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.
Non-Competition Provisions. Martin Resource Management agrees for so long as Martin Resource Management controls the general partner not to engage in the business of
•
providing terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants;
•providing marine transportation of petroleum products and by-products;
•distributing NGLs; and
•manufacturing and selling sulfur-based fertilizer products and other sulfur-related products.
This restriction does not apply to:
•
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:
◦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,
◦
providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas,
◦operating an underground NGL storage facility in Arcadia, Louisiana,
◦operating an environmental consulting company,
◦operating an engineering services company,
◦supplying employees and services for the operation of the Partnership's business,
◦operating a natural gas optimization business,
◦
operating, for its account and the Partnership's account, the docks, roads, loading and unloading facilities and other common use facilities or access routes at the Partnership's Stanolind terminal,
◦
operating, solely for the Partnership's account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas and South Houston, Texas;
•
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.
Services. Under the Omnibus Agreement, Martin Resource Management provides us with corporate staff and support services that are substantially identical in nature and quality to the services previously provided by Martin Resource Management in connection with its management and operation of our assets during the one-year period prior to the date of the agreement. The Omnibus Agreement requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses. In addition to the direct expenses, 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. Effective January 1, 2014 through December 31, 2014, the Conflicts Committee approved an annual reimbursement for indirect expenses of $12.5 million. For the years ended December 31, 2013, 2012 and 2011, the Conflicts Committee approved and we reimbursed Martin Resource Management of $10.6 million, $7.6 million and $4.8 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.
These indirect expenses cover all of the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. The provisions of the Omnibus Agreement regarding Martin Resource Management’s services will terminate if Martin Resource Management ceases to control our general partner.
Related Party Transactions. The Omnibus Agreement prohibits us from entering into any material agreement with Martin Resource Management without the prior approval of the Conflicts Committee. For purposes of the Omnibus Agreement, the term material agreements means any agreement between us and Martin Resource Management that requires aggregate annual payments in excess of then-applicable limitation on the reimbursable amount of indirect general and administrative expenses. Please read “ Services” above.
License Provisions. Under the Omnibus Agreement, Martin Resource Management has granted us a nontransferable, nonexclusive, royalty-free right and license to use certain of its trade names and marks, as well as the trade names and marks used by some of its affiliates.
Amendment and Termination. The Omnibus Agreement may be amended by written agreement of the parties; provided, however that it may not be amended without the approval of the Conflicts Committee if such amendment would adversely affect the unitholders. The Omnibus Agreement was first amended on November 25, 2009, to permit us to provide refining services to Martin Resource Management. The Omnibus Agreement was amended further on October 1, 2012, to permit us to provide certain lubricant packaging products and services to Martin Resource Management. Such amendments were approved by the Conflicts Committee. The Omnibus Agreement, other than the indemnification provisions and the provisions limiting the amount for which we will reimburse Martin Resource Management for general and administrative services performed on our behalf, will terminate if we are no longer an affiliate of Martin Resource Management.
Motor Carrier Agreement
We are a party to a motor carrier agreement effective January 1, 2006, as amended, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Resource Management operates its land transportation operations. Under the agreement, Martin Transport, Inc. agrees to ship our NGL shipments as well as other liquid products.
Term and Pricing. The agreement has an initial term that expired in December 2007 but 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. We have the right to terminate this agreement at anytime by providing 90 days prior notice. Under this agreement, Martin Transport, Inc. transports our NGL shipments as well as other liquid products. These rates are subject to any adjustment to which are mutually agreed or in accordance with a price
index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the United States Department of Energy’s national diesel price list.
Indemnification. Martin Transport has indemnified us against all claims arising out of the negligence or willful misconduct of Martin Transport and its officers, employees, agents, representatives and subcontractors. We indemnified Martin Transport against all claims arising out of the negligence or willful misconduct of us and our officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin Transport and us, our indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligence or misconduct.
Terminal Services Agreements
Diesel Fuel Terminal Services Agreement. We are a party to an agreement under which we provide terminal services to Martin Resource Management. This agreement was amended and restated as of October 27, 2004 and was set to expire in December 2006, but automatically renewed and will continue to automatically renew on a month-to-month basis until either party terminates the agreement by giving 60 days written notice. The per gallon throughput fee we charge under this agreement may be adjusted annually based on a price index.
Miscellaneous Terminal Services Agreements. We are currently party to several terminal services agreements and, from time to time, we may enter into other terminal service agreements for the purpose of providing terminal services to related parties. Individually, each of these agreements is immaterial but when considered in the aggregate they could be deemed material. These agreements are throughput based with a minimum volume commitment. Generally, the fees due under these agreements are adjusted annually based on a price index.
Talen's Agreements. In connection with the Talen's acquisition, new agreements were executed, each with effective dates of December 31, 2012. Under the terms of these contracts, Talen's provides terminal services to Martin Resource Management. The terminal services agreements both have five-year terms and provide a per gallon throughput rate, which may be adjusted annually based on a price index.
Marine Agreements
Marine Transportation Agreement. We are a party to a marine transportation agreement effective January 1, 2006, which was amended January 1, 2007, under which we provide marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. Effective each January 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then- applicable term. The fees we charge Martin Resource Management are based on applicable market rates.
Marine Fuel. We are a party to an agreement with Martin Resource Management dated November 1, 2002 under which Martin Resource Management provides us with marine fuel from its locations in the Gulf of Mexico at a fixed rate over the Platt’s U.S. Gulf Coast Index for #2 Fuel Oil. Under this agreement, we agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management.
Other Agreements
Cross Tolling Agreement. We are party to an agreement with Cross, dated November 25, 2009, under which we process crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The tolling agreement, which has subsequently been amended, has a 22 year term which expires November 25, 2031. Under this tolling agreement, Martin Resource Management agreed to refine a minimum of 6,500 barrels per day of crude oil at the refinery at a fixed price per barrel. Any additional barrels are refined at a modified price per barrel. In addition, Martin Resource Management agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.
Sulfuric Acid Sales Agency Agreement. We are a party to a second amended and restated sulfuric acid sales agency agreement dated August 5, 2013 under which Martin Resource Management purchases and markets the sulfuric acid produced by our sulfuric acid production plant at Plainview, Texas, and which is not consumed by our internal operations. This agreement, as amended, will remain in place until we terminate it by providing 180 days’ written notice. Under this agreement,
we sell all of our excess sulfuric acid to Martin Resource Management. Martin Resource Management then markets such acid to third-parties and we share in the profit of Martin Resource Management’s sales of the excess acid to such third parties.
Other Miscellaneous Agreements. From time to time we enter into other miscellaneous agreements with Martin Resource Management for the provision of other services or the purchase of other goods.
Other Related Party Transactions
2012 Public Offerings.
Public Offerings. On January 25, 2012, we completed a public offering of 2,645,000 common units at a price of $36.15 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 2,645,000 common units, net of underwriters' discounts, commissions and offering expenses were $91.4 million. Our general partner contributed $2.0 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. On January 25, 2012, all of the net proceeds were used to reduce our outstanding indebtedness.
On November 26, 2012, we completed a public offering of 3,450,000 common units at a price of $31.16 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses were $102.8 million. Our general partner contributed $2.2 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. All of the net proceeds were used to reduce our outstanding indebtedness.
2011 Public Offering.
On February 9, 2011, we completed a public offering of 1,874,500 common units at a price of $39.35 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 1,874,500 common units, net of underwriters’ discounts, commissions and offering expenses were $70.7 million. Our general partner contributed $1.5 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us.
Marine Transportation Equipment Purchase. On September 30, 2013, we acquired two inland tank barges from Martin Resource Management for $7.1 million. The excess carrying value of the assets over the purchase price paid by Martin Resource Management at the sales date was $0.3 million and was recorded as an adjustment to partners' capital.
Talen's Marine & Fuel, LLC. On December 31, 2012, we acquired all of the outstanding membership interests in Talen's from Quintana Energy Partners, L.P. for $103.4 million, subject to certain post-closing adjustments. Simultaneous with the acquisition, we sold certain working capital-related assets and a customer relationship intangible asset to Martin Energy Services LLC for $56.0 million. The excess carrying value of the assets over the purchase price paid by Martin Resource Management at the sales date was $4.3 million and was recorded as an adjustment to partners' capital.
Lubricant Product Blending and Packaging Assets. On October 2, 2012, we acquired from Cross, certain specialty lubricant product blending and packaging assets, including working capital, for total consideration of $121.8 million in cash at closing, plus a final net working capital adjustment of $0.9 million paid in October of 2012. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these blending and packaging assets was recorded at the historical carrying value of the assets at the acquisition date, which totaled $62.4 million. The excess purchase price over the historical carrying value of the assets at the acquisition date was $60.3 million and was recorded as an adjustment to partners' capital.
Redbird Class A Interests. On October 2, 2012, we acquired from Martin Resource Management all of the remaining Class A interests in Redbird for $150.0 million in cash. The acquisition of these interests was recorded at the historical carrying value of the interests at the acquisition date. We recorded an investment in consolidated entities of $68.2 million and the excess of the purchase price over the carrying value of the Class A interests of $81.8 million was recorded as an adjustment to partners' capital.
Acquisition of Certain Terminalling Assets. On January 31, 2011, we acquired 13 shore-based marine terminalling facilities, one specialty terminalling facility and certain terminalling related assets from Martin Resource Management for
$36.5 million. The net book value of the acquired assets of $16.8 million was recorded in property, plant and equipment. The remaining $19.7 million was recorded as a reduction of partners' capital.
Miscellaneous. Certain of directors, officers and employees of our general partner and Martin Resource Management maintain margin accounts with broker-dealers with respect to our common units held by such persons. Margin account transactions for such directors, officers and employees were conducted by such broker-dealers in the ordinary course of business.
For information regarding amounts of related party transactions that are included in the Partnership's Consolidated Statements of Operations, please see Footnote 13, "Related Party Transactions", in Part II, Item 8.
Approval and Review of Related Party Transactions
If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our general partner or to our management, as appropriate. If the board of directors is involved in the approval process, it determines whether to refer the matter to the Conflicts Committee, as constituted under our limited partnership agreement. If a matter is referred to the Conflicts Committee, it obtains information regarding the proposed transaction from management and determines whether to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. If the Conflicts Committee retains such counsel or financial advisor, it considers such advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.
Item 14.
Item 14.
Principal Accounting Fees and Services
KPMG, LLP served as our independent auditors for the fiscal years ended December 31, 2013 and 2012. The following fees were paid to KPMG, LLP for services rendered during our last two fiscal years:
(1)
2013 audit fees include fees for the annual integrated audit and fees related to services in connection with filing updated financial statements and in connection with transactions. 2012 audit fees include fees for the annual integrated audit and fees related to services in connection with filing updated financial statements and 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.
Under policies and procedures established by the Board of Directors and the Audit Committee, the Audit Committee is required to pre-approve all audit and non-audit services performed by our independent auditor to ensure that the provisions of such services do not impair the auditor’s independence. All of the services described above that were provided by KPMG LLP in years ended December 31, 2013 and December 31, 2012 were approved in advance by the Audit Committee.
PART IV
Item 15.
Item 15.
Exhibits, Financial Statement Schedules
(a) Financial Statements, Schedules
(1)
The following financial statements of Martin Midstream Partners L.P. and are included in Part II, Item 8:
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2013 and 2012
Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011
Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011
Consolidated Statements of Changes in Capital for the years ended December 31, 2013, 2012 and 2011
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2012 and 2011
Notes to the Consolidated Financial Statements
(2)
Financial Statements of Waskom Gas Processing Company for the seven months ended July 31, 2012 and year ended December 31, 2011, an affiliate accounted for by the equity method, which constituted a significant subsidiary.
(b) Exhibits
Reference is made to the Index to Exhibits beginning on page 136 for a list of all exhibits filed as part of this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, we have duly caused this Report to be signed on our behalf by the undersigned, thereunto duly authorized representative.
Martin Midstream Partners L.P.
(Registrant)
By: Martin Midstream GP LLC
It's General Partner
Date: March 3, 2014 By: /s/ Ruben S. Martin
Ruben S. Martin
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 3rd day of March, 2014.
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/ Alexander W.F. Black
Director of Martin Midstream GP LLC
Alexander W.F. Black
/s/ Sean P. Dolan
Director of Martin Midstream GP LLC
Sean P. Dolan
/s/ C. Scott Massey
Director of Martin Midstream GP LLC
C. Scott Massey
/s/ Byron R. Kelley
Director of Martin Midstream GP LLC
Byron R. Kelley
/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
INDEX TO EXHIBITS
(1) Material has been redacted from this exhibit and filed separately with the Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, which has been granted.
Financial Statement Schedule
Pursuant to Item 15(a)(2)
INDEPENDENT AUDITORS' REPORT
To the Partners of
Waskom Gas Processing Company:
We have audited the accompanying consolidated balance sheet of Waskom Gas Processing Company and subsidiaries (the “Partnership”) as of December 31, 2011 and the related consolidated statements of income, partners' capital, and cash flows for the year ended December 31, 2011. These consolidated financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Waskom Gas Processing Company and subsidiaries as of December 31, 2011 and the results of their operations and their cash flows for the year ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Shreveport, Louisiana March 5, 2012
WASKOM GAS PROCESSING COMPANY
See accompanying notes to consolidated financial statements.
WASKOM GAS PROCESSING COMPANY
See accompanying notes to consolidated financial statements.
WASKOM GAS PROCESSING COMPANY
See accompanying notes to consolidated financial statements.
WASKOM GAS PROCESSING COMPANY
See accompanying notes to consolidated financial statements.
WASKOM GAS PROCESSING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
NATURE OF BUSINESS
Waskom Gas Processing Company (the “Partnership”), a Texas General Partnership, was formed on November 1, 1995 to construct and operate the Waskom Processing Plant (“the Plant”). As of December 31, 2011 the partners are CenterPoint Energy Gas Processing Company (50%) and Prism Gas Systems I, L.P. (50%). Prism Gas Systems I, L.P. serves as operator. The Partnership is engaged in the processing, gathering and marketing of natural gas and natural gas liquids (“NGL's”), predominantly in Texas and northwest Louisiana.
The Plant is a 320 MMcfd cryogenic turboexpander gas plant located in Harrison County, Texas. The Plant has full NGL fractionation, treating and stabilization capabilities. Fractionation is a process used to separate the mixture of NGL's into individual products for sale. Expansions to the processing plant were completed in March and June of 2007, July of 2008, June of 2009 and September of 2011 increasing the capacity from 150 MMcfd to 320 MMcfd. In July 2009 the Waskom fractionator was expanded to a capacity of 14,500 barrels per day from 12,500 barrels per day. A NGL railroad loading facility was constructed in 2011 and was placed in operation in the first quarter of 2012.
The natural gas supply for the Plant is derived primarily from natural gas wells located in the Cotton Valley formation of East Texas and Northwest Louisiana. The primary suppliers of natural gas to the Plant include BP American Production Company, Centerpoint Energy Gas Transmission Company, Samson Lone Star, LLC and Devon Energy Corporation, which collectively represent approximately 75% of the 252 MMcfd of natural gas supplied for the seven months ended July 31, 2012. The primary suppliers of natural gas to the Plant include BP American Production Company, Centerpoint Energy Gas Transmission Company, GMX/Endeavour Pipeline, Inc., Samson Lone Star, LLC and Devon Energy Corporation, which collectively represent approximately 77% of the 269 MMcfd of natural gas supplied for the year ended December 31, 2011.
The processing contracts for the Waskom Processing Plant are primarily percent-of-liquids (“POL”) contracts, in which we retain a portion of the NGL's recovered as a processing fee, percent-of-proceeds (“POP”) contracts in which we retain a portion of both the residue gas and the NGL's as payment for services and straight fee contracts in which we receive a fee for every Mcf of gas delivered to the plant. As of July 31, 2012, approximately 37.5% of the contracts are POL, 25% of the contracts are fee and 25% of the contracts are POP (unaudited). In addition, there is one minor contract for processing on a keep-whole basis and there is one purchase contract.
Sales of third party gas and fractionated NGL's are predominately to the partners and occur at the tailgate of the Plant.
2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation - During 2010 and 2008, Waskom Midstream LLC and Waskom Products Pipeline, LLC, respectively, were formed as wholly owned subsidiaries of Waskom Gas Processing Company, to hold certain plant and pipeline assets of the Partnership. Accordingly, the financial statements are consolidated to include these entities. All eliminations of intercompany balances have been made.
Accounts Receivable - Accounts receivable include trade receivables, recorded at invoiced amounts.
Property and Equipment - Property and equipment are stated at cost and depreciated using the straight-line method over the estimated useful lives of the classes of assets, as follows:
Depreciation expense was $4,660,825 (unaudited) and $6,794,726 for the seven months ended 2012 and the year ended December 31, 2011, respectively. Repairs and maintenance are charged to operations as incurred. Renewals and betterments are capitalized.
Inventories - Substantially all inventory at July 31, 2012 and December 31, 2011 represents pipe held for future projects. Such pipe was valued at acquisition cost.
Asset Retirement Obligations - The Partnership records asset retirement obligations (“ARO”) for costs associated with legal obligations to retire tangible, long-lived assets. The Partnership records as an offset to the “ARO”, an asset at fair
value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset. The Partnership's asset retirement obligations include purging, plugging and remediation costs associated with the pipeline. Accretion expense for the seven months ended July 31, 2012, and the year ended December 31, 2011 was $34,063 (unaudited) and $54,536, respectively.
Impairment of Long-Lived Assets - Long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.
Revenue Recognition - Revenues are recognized when title passes or service is performed. The Partnership's business consists largely of the ownership and operation of physical assets. End sales from these businesses result in physical deliveries of commodities.
Federal Income Taxes - The Partnership is a Texas General Partnership and as such has no liability for Federal Income Taxes. Each partner is responsible for its share of federal income tax.
On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state business tax by replacing the taxable capital and earned surplus components of the then existing franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the new margin tax. These deferred taxes are immaterial. Texas margin tax expense for the seven months ended July 31, 2012 and the year ended December 31, 2012 and 2011 was $100,000 (unaudited) and $53,008, respectively.
Environmental Liabilities - The Partnership's policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses for environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value.
Use of Estimates - The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts at the date of the financial statements and the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates.
3.
RELATED-PARTY TRANSACTIONS
During 2012 and 2011, the Partnership engaged in certain material transactions with the partners. The Partnership believes that the terms of these transactions were comparable to those that could have been negotiated with unrelated third parties. As of July 31, 2012 and December 31, 2011, the Partnership had receivables of approximately $5,869,715 (unaudited) and $18,241,163, respectively, and payables of approximately $2,131,007 (unaudited) and $4,057,864, respectively, due from and due to the partners.
Per the partnership agreement, cash contributions are made by the partners for capital expenditures and working capital. Contributions for capital expenditures totaled $7,293,499 (unaudited) and $32,209,322 for the seven months ended 2012, and the year ended 2011, respectively. The partnership agreement allows for cash distributions to be made to the partners of any cash available in excess of working capital requirements, generally equal to two months of historical operating expenses. Such cash distributions in excess of working capital totaled $1,209,056 (unaudited) and $4,432,461 for the seven months ended 2012, and the year ended 2011, respectively. Other cash distributions totaled $0 (unaudited) and$2,400,000 for the seven months ended 2012, and the year ended 2011, respectively.
The Partnership purchases gas from third party producers and processes this gas based on processing contracts, which are primarily POL contracts. The percentage of liquids retained by the Partnership is distributed to the partners as distributions of products-in-kind based on the partners' equity interest. Distributions of products in-kind of $12,723,846 (unaudited) and
$25,407,211for the seven months ended 2012, and the year ended 2011, respectively, were made to the partners. Distributions of products in-kind are valued at prevailing market prices at the time of distribution.
In some instances, the fractionated NGL's (less any retained portions) are returned to the third party producers, but in most cases, the third party producers enter into agreements with the partners to market their product. In such instances, the Partnership will sell the product to the partners. Such sales amounted to $48,098,581 (unaudited) and $85,613,194 for the seven months ended 2012, and the year ended 2011, respectively, and are included as natural gas liquid sales in the income statement.
4.
ACQUISITION
On January 15, 2010, the Partnership through its wholly owned subsidiary Waskom Midstream LLC, acquired from Crosstex North Texas Gathering, L.P., a 100% interest in approximately 62 miles of gathering pipeline, two 35 MMcfd dew point control plants and equipment referred to as the Harrison Pipeline System for approximately $40,000,000.
5.
COMMITMENTS AND CONTINGENCIES
The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Management believes that any future costs should not have a material adverse effect on the Partnership's liquidity or financial position.
6.
SUBSEQUENT EVENT
On July 31, 2012, Prism Gas Systems I, L.P. sold its 50% interest in the Partnership to CenterPoint Energy Gas Processing Company.