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Designing
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2012 AnnuAl RepoRt
About Martin Midstream Partners L.P.
Martin Midstream Partners L.P. is a publicly traded limited partnership with a diverse set of operations
focused primarily in the United States Gulf Coast region. Our four primary business lines include:
terminalling, storage, processing and packaging services for petroleum products and by-products;
natural gas liquids storage, marketing and 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 we gather, process, transport, store and market are produced
primarily by major and independent oil and gas companies who often turn to third parties, such as us,
for the transportation and disposition of these products. In addition to these major and independent
oil and gas companies, our primary customers include independent refiners, large chemical companies,
fertilizer manufacturers and other wholesale purchasers of these products. We generate the majority
of our cash flow from fee-based contracts with these customers. Our location in the Gulf Coast region
of the United States provides us strategic access to a major hub for petroleum refining, natural gas
gathering and processing and support services for the exploration and production industry.
We were formed in 2002 by Martin Resource Management Corporation (“Martin Resource Management”),
a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products
and services to drilling rig contractors. Since then, Martin Resource Management has expanded its
operations through acquisitions and internal expansion initiatives as its management identified and
capitalized on the needs of producers and purchasers of hydrocarbon products and by-products and
other bulk liquids.
TeRMInaLLInG & STORaGe
naTURaL GaS SeRvICeS
SULfUR SeRvICeS
MaRIne TRanSPORTaTIOn
U.S. InLand and WaTeRWayS SeRved
Robert D. Bondurant
Chief Financial Officer
Randall L. Tauscher
Chief Operating Officer
Wesley M. Skelton
Chief Administrative Officer
Chris H. Booth
Chief Legal Officer
Improving Our Company
A strong management team is the foundation of any company. Martin Midstream’s
senior management team has an average of 23 years providing vision and direction.
D e s i g n i n g o u r F u t u r e
Martin MidstreaM Partners L.P. 2012 annuaL rePort
Pag e 1
Let ter to u n ith o LD ers
Dear Fellow Unitholders,
Last year in my letter to the unitholders we
production. Currently, we are continuing to
commemorated our 10th Anniversary as a
invest in the packaging division having added
publicly traded master limited partnership. Now
single unit container manufacturing on-site
in our 11th year, we are reaping the efforts
further integrating our operations.
of the first decade and positioning ourselves
for the next 10 years while participating in the
greatest energy boom in our nation’s history.
We subscribe to the notion that U.S. energy
independence is a true possibility. To that
end, we are actively participating in the Eagle
We will look back at 2012 as a transformative
Ford shale crude oil and liquids transportation
year for MMLP. We divested a large portion
value chain. Our world-class terminal at the
of our Natural Gas Services asset base and
Port of Corpus Christi has current capacity of
virtually eliminated direct natural gas commodity
600,000 barrels of off-take storage available
exposure through gathering and processing.
for cross-handling to marine tankers and
We reinvested those proceeds into fee-based
barges. During 2013, we are constructing an
natural gas storage interests and our fast-
additional 300,000 barrels of storage capacity
growing lubricant packaging division of our
which is also under long-term contract and
Terminalling and Storage segment. While we
plan to be loading up to 200,000 barrels per
have taken a long-term view pertaining to the
day for our anchor customer. We expect to
natural gas storage development and do not
commence commercial operations on the
expect an immediate cash flow impact, our
final stage of the terminal during the second
packaging division has shown remarkable
quarter of 2014. Also, earlier in 2013 we
upside and stronger than anticipated cash
acquired six liquefied petroleum barges,
flow in just its first two quarters. We believe
enhancing our natural gas liquids transport
our system is the only one of its kind efficiently
and handling capability associated with the
packaging lubricants directly at the source of
shale phenomena.
“Unitholders will
continUe to harvest
economic retUrns
as we execUte oUr
growth strategy.”
ruben s. MArtin iii
At the end of 2012, we acquired Talen’s
energy. Through the hard work of our
Marine & Fuel, LLC (Talen’s) and added 10
employees, our Partnership is well-positioned
marine terminal locations. We believe that
financially, geographically and strategically to
with Talen’s, we command a significant market
capture some of the upside of this amazing
position servicing our customers in the U.S.
energy revolution.
Gulf Coast with fuel and lubricant volumes
flowing through our marine terminal system.
The positive momentum we carried at the
end of 2012 has continued thus far in 2013.
The management team we have assembled
Based on the strength of our first quarter
continues to improve as we grow. We have a
performance, we raised the distribution to a
well-balanced mix of long-term experience
new annualized level of $3.10 and our units
and a strong team of younger professionals
have responded positively thus far.
eager to lead our organization for years to
come. The Partnership’s assets have never
operated with the current level of efficiency
and I firmly believe this is attributable to our
We are glad you have chosen to be our
partners. I wish you continued prosperity
for the remainder of 2013.
enhanced management. That, coupled with
Yours Truly,
our increasing focus on health, safety and
environmental issues, renders a team of which
I am truly proud.
That said, I believe there is more opportunity
Ruben S. Martin III
today than I can recall at any point in my
President & Chief Executive Officer
30-plus year career servicing midstream
D e s i g n i n g o u r F u t u r e
Martin MidstreaM Partners L.P. 2012 annuaL rePort
Pag e s 2 / 3
segM ent overvi ew
Facilities within Martin Midstream’s Terminalling & Storage segment provide
storage, refining, blending, packaging and handling services for producers
350000
and suppliers of petroleum products and by-products, lubricants and other
300000
liquids and fuel oil, including the refining, blending and packaging of various
250000
grades and quantities of naphthenic lubricants and related products. These
200000
facilities and resources provide us with the ability to handle various products
requiring specialized treatment, such as molten sulfur and asphalt. We also
150000
provide land rental to oil and gas companies along with storage and handling
100000
services for lubricants and fuel oil. Through a recent acquisition we acquired
10 additional terminals from Martin Resource Management, bringing us to
a total of 47 terminals along the Gulf Coast. This business is built on quality
service and long-term relationship with our customers.
50000
’08
’09
’10
’12
’11
0
Percent of
Operating
Income
Operating Revenue
after Eliminations
(IN MILLIONS)
$318
$279
$186
$165
$195
39%
$51 MiLLion
’08
’09
’10
’11
’12
Martin Midstream’s Natural Gas Services segment distributes natural gas liquids
(“NGLs”). We purchase NGLs primarily from refineries and natural gas processors.
1000000
We store NGLs in our supply and storage facilities for wholesale deliveries to
800000
propane retailers, refineries and industrial NGL users in Texas and the Southeastern
U.S. We own an NGL pipeline which spans approximately 200 miles running from
600000
Kilgore, Texas to Beaumont, Texas. We own three NGL supply and storage
facilities with an aggregate above-ground storage capacity of approximately
400000
3,000 barrels and we lease approximately 2.7 million barrels of underground
200000
storage capacity for NGLs. Additionally, through our ownership interests in
Redbird Gas Storage LLC, we are partners in a joint venture, Cardinal Gas
Storage Partners LLC, which is focused on the development, construction,
operation and management of natural gas storage facilities across northern
Louisiana and Mississippi.
’08
’09
’10
’12
’11
0
Percent of
Operating
Income
14%
$18 MiLLion
Operating Revenue
after Eliminations
(IN MILLIONS)
$826
$612
$532
$442
$338
’08
’09
’10
’11
’12
350000
400000
300000
The Sulfur Services segment of Martin Midstream manufactures and sells
fertilizer products and has an integrated system of transportation assets
and facilities relating to sulfur services. We process and distribute sulfur
predominantly produced by oil refineries primarily located in the United
States Gulf Coast region. At our facilities in California and Texas, we process
molten sulfur into formed solid sulfur. The sulfur we process is primarily
used in the production of fertilizers and industrial chemicals. We own and
operate six sulfur-based fertilizer production plants and one emulsified
sulfur blending plant. These plants are located in Illinois, Texas and Utah.
We also own and operate a sulfuric acid production plant, which processes
molten sulfur into sulfuric acid, and an ammonium sulfate plant, both located
in Plainview, Texas.
200000
250000
100000
150000
50000
’08
’09
’10
’12
’11
0
Percent of
Operating
Income
34%
$45 MiLLion
Operating Revenue
after Eliminations
(IN MILLIONS)
$372
$275
$262
$165
$80
’08
’09
’10
’11
’12
100000
Martin Midstream’s Marine Transportation segment consists of 54 inland
marine tank barges, 29 inland push boats and four offshore tug/barge units.
Our fleet transports petroleum products and by-products domestically,
coastwise and along the inland waterways system, and internationally,
including the Caribbean, Central America, and South America. We have
invested significantly to modernize our fleet. As a result, the average
age of our vessels is 23 years. We believe our modernized fleet is more
attractive to our existing customers as well as potential new customers.
In addition, our fleet contains vessels that reflect our focus on specialty
product transportation.
80000
60000
40000
20000
0
Percent of
Operating
Income
14%
$18 MiLLion
’08
’09
’10
’11
’12
Operating Revenue
after Eliminations
(IN MILLIONS)
$76
$78
$77
$68
$86
’08
’09
’10
’11
’12
D e s i g n i n g o u r F u t u r e
Martin MidstreaM Partners L.P. 2012 annuaL rePort
Pag e s 4 / 5
Co rpus Ch risti , tex A s
Late in 2012, the Partnership successfully put into service new terminalling assets
strategically located at the Port of Corpus Christi, Texas. Approximately 600,000 barrels
of storage was constructed at the terminus point of the Harvest Gardendale Pipeline.
Our tankage and strategic location facilitate the extraction of Eagle Ford Shale crude
oil production moving through the terminal to waterborne access within the port. The
terminal operates under a long-term contract with a major integrated oil company.
During 2013, the Partnership is constructing an additional 300,000 barrels of storage
capacity to be put in service by the second quarter of 2014.
(cid:31) CORPuS CHRISTI
CRuDE TERMInaL
the Corpus Christi
CruDe FACiLity is
weLL-positioneD For
signiFiCAnt Fee-bAseD
CAsh FLow growth As
eAgLe ForD ACtivity
Continues to gAin
MoMentuM.
D e s i g n i n g o u r F u t u r e
Martin MidstreaM Partners L.P. 2012 annuaL rePort
Pag e s 6 / 7
sMACkover , Ark AnsA s
During the second quarter of 2012, the Partnership successfully put into service a new
vacuum tower at our Smackover Naphthenic lube oil processing facility. The new vacuum
tower was designed with a larger diameter column and more efficient vacuum to reduce
the amount of vacuum tower bottoms. This tower creates improved efficiency at the
refinery by yielding more high viscosity base oils and reducing lower value asphalt yields
from the crude source. The vacuum tower project represents an approximate investment
of $23 million.
our new vACuuM
tower wiLL inCreAse
the FACiLity’s eFFiCienCy
by reDuCing the
AMount oF non-
LubriCAnt resiDuAL
oiL proDuCeD.
no rth ern Loui siAnA/ Miss iss ip p i
During the fourth quarter of 2012, the Partnership purchased all of the remaining Class A
equity interests in Redbird Gas Storage LLC (“Redbird”) for $150 million. Redbird was
formed by the Partnership and Martin Resource Management to invest in Cardinal Gas
Storage Partners LLC (“Cardinal”). Cardinal is a joint venture between Redbird and
Energy Capital Partners that is focused on the development, construction, operation
and management of four natural gas storage facilities in the Southeastern United States.
Through the acquisition, Redbird became a wholly-owned subsidiary of the Partnership
owning an approximate 38.4% membership interest in Cardinal at year end 2012. Cardinal
plans to put multiple natural gas storage assets into service in the next year and expects
to receive distributions from those assets commencing in 2015.
D e s i g n i n g o u r F u t u r e
Martin MidstreaM Partners L.P. 2012 annuaL rePort
Pag e s 8 / 9
our purChAse oF the
sMACkover pACkAging
Assets CreAtes Another
soLiD growth pLAtForM For
MMLp. these Assets proviDe
Further integrAtion
to MMLp’s sMACkover
LubriCAnt FACiLity FroM
whiCh we wiLL work to
Lever into ADDitionAL
MArket shAre going
ForwArD.
sMACkover , Ark AnsA s
During the fourth quarter of 2012, the Partnership acquired certain specialty lubricant
product packaging assets from Cross Oil Refining & Marketing, Inc. (“Cross”), a wholly-
owned subsidiary of Martin Resource Management for approximately $122 million. With
this acquisition, the Partnership will be one of the largest independent manufacturers
and distributors of specialty lubricant products. These specialty lubricant products are
used in various applications including hydraulic fluids, transmission fluids, motor oils,
machine/gear oils as well as other commercial and industrial applications. The packaging
asset is primarily located on-site at the Cross naphthenic lubricant refinery in Smackover,
Arkansas creating the only single-site, fully-integrated lubricant refining, blending and
packaging facility in the United States.
u. s . gu LF Co A st
At the end of 2012, the Partnership acquired Talen’s Marine & Fuel, L.L.C. This acquisition
expands our shore-based marine terminal infrastructure by adding ten marine terminal
locations between Houston/Galveston, Texas and Port Fourchon, Louisiana. Through
the acquisition, we added approximately 300,000 barrels of tankage and an additional
4,000 feet of water-accessible bulkhead. The Partnership has one of the most comprehensive
United States Gulf Coast shore-based marine terminalling systems in existence. Our
terminalling system supports the offshore oil and gas exploration and production
industry. Together with our affiliate Martin Resource Management, we are a leading
supplier of fuels, lubricants and full-service logistical support across the region.
the tALen’s ACquisition
gives MMLp A LeADing
MArket position oF
FueLing AnD LubriCAnt
terMinALs ALong the
guLF CoAst.
D e s i g n i n g o u r F u t u r e
Martin MidstreaM Partners L.P. 2012 annuaL rePort
Pag e s 10 /11
Fi nA n CiAL h i gh Li ghts
(in thousands, except per unit amounts)
2008
2009
2010
2011
2012
Total Assets
Revenue
1500000
Operating Income
1200000
Net Income
900000
Net Distributable Cash Flow
600000
Distributions per Unit
$ 763,211
$ 739,161
$ 864,425
$ 1,069,108
$ 1,012,996
$ 1,162,749
$ 651,174
$ 880,115
$ 1,242,490
$ 1,490,361
100000
80000
60000
40000
$
$
$
$
48,602
$ 43,138
$ 48,082
65,741
$ 22,943
$ 27,533
64,309
$ 59,235
$ 69,196
3.5
$
3.0
2.5
2.0
$
$
2.91
$
3.00
$
3.00
1.5
$
3.05
47,352
$
73,835
22,759
$ 101,987
67,471
$
$
88,897
3.08
300000
*includes continuing and discounted operations
20000
0
’08
’09
’10
’11
’12
0
’08
’09
’10
’11
’12
1.0
0.5
0.0
’08
’09
’10
’11
’12
Revenue
(IN MILLIONS)
net Distributable Cash Flow
(IN MILLIONS)
Distributions per L.P. unit
$1,490
$1,163
$1,242
$880
$651
$89
$2.91
$3.00
$3.00
$3.05
$3.08
$64
$59
$69
$67
’08
’09
’10
’11
’12
’08
’09
’10
’11
’12
’08
’09
’10
’11
’12
Page 12
Mart in Midstr eaM Part ner s L. P. 2012 annu aL rePort
C hAn g e f o r s t r o n g r e s U lt s
D e s i g n i n g o u r F u t u r e
M a r t i n M i d s t r e a M Pa r t n e r s L . P. 2 0 12 an n uaL
r eP o r t
Pag e s 6 / 7
Adjusted EBITDA by Segment as of 12/31/12
Terminalling
and Storage
Sulfur
Services
Natural
Gas Services
Marine
Transportation
12/31/12
Reconciliation of operating income from
continuing operations to Adjusted EBITDA
Operating Income from continuing operations
Depreciation and amortization
Loss on disposition or sale of property,
plant, and equipment
Mount Belvieu escrow payment
Distributions from unconsolidated entities
Non-cash compensation expense
$27,944
22,976
$37,262
7,371
$13,924
601
$ 6,751
11,115
$ 85,881
42,063
496
(375)
—
—
258
—
—
—
—
—
3,961
—
41
—
—
—
795
(375)
3,961
—
Adjusted EBITDA(1)(2)
$51,041
$44,891
$18,486
$17,907
$132,325
Percentage Contribution by Segment
39%
34%
14%
14%
100%
(1) Excludes unallocated SG&A of $11,661
(2) Financial information includes results attributable to the Redbird Gas Storage LLC Class A interests and the blending and packaging assets prior to acquisition
Distributable Cash Flow Reconciliation
Net income
Less: (Income) loss from discontinued operations
Net income from continuing operations
Adjustments to reconcile net income to distributable cash flow:
Continuing operations:
Depreciation and amortization
Loss (gain) on sale of property, plant and equipment
Amortization of debt discount
Amortization of deferred debt issuance costs
Gain from ownership change in unconsolidated entity
Gain on involuntary conversion of property, plant and equipment
Payments of installment notes payable and capital lease obligations
Deferred income taxes
Early extinguishment of interest rate swaps
Non-cash operating lease expense
Non-cash hurricane costs (net of cash payments)
Mont Belvieu indemnity escrow payment
Debt prepayment premium
Gain on sale of equity method investment
Equity in (earnings) loss of unconsolidated entities
Gain on contribution of assets to Redbird
Payments for plant turnaround costs
Maintenance capital expenditures
Other
Distribution equivalents from unconsolidated entities from
2008(1)
2009(1)
2010(1)
2011(1)
2012(1)
$ 65,741
(16,816)
$ 22,943
(5,268)
$ 27,533
(8,061)
$ 22,759
(9,392)
$ 101,987
(64,865)
48,925
17,675
19,472
13,367
37,122
32,150
(128)
—
1,120
—
(65)
—
638
—
—
512
—
—
—
2,160
(24,271)
—
(16,331)
39
36,183
(5,008)
—
1,689
(3,028)
(1,017)
—
311
—
—
—
—
—
—
5,053
—
—
(6,998)
98
36,884
119
269
4,814
(6,413)
—
—
452
3,850
—
—
(348)
—
—
(2,536)
—
(1,090)
(4,093)
113
40,276
899
351
3,755
—
—
(1,132)
622
—
69
—
—
—
—
4,752
—
(2,103)
(9,807)
190
42,063
795
581
3,290
—
—
(279)
402
—
—
—
(375)
2,470
(486)
1,113
—
(2,107)
(8,658)
385
continuing operations
—
—
—
1,432
3,961
Distributable cash flow from continuing operations
44,749
44,958
51,493
52,671
80,277
Discontinued operations:
Income (loss) from discontinued operations, net of tax
Depreciation and amortization
Loss (gain) on sale of property, plant and equipment
Gain on sale of discontinued operations
Non-cash mark to market on derivatives
Deferred income taxes
Income tax expense from sale of discontinued operations
Equity in earnings of unconsolidated entities
Maintenance capital expenditures
Distribution equivalents from unconsolidated entities from
16,816
3,545
—
(3)
(2,327)
2,177
—
(13,224)
(1,667)
5,268
3,963
12
—
2,526
90
—
(7,044)
(603)
8,061
4,452
93
—
380
(415)
—
(9,792)
(560)
9,392
5,512
—
—
(3,293)
(155)
—
(9,411)
(1,140)
64,865
2,320
(10)
(61,848)
—
—
1,598
(4,611)
(537)
discontinued operations
11,450
7,353
13,015
14,163
6,792
Invested cash in unconsolidated entities from discontinued
operations
2,793
2,712
2,469
(268)
51
Distributable cash flow from discontinued operations
19,560
14,277
17,703
14,800
8,620
Net Distributable cash flow
$ 64,309
$ 59,235
$ 69,196
$ 67,471
$ 88,897
(1) Financial information for 2012, 2011, 2010, 2009 and 2008 has been revised to include results attributable to the Redbird Class A interests and the Blending and
Packaging Assets acquired from Cross prior to October 2, 2012
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Mark One
FORM 10-K
Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the fiscal year ended December 31, 2012
OR
Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the transition period from _____ to _____.
Commission file number 000-50056
MARTIN MIDSTREAM PARTNERS L.P.
(Exact name of registrant as specified in its charter)
State or other jurisdiction of incorporation or organization
Delaware
05-0527861
(I.R.S. Employer Identification No.)
4200 Stone Road Kilgore, Texas 75662
(Address of principal executive offices) (Zip Code)
903-983-6200
(Registrant’s telephone number, including area code)
_______________________
Securities Registered Pursuant to Section 12(b) of the Act:
Title of each class
Common Units representing limited partnership interests
Name of each exchange on which registered
NASDAQ Global Select Market
Securities Registered Pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements the past 90 days.
Yes
No
Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such
shorter period that the Registrant was required to submit and post such files).
Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will
not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of
this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller
reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if a smaller
reporting company)
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
No
As of June 30, 2012, 23,116,776 common units were outstanding. The aggregate market value of the common units
held by non-affiliates of the registrant as of such date approximated $540,979,685 based on the closing sale price on that
date. There were 26,624,526 of the registrant’s common units outstanding as of March 4, 2013.
DOCUMENTS INCORPORATED BY REFERENCE: None.
Page
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TABLE OF CONTENTS
PART I
Business
Item 1.
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Item 3.
Item 4. Mine Safety Disclosures
Properties
Legal Proceedings
PART II
Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity
Securities
Selected Financial Data
Item 5.
Item 6.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantative and Qualitative Disclosures about Market Risk
Financial Statements and Supplementary Data
Item 8.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
PART IV
Item 15. Exhibits, Financial Statement Schedules
i
Item 1.
Business
PART I
References in this annual report to “we,” “ours,” “us” or like terms when used in a historical context refer to the assets
and operations of Martin Resource Management's business contributed to us in connection with our initial public offering on
November 6, 2002. References in this annual report to “Martin Resource Management” refers to Martin Resource Management
Corporation and its subsidiaries, unless the context otherwise requires. References in this annual report to the Partnership refers
to Martin Midstream Partners L.P. and its subsidiaries, unless the content otherwise requires. You should read the following
discussion of our financial condition and results of operations in conjunction with the consolidated financial statements and the
notes thereto included elsewhere in this annual report. For more detailed information regarding the basis for presentation for
the following information, you should read the notes to the consolidated financial statements included elsewhere in this annual
report.
Forward-Looking Statements
This annual report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Statements included
in this annual report that are not historical facts (including any statements concerning plans and objectives of management for
future operations or economic performance, or assumptions or forecasts related thereto), are forward-looking statements. These
statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,”
“expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain
projections of results of operations or of financial condition or state other “forward-looking” information. We and our
representatives may from time to time make other oral or written statements that are also forward-looking statements.
These forward-looking statements are made based upon management's current plans, expectations, estimates,
assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We
caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed
or implied in the forward-looking statements.
Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from
those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed
above in “Item 1A. Risk Factors - Risks Related to our Business”.
Overview
We are a publicly traded limited partnership with a diverse set of operations focused primarily in the U.S. ("U.S.")
Gulf Coast region. Our 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;
•
Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution; and
• Marine transportation services for petroleum products and by-products.
The petroleum products and by-products we 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
1
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, 2012, Martin Resource Management owned
19.2% of our total outstanding common limited partner units. Furthermore, it owns and controls our general partner, which
owns a 2.0% general partner interest in us and all of our incentive distribution rights. Martin Resource Management directs our
business operation through its ownership 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 conduction of our business and
operating our assets.
The historical operation of our business segments by Martin Resource Management provides us with several decades
of experience and a demonstrated track record of customer service across our operations. Our current lines of business have
been developed and systematically integrated over this period of more than 60 years, including natural gas services (1950s);
sulfur (1960s); marine transportation (late 1980s); and terminalling and storage (early 1990s). This development of a
diversified and integrated set of assets and operations has produced a complementary portfolio of midstream services that
facilitates the maintenance of long-term customer relationships and encourages the development of new customer relationships.
Primary Business Segments
Our primary business segments can be generally described as follows:
•
Terminalling and Storage. We own or operate 31 marine shore based terminal facilities and 16 specialty terminal
facilities located in the U.S. Gulf Coast region that provide storage, refining, blending, packaging, and handling
services for producers and suppliers of petroleum products and by-products, lubricants and other liquids, including
the refining, blending and packaging of various grades and quantities of naphthenic lubricants and related products.
Our facilities and resources provide us with the ability to handle various products that require specialized treatment,
such as molten sulfur and asphalt. We also provide land rental to oil and gas companies along with storage and
handling services for lubricants and fuel oil. We provide these terminalling and storage services on a fee basis
primarily under long-term contracts. A significant portion of the contracts in this segment provide for minimum fee
arrangements that are not based on the volumes handled.
• Natural Gas Services. We distribute natural gas liquids (“NGLs"). We purchase NGLs primarily from refineries
and natural gas processors. We store NGLs in our supply and storage facilities for wholesale deliveries to propane
retailers, refineries and industrial NGL users in Texas and the Southeastern U.S. We own an NGL pipeline which
spans approximately 200 miles running from Kilgore, Texas to Beaumont, Texas. We own three NGL supply and
storage facilities with an aggregate above-ground storage capacity of approximately 3,000 barrels and we lease
approximately 2.7 million barrels of underground storage capacity for NGLs. Additionally, through our ownership
interests in Redbird Gas Storage LLC (“Redbird”), we are partners in a joint venture, Cardinal Gas Storage Partners
LLC (“Cardinal”), which is focused on the development, construction, operation and management of natural gas
storage facilities across northern Louisiana and Mississippi. We previously engaged in the natural gas processing
business through our subsidiaries, Prism Gas Systems I, L.P. (“Prism Gas”) and Woodlawn Pipeline Co., Inc.
(“Woodlawn”), and the Darco Gathering System, the Harrison Gathering System and the East Harrison Pipeline
System. The East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas,
which included Woodlawn, the Darco Gathering System, the Harrison Gathering System and the East Harrison
Pipeline System (the “Prism Assets”), and certain other natural gas gathering and processing assets owned by us
were sold on July 31, 2012 to a subsidiary of CenterPoint Energy Inc. (“CenterPoint”) for net cash proceeds of
$273.3 million.
•
Sulfur Services. We have developed an integrated system of transportation assets and facilities relating to sulfur
services over the last 50 years. We process and distribute sulfur predominantly produced by oil refineries primarily
located in the U.S. Gulf Coast region. We handle molten sulfur on contracts that are tied to sulfur indices and tend
to provide stable margins. We process molten sulfur into prilled or pelletized sulfur on take-or-pay fee contracts at
our facilities in Port of Stockton, California and Beaumont, Texas. The sulfur we process and handle is primarily
used in the production of fertilizers and industrial chemicals. We own and operate six sulfur-based fertilizer
production plants and one emulsified sulfur blending plant that manufacture primarily sulfur-based fertilizer
products for wholesale distributors and industrial users. These plants are located in Illinois, Texas and Utah.
2
Demand for our sulfur products exists in both the domestic and foreign markets, and we believe our asset base
provides us with additional opportunities to handle increases in U.S. supply and access to foreign demand.
• Marine Transportation. We own a fleet of 54 inland marine tank barges, 29 inland push boats and four offshore
tug barge units that transport petroleum products and by-products largely in the U.S. Gulf Coast region. We provide
these transportation services on a fee basis primarily under annual contracts and many of our customers have long
standing contractual relationships with us. Over the past several years, we have focused on modernizing our fleet.
As a result, the average age of our vessels has decreased from 33 years in 2006 to 23 years as of December 31,
2012. This modernized asset base is attractive both to our existing customers as well as potential new customers. In
addition, our fleet contains several vessels that reflect our focus on specialty products. For example, we are one of a
very limited number of companies that can transport molten sulfur.
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 growth capital expenditures
primarily in our Terminalling and Storage and Natural Gas Services segments.
During the past year, we continued to experience positive market dynamics in our Terminalling and Storage segment.
This is in large part to the rapid development of the Eagle Ford shale basin in South Texas and its need for off-take
infrastructure. In addition, we purchased certain specialty lubricant product blending and packaging assets from Cross Oil
Refining & Marketing, Inc. ("Cross"), a wholly-owned subsidiary of Martin Resource Management, as further integration into
our existing assets.
We also purchased all remaining Class A interests in Redbird. Redbird was formerly a joint venture between us and
Martin Resource Management formed in 2011 to invest in Cardinal, a joint venture between Martin Resource Management and
Energy Capital Partners ("ECP") that is focused on the development, construction, operation and management of natural gas
storage facilities in northern Louisiana and Mississippi. As a result of this transaction, Redbird is now a wholly-owned
subsidiary of us. We believe natural gas storage assets are ideally suited for the master limited partnership structure.
Recent Acquisitions
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 Quintana Energy Partners, L.P. for $103.4 million in cash, 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. 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.
Acquisition of Redbird Interests. On October 2, 2012, we acquired the remaining Class A interests in Redbird for
$150.0 million in cash from Martin Underground Storage, Inc., a subsidiary of Martin Resource Management. Redbird was
formed by us and Martin Resource Management in 2011 to invest in Cardinal. Cardinal is a joint venture between Redbird and
ECP that is focused on the development, construction, operation and management of natural gas storage facilities across
northern Louisiana and Mississippi.
Acquisition of Specialty Lubricant Product Blending and Packaging Assets. On October 2, 2012, we acquired from
Cross certain specialty lubricant product blending and packaging assets ("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.
3
Other Developments
Litigation Settlement. On October 2, 2012, we announced that the ongoing litigation and disputes since May 2008
involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The
settlement, among other things, provided for a resolution of all the lawsuits and disputes. In connection with the settlement,
Martin Resource Management transferred 1,500,000 of our common units to KCM, LLC. Martin Resource Management
continues to own 5,093,267 of our common units.
Amendment No. 2 to Omnibus Agreement. In connection with the purchase of the Blending and Packaging Assets, on
October 2, 2012, we entered into Amendment No. 2 to our Omnibus Agreement (the “Amendment”) with Martin Resource
Management, Martin Midstream GP LLC (the "General Partner"), and Martin Operating Partnership L.P. (the "Operating
Partnership"). The Amendment allows us to provide certain products and services to Martin Resource Management under the
Omnibus Agreement by amending the definition of the term “Business” to reflect the operation of the blending and packaging
assets acquired by the Partnership pursuant to the purchase agreement.
Amendment No. 3 to the Second Amendment and Restated Agreement of Limited Partnership. In conjunction with the
Redbird purchase agreement, on October 2, 2012, the 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 the 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.
Disposition of Natural Gas Gathering Assets. On June 18, 2012, we and a subsidiary of CenterPoint, entered into a
definitive agreement under which CenterPoint would acquire our East Texas and Northwest Louisiana natural gas gathering and
processing assets owned by Prism Gas, which include Woodlawn, the Darco Gathering System, the Harrison Gathering System,
and the East Harrison Pipeline System, and other natural gas gathering and processing assets also owned by us, for cash in a
transaction valued at approximately $275.0 million excluding any transaction costs and purchase price adjustments. The asset
sale included our 50% operating interest in Waskom Gas Processing Company (“Waskom”). A subsidiary of CenterPoint
owned the other 50% percent interest. On July 31, 2012, we completed the sale of our East Texas and Northwest Louisiana
natural gas gathering and processing assets for net cash proceeds of $273.3 million. Additionally, on September 18, 2012, we
completed the sale of our interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline
Energy, LLC (“PIPE”) to a private investor group for $1.5 million in cash (the assets described above, collectively, are herein
referred to as the "Prism Assets"). Prism Gas Systems I, L.P. and all of its subsidiaries were liquidated and dissolved prior to
December 31, 2012.
Public 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.
Debt Financing Activities. On May 24, 2012, we redeemed $25.0 million of the Senior 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 May 10, 2012, we increased the maximum amount of borrowings and letters of credit
available under our revolving credit facility from $375.0 million to $400.0 million. See subsequent events section below for
discussion surrounding our February 2013 issuance of senior unsecured notes.
For a more detailed discussion regarding our credit facility, see “Description of Our Long-Term Debt—Credit Facility”
within this Item.
4
Subsequent Events
NGL Marine Equipment Purchase. On February 28, 2013, we purchased from affiliates of Florida Marine
Transporters, Inc. six liquefied petroleum gas pressure barges and two commercial push boats for approximately $50.8 million.
The purchase was funded with borrowings under the Partnership's revolving credit facility.
Senior Notes Issuance. On February 11, 2013, we completed a private placement of $250.0 million in aggregate
principal amount of 7.25% 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 the Partnership's revolving credit facility.
Quarterly Distribution. On January 24, 2013, we declared a quarterly cash distribution of $0.77 per common unit for
the fourth quarter of 2012, or $3.08 per common unit on an annualized basis, which was paid on February 14, 2013 to
unitholders of record as of February 7, 2013.
Common Unit Grants. On January 2, 2013, we issued 57,500 restricted common units under our long-term incentive
plan to the executive officers of the General Partner and certain Martin Resource Management employees who provide services
to us. These restricted units vest 100% on January 1, 2016.
Our Business Strategy
The key components of our business strategy are:
• Pursue Organic Growth Projects. We continually evaluate economically attractive organic expansion opportunities in
new or existing areas of operation that will allow us to leverage our existing market position and increase the
distributable cash flow from our existing assets through improved utilization and efficiency.
• Pursue Internal Organic Growth by Attracting New Customers and Expanding Services Provided to Existing
Customers. We seek to identify and pursue opportunities to expand our customer base across all of our business
segments. We generally begin a relationship with a customer by transporting, storing or marketing a limited range of
products and services. We believe expanding our customer base and our service and product offerings to existing
customers is an efficient and cost effective method of achieving organic growth in revenues and cash flow. We believe
significant opportunities exist to expand our customer base and provide additional services and products to existing
customers.
• Pursue Strategic Acquisitions. We continually monitor the marketplace to identify and pursue accretive acquisitions
that expand the services and products we offer or that expand our geographic presence. After acquiring other
businesses, we will attempt to utilize our industry knowledge, network of customers and suppliers and strategic asset
base to operate the acquired businesses more efficiently and competitively, thereby increasing revenues and cash flow.
We believe that our diversified base of operations provides multiple platforms for strategic growth through
acquisitions.
• Pursue Strategic Commercial Alliances. Many of our larger customers, which include major integrated energy
companies, have established strategic alliances with midstream service providers such as us to address logistical and
transportation problems or achieve operational synergies. We intend to pursue strategic commercial alliances with such
customers in the future.
Competitive Strengths
We believe we are well positioned to execute our business strategy because of the following competitive strengths:
Fee Based Contracts. We generate a majority of our cash flow from fee-based contracts with our customers. In
addition, a significant portion of these fee-based contracts consist of reservation charges or minimum fee arrangements, which
reduce the volatility of a portion of our cash flows due to volume fluctuations.
Asset Base and Integrated Distribution Network. We operate a diversified asset base that enables us to offer our
customers an integrated distribution network consisting of transportation, terminalling and storage and midstream logistical
5
services while minimizing our dependence on the availability and pricing of services provided by third parties. Our integrated
distribution network enables us to provide customers with a complementary portfolio of transportation, terminalling,
distribution and other midstream services for petroleum products and by-products.
Strategically Located Assets. We are one of the largest operators of marine service shore-based terminals in the U.S.
Gulf Coast region providing broad geographic coverage and distribution capability of our products and services to our
customers. Our natural gas storage and natural gas liquids distribution and storage assets are focused in areas that continue to
experience high levels of drilling activity. In addition, our natural gas storage assets are located in areas highly desirable for our
customers. Finally, many of our sulfur services assets are strategically located to source sulfur from the largest refinery sources
in the U.S.
Specialized Transportation Equipment and Storage Facilities. We have the assets and expertise to handle and transport
certain petroleum products and by-products with unique requirements for transportation and storage. For example, we own
facilities and resources to transport a variety of specialty products, including ammonia, molten sulfur and asphalt. Some of
these specialty products require treatment across a wide range of temperatures ranging between approximately -30 to +400
degrees Fahrenheit to remain in liquid form, which our facilities are designed to accommodate. We believe these capabilities
help us enhance relationships with our customers by offering them services to handle their unique product requirements.
Strong Industry Reputation and Established Relationships with Suppliers and Customers. We believe we have
established a reputation in our industry as a reliable and cost-effective supplier of services to our customers and have a track
record of safe, efficient operation of our facilities. Our management has also established long-term relationships with many of
our suppliers and customers. We believe we benefit from our management's reputation and track record and from these long-
term relationships.
Financial Strength and Flexibility. We have historically financed our operations with a combination of debt and equity
while maintaining a modest leverage profile, even in challenging business environments. Since our initial public offering, we
have accessed the public equity markets eight times for approximately $539.3 million in total net proceeds, including capital
contributions from our general partner. As of March 4, 2013, we have accessed the public debt markets two times for
approximately $442.3 million in total net proceeds. We have also occasionally issued common units to Martin Resource
Management in exchange for cash or assets.
Experienced Management Team and Operational Expertise. Members of our executive management team and the
heads of our principal business lines have, on average, more than 30 years of experience in the industries in which we operate.
Our management team has a successful track record of creating internal growth and completing acquisitions. We believe our
management team's experience and familiarity with our industry and businesses are important assets that assist us in
implementing our business strategies.
Terminalling and Storage Segment
Industry Overview. The U.S. petroleum distribution system moves petroleum products and by-products from oil
refinery and natural gas processing facilities to end users. This distribution system is comprised of a network of terminals,
storage facilities, pipelines, tankers, barges, railcars and trucks. Terminals play a key role in moving these products throughout
the distribution system by providing storage, blending and other ancillary services.
In the 1990s, the petroleum industry entered a period of consolidation. Refiners and marketers developed large-scale,
cost-efficient operations resulting in several refinery acquisitions, combinations, alliances and joint ventures. This consolidation
resulted in major oil companies integrating the various components of their businesses, including terminalling and storage.
However, major integrated oil companies later concentrated their focus and resources on their core competencies of exploration,
production, refining and retail marketing and examined ways to lower their distribution costs. Additionally, the Federal Trade
Commission required some divestitures of terminal assets in markets in which merged companies, alliances and joint ventures
were regarded as having excessive market power. As a result of these factors, oil and gas companies began to increasingly rely
on third parties, such as us, to perform many terminalling and storage services.
Although many large energy and chemical companies own terminalling and storage facilities, these companies also use
third-party terminalling and storage services. Major energy and chemical companies typically have a strong demand for
terminals owned by independent operators when such terminals are strategically located at or near key transportation links, such
as deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage
facilities are inadequate, either because of lack of capacity, the nature of the stored material or specialized handling
requirements.
6
The Gulf Coast region is a major hub for petroleum refining. Approximately 50% of U.S. refining capacity exists in
this region. Growth in the refining and natural gas processing industries has increased the volume of petroleum products and
by-products that are transported within the Gulf Coast region, which consequently has increased the need for terminalling and
storage services.
The marine and offshore oil and gas exploration and production industries use terminal facilities in the Gulf Coast
region as shore bases that provide them logistical support services as well as provide a broad range of products, including fuel
oil, lubricants, chemicals and supplies. The demand for these types of terminals, services and products is driven primarily by
offshore exploration, development and production in the Gulf of Mexico. Offshore activity is greatly influenced by current and
projected prices of oil and natural gas.
Marine Shore Based Terminals. We own or operate 31 marine shore based terminals along the Gulf Coast from
Theodore, Alabama to Corpus Christi, Texas. Of our 31 marine shore based terminals, 12 were acquired on January 31, 2011,
through our acquisition of certain terminalling assets from Martin Resource Management and seven were acquired through the
purchase of Talen's on December 31, 2012. Our terminal assets are located at strategic distribution points for the products we
handle and are in close proximity to our customers.
We are one of the largest operators of marine shore based terminals in the Gulf Coast region. These terminals are used
to distribute and market fuel and lubricants, and the full service terminals also provide shore bases for companies that are
operating in the offshore exploration and production industry. Customers are primarily oil and gas exploration and production
companies and oilfield service companies, such as drilling fluid companies, marine transportation companies and offshore
construction companies. Shore bases typically provide logistical support, including the storing and handling of tubular goods,
loading and unloading bulk materials, providing facilities from which major and independent oil companies can communicate
with and control offshore operations and leasing dockside facilities to companies which provide complementary products and
services such as drilling fluids and cementing services. We generate revenues from our terminals that have shore bases by fees
that we charge our customers under land rental contracts for the use of our terminal facility for these shore bases. These
contracts generally provide us a fixed land rental fee and additional rental fees that are determined based on a percentage of the
sales value of the products and services delivered from the shore base. In addition, Martin Resource Management, through
contractual arrangements, pays us for terminalling and storage of fuel oil and lubricants at these terminal facilities.
Our 31 marine shore based terminals are divided into two classes of terminals: (i) full service terminals and (ii) fuel
and lubricant terminals.
Full Service Terminals. We own or operate 12 full service terminals. These terminal facilities provide logistical
support services and storage and handling services for fuel oil and lubricants. The significant difference between our full
service terminals and our fuel and lubricant terminals is that our full service terminals generate additional revenues by
providing shore bases to support our customer’s operating activities related to the offshore exploration and production industry.
One typical use for our shore bases is for drilling fluids manufacturers to manufacture and sell drilling fluids to the offshore
drilling industry. Offshore drilling companies may also set up service facilities at these terminals to support their offshore
operations. Customers of our full service terminals are primarily oil and gas exploration and production companies, oilfield
service companies such as drilling fluids companies, marine transportation companies and offshore construction companies.
The following is a summary description of our 12 full service terminals:
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Terminal
Location
Amelia-2 (3)(4)
Amelia, Louisiana
Aggregate Capacity
13,000 Bbls.
Cameron East (2)
Cameron, Louisiana
Dock 193 (7)(12)
Geuydan, Louisiana
Fourchon-15 (3)(6)
Fourchon, Louisiana
32,500 Bbls.
14,700 Bbls.
16,500 Bbls.
Freshwater City (7)(8)(9)
Freshwater City, Louisiana
7,400 Bbls.
Galveston-T (7)
Galveston Texas
Harbor Island (1)
Harbor Island, Texas
10,400 Bbls.
31,400 Bbls.
Intracoastal City-2 (3)(5)
Intracoastal City, Louisiana
12,500 Bbls.
Pascagoula
Pascagoula, Mississippi
Pelican Island
Galveston, Texas
Theodore
Theodore, Alabama
Venice (3)(10)(11)
Venice, Louisiana
11,000 Bbls.
88,600 Bbls.
20,000 Bbls.
25,000 Bbls.
(1) A portion of this terminal is located on land owned by a third party and leased under a lease that expires in January 2015.
(2)
This terminal is located on land owned by third parties and leased under a lease that expires in March 2017 and can be
extended by us through February 2022.
These terminals were acquired from Martin Resource Management on January 31, 2011.
This terminal is located on land owned by a third party and leased under a lease that expires in August 2018 and can be
extended by us through August 2023.
This terminal is located on land owned by a third party and leased under a lease that expires in December 2015 and can
be extended by us through December 2025.
This terminal is located on land owned by a third party and leased under a lease that expires in February 2017.
These terminals were acquired from the purchase of Talen's on December 31, 2012.
This terminal is located on land owned by a third party and leased under a lease that expires in March 2014 and can be
extended by us through March 2017.
This terminal has a warehousing agreement with a third party and under a lease that expires in March 2014 and can be
extended by us through March 2017.
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10) This terminal is located on land owned by third parties and leased under a lease that expires in September 2017 and can
be extended by us through December 2027
(11) This terminal was converted from a fuel and lube terminal to a full service terminal in 2012.
(12) A Portion of this terminal is located on land owned by a third party and leased under a lease that expires in May 2014
and can be extended by us through May 2016.
Fuel and Lubricant Terminals. We own or operate 19 lubricant and fuel oil terminals located in the Gulf Coast region
that provide storage and handling services for lubricants and fuel oil.
The following is a summary description of our fuel and lubricant terminals:
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Terminal
Berwick (1)
Location
Berwick, Louisiana
Aggregate Capacity
25,000 Bbls.
Cameron West (5)(19)
Cameron, Louisiana
Cameron-7 (10)(20)(19)
Cameron, Louisiana
Cameron-8 (10)(6)(19)(23)
Cameron, Louisiana
Dulac (10)(12)
Dulac, Louisiana
Fourchon (9)
Fourchon, Louisiana
Fourchon 16 (10)(17)
Fourchon, Louisiana
Fourchon 17(10)(13)
Fourchon, Louisiana
Fourchon-T (4)(11)
Fourchon, Louisiana
Freeport (19)
Freeport, Texas
18,400 Bbls.
15,500 Bbls.
32,000 Bbls.
16,300 Bbls.
80,500 Bbls.
11,900 Bbls.
40,900 Bbls.
39,100 Bbls.
8,500 Bbls.
Intracoastal City (7)(8)(23)
Intracoastal City, Louisiana
32,400 Bbls.
Lake Charles-T (4)(18)
Lake Charles, Louisiana
13,500 Bbls.
Morgan City 33 (10)(16)(23)
Morgan City, Louisiana
53,500 Bbls.
Morgan City DWC 31(10)(15) Morgan City, Louisiana
7,100 Bbls.
Port Arthur (4)(21)
Port Arthur, Texas
Port O'Connor (2)(19)
Port O'Connor, Texas
River Ridge (10)(14)
River Ridge, Louisiana
Sabine Pass (3)(19)
Sabine Pass, Texas
Texas Terminal (4)(22)
Houston, Texas
0 Bbls.
7,000 Bbls.
10,000 Bbls.
17,500 Bbls.
0 Bbls.
(1)
(2)
(3)
(4)
(5)
(6)
This terminal is located on land owned by third parties and leased under a lease that expires in September 2017.
This terminal is located on land owned by a third party and leased under a lease that expires in March 2014.
This terminal is located on land owned by a third party and leased under a lease that expires in September 2016 and can
be extended by us through September 2036.
These terminals were acquired from the purchase of Talen's on December 31, 2012.
This terminal is located on land owned by a third party and leased under a lease that expires in February 2013. We are
currently negotiating to extend the lease until February 2033.
This terminal is located on land owned by a third party and leased under a lease that expires in July 2016 and can be
extended by us through July 2036.
(7) A portion of this terminal is located on land owned by a third party at which we throughput fuel oil pursuant to an
agreement that expires in April 2014.
(8) A portion of this terminal is located on land owned by third parties and leased under a lease that expires in April 2014.
This terminal is located on land owned by a third party at which we throughput lubricants and fuel oil pursuant to an
(9)
agreement that expires in January 2017.
(10) These terminals were acquired from Martin Resource Management on January 31, 2011.
9
(11) This terminal is located on land owned by a third party at which we throughput lubricants and fuel oil pursuant to an
agreement that expires in October 2018 and can be extended by us through October 2038.
(12) This terminal is located on land owned by third parties and leased under a lease that expires in December 2021 and can
be extended by us through December 2041.
(13) This terminal is located on land owned by third parties and leased under a lease that expires in December 2013 and can
be extended by us through December 2023.
(14) This terminal is located on land owned by third parties and leased under a lease that expires in April 2019.
(15) This terminal is located on land owned by third parties and leased under a lease that expires in December 2014 and can
be extended by us through December 2034. In addition, there is an office sublease that expires December 2014 and can
be extended through December 2019.
(16) This terminal is located on land owned by third parties and leased under a lease that expires in May 2014 and can be
extended by us through May 2019.
(17) This terminal is located on land owned by third parties and leased under multiple leases that expires in July 2017, and
July 2016, and March 2017. These leases can be extended by us through March 2022, and July 2026, respectively.
(18) This terminal is located on land owned by third parties and leased under a lease that expires in April 2023.
(19) These terminals were converted from full services terminals to fuel and lube terminals during 2012.
(20) This terminal is located on land owned by a third party and leased under a lease that expires in July 2017 and can be
extended by us through July 2027.
(21) This terminal is located on land owned by third parties and leased under a lease that expires in November 2015 and can
be extended by us through November 2025.
(22) This terminal is located on land owned by third parties and leased under a lease that expires 55 months after receipt of
the U.S. Army Corps of Engineers permit for dredging.
(23) These terminals are currently in caretaker status.
Specialty Petroleum Terminals. We own or operate 16 terminal facilities providing storage and handling services for
some or all of the following: anhydrous ammonia, asphalt, sulfur, sulfuric acid, fuel oil, crude oil and other petroleum products
and by-products. Of our 14 terminals, one was acquired on January 31, 2011, through our acquisition of certain terminalling
assets from Martin Resource Management and two were acquired through our acquisition of Talen's on December 31,
2012. Our specialty terminals have an aggregate storage capacity of approximately 2.9 million barrels. Each of these terminals
has storage capacity for petroleum products and by-products and assets to handle products transported by vessel, barge and/or
truck. The location and composition of our terminals are structured to complement our other businesses and reflect our strategy
to provide a broad range of integrated services in the handling and transportation of petroleum products and by-products. We
primarily developed our terminalling and storage assets by acquiring existing terminalling and storage facilities and then
customizing and upgrading these facilities as needed to integrate the facilities into our petroleum product and by-product
transportation network and to more effectively service customers. We have also identified strategic locations near rail,
waterways and pipelines and have developed our own terminal facilities. We expect to continue to acquire facilities, streamline
their operations and customize and upgrade them as part of our growth strategy. We also anticipate continuing to develop our
own facilities when strategically desirable locations are identified. We also continually evaluate opportunities to add services
and increase access to our terminals to attract more customers and create additional revenues.
Our Tampa terminal is located on approximately 10 acres of land owned by the Tampa Port Authority that was leased
to us under a 10-year lease that commenced on December 16, 2006 with two five-year options. Our Stanolind terminal is
located on approximately 11 acres of land owned by us located on the Neches River in Beaumont, Texas. Our Neches terminal
is a deep water marine terminal located near Beaumont, Texas, on approximately 50 acres of land owned by us. Our Corpus
Christi, Texas Barge terminal is located on approximately 25 acres of land owned by us and has access to the waterfront via
marine docks owned by the Port of Corpus Christi. Our Corpus Christi, Texas Crude terminal is located on 10 acres leased
from the Port of Corpus Christi under terms of a five-year lease commencing on May 18, 2011 with five five-year options.
At our Tampa, Neches, Stanolind and Corpus Christi terminals, our customers are primarily large oil refining and
natural gas processing companies. We charge either a fixed monthly fee or a throughput fee for the use of our facilities, based
on the capacity of the applicable tank. We conduct a substantial portion of our terminalling and storage operations under long-
term contracts, which enhances the stability and predictability of our operations and cash flow. We attempt to balance our short-
term and long-term terminalling contracts in order to allow us to maintain a consistent level of cash flow while maintaining
flexibility to earn higher storage revenues when demand for storage space increases. In addition, a significant portion of the
contracts for our specialty terminals provide for minimum fee arrangements that are not based on the volume handled.
In Channelview, Texas, we operate a terminal used for lubricant blending, storage, packaging and distribution. This
terminal is used as our central hub for bulk lubricant distribution where we receive, package and ship our lubricants to our
terminals or directly to customers.
10
In Smackover, Arkansas, we also own a refinery and terminal where we process crude oil into finished products that
include naphthenic lubricants, distillates, asphalt and other intermediates. This process is dedicated to an affiliate of Martin
Resource Management through a long-term tolling agreement based on throughput rates and a monthly reservation fee.
In Smackover, Arkansas, we own and operate a terminal used for lubricant blending, storage, packaging and distribution.
This terminal is used as our central hub for branded and private label package lubricants where we receive, package and ship
heavy-duty, passenger car, and industrial lubricants to a network of retailers and distributors. A secondary blending and packaging
operation is owned in Kansas City, Kansas, that allows us to serve markets that we cannot out of our Smackover facility.
In Houston, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource Management
through a terminalling service agreement based on throughput rates.
In Port Neches, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource
Management through a terminalling service agreement based upon throughput rates.
In Omaha, Nebraska, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource
Management through a terminalling service agreement based on throughput rates.
In Beaumont, Texas we own Spindletop Terminal where we receive natural gasoline via pipeline and then ship the
product to our customers via other pipelines to which the facility is connected. Our fees for the use of this facility are based on
the number of barrels shipped from the terminal.
In Broussard, Louisiana, we own a lubricant terminal on leased land whose use is dedicated to an affiliate of Martin
Resource Management through a terminalling service agreement based on throughput rates.
In Jennings, Louisiana, we own a lubricant terminal whose use is dedicated to an affiliate of Martin Resource
Management through a terminalling service agreement based on throughput rates.
In Lake Charles, Louisiana, we own a lubricant terminal on leased land whose use is dedicated to an affiliate of Martin
Resource Management through a terminalling service agreement based on throughput rates.
The following is a summary description of our shore-based specialty terminals:
Terminal
Tampa (1)
Location
Tampa, Florida
Aggregate Capacity
718,000 Bbls.
Products
Description
Asphalt, sulfur and fuel oil Marine terminal, loading/
Stanolind
Neches
Beaumont,
Texas
Beaumont,
Texas
555,000 Bbls.
Asphalt, crude oil, sulfur,
sulfuric acid and fuel oil
500,400 Bbls.
Molten sulfur, ammonia,
asphalt, fuel oil, crude oil
and sulfur-based fertilizer
Corpus Christi
Barge terminal
Corpus Christi,
Texas
150,000 Bbls.
Fuel oil and diesel
Corpus Christi
Crude terminal
(2)
Corpus Christi,
Texas
600,000 Bbls.
Crude oil
unloading for vessels, barges
railcars and trucks
Marine terminal, marine dock
for loading/unloading of
vessels, barges, railcars and
trucks
Marine terminal, loading/
unloading for vessels, barges,
railcars and trucks
Marine terminal, loading/
unloading barges and vessels
and unloading trucks
Marine terminal, loading/
unloading barges and vessels,
trucks, and pipeline access
(1)
This terminal is located on land owned by the Tampa Port Authority that was leased to us under a 10-year lease that
expires in December 2016 with two five-year extension options.
(2) Our Corpus Christi, Texas Crude terminal is located on 10 acres leased from the Port of Corpus Christi under terms of a
five-year lease commencing on May 18, 2011 with five five-year options.
The following is a summary description of our non shore-based specialty terminals:
11
Terminal
Channelview
Location
Aggregate Capacity
Products
Description
Houston, Texas 44,000 sq.
Lubricants
Lubricants blending and
storage
ft. Warehouse 35,000
Bbls
7,500 Bbls per day
Smackover
Refinery
Smackover,
Arkansas
Martin Lubricants Smackover,
Arkansas
Martin Lubricants Kansas City,
Kansas
Naphthenic lubricants,
Distillates, Asphalt
Crude refining facility
235,000 sq. ft.
Warehouse 5.3 million
gallons bulk storage
Gard, SynGard, and
Xtreme brands, and private
label packaged lubricants
65,000 sq. ft.
Warehouse 1.5 million
gallons bulk storage
Gard, SynGard, and
Xtreme brands, and private
label packaged lubricants
Lubricants packaging facility
Lubricants packaging facility
South Houston
Asphalt
Houston, Texas 71,000 Bbls
Asphalt
Asphalt Processing and storage
Port Neches
Asphalt
Port Neches,
Texas
Omaha Asphalt
Spindletop
Broussard Bulk
Facility (4)(5)
Omaha,
Nebraska
Beaumont,
Texas
Broussard,
Louisiana
Jennings Bulk
Plant (5)
Jennings,
Louisiana
Lake Charles (3)
Lake Charles,
Louisiana
31,300 Bbls
Asphalt
Asphalt Processing and storage
114,200 Bbls
Asphalt
Asphalt Processing and storage
90,000 Bbls
Natural Gasoline
Pipeline receipts and shipments
43,000 sq. ft.
Warehouse
9,200 Bbls.
41,000 sq. ft. building
space
4,000 Bbls.
18,000 sq.
ft.Warehouse 6,800
Bbls
Lubricants, Fuel
Lubricants and Fuel storage
Lubricants, Fuel
Lubricants and Fuel storage
Lubricants
Lubricants storage
(3)
(4)
(5)
This terminal is located on land owned by third parties and leased under a lease that expires in January 2016 and can be
extended by us through January 2021. This terminal was acquired from Martin Resource Management on January 31,
2011.
This terminal is located on land owned by third parties and leased under a lease that expires in November 2015 and can
be extended by us through November 2030.
These terminals were acquired from the purchase of Talen's on December 31, 2012.
Competition. We compete with independent terminal operators and major energy and chemical companies that own
their own terminalling and storage facilities. We believe many customers prefer to contract with independent terminal operators
rather than terminal operators owned by integrated energy and chemical companies that may have refining or marketing
interests that compete with the customers.
Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and
price. A favorably-located terminal has access to various cost effective transportation modes, both to and from the terminal,
such as waterways, railroads, roadways and pipelines. Terminal versatility depends upon the operator’s ability to handle diverse
products, some of which have complex or specialized handling and storage requirements. The service function of a terminal
includes, among other things, the safe storage of product at specified temperature, moisture and other conditions and receiving
and delivering product to and from the terminal. All of these services must be in compliance with applicable environmental and
other regulations.
We believe we successfully compete for terminal customers because of the strategic location of our terminals along the
Gulf Coast, our integrated transportation services, our reputation, the prices we charge for our services and the quality and
versatility of our services. Additionally, while some companies have significantly more terminalling and storage capacity than
us, not all terminalling and storage facilities located in the markets we serve are equipped to properly handle specialty products
12
such as asphalt, sulfur, anhydrous ammonia and sulfuric acid. As a result, our facilities typically command higher terminal fees
when compared to fees charged for terminalling and storage of other petroleum products.
The principal competitive factors affecting our terminals, which provide fuel and lubricants distribution and marketing,
as well as shore bases at certain terminals, are the locations of the facilities, availability of competing logistical support services
and the experience of personnel and dependability of service. The distribution and marketing of our lubricant products is brand
sensitive and we encounter brand loyalty competition. Shore base rental contracts are generally long-term contracts and provide
more protection from competition. Our primary competitors for both lubricants and shore bases include several independent
operations as well as major companies that maintain their own similarly equipped marine terminals, shore bases and fuel and
lubricant supply sources.
Natural Gas Services Segment
NGL Industry Overview. NGLs are produced through natural gas processing. They are also a by-product of crude oil
refining. NGLs include ethane, propane, normal butane, iso butane and natural gasoline.
Ethane is almost entirely used as a petrochemical feedstock in the production of ethylene and propylene. Propane is
used as a petrochemical feedstock in the production of ethylene and propylene, as a fuel for heating, for industrial applications,
as motor fuel and as a refrigerant. Normal butane is used as a petrochemical feedstock, as a blend stock for motor gasoline and
as a component in aerosol propellants. Normal butane can also be made into iso butane through isomerization. Iso butane is
used in the production of motor gasoline, alkylation or MTBE and as a component in aerosol propellants. Natural gasoline is
used as a component of motor gasoline, as a petrochemical feedstock and as a diluent.
NGL Facilities. We purchase NGLs primarily from major domestic oil refiners and natural gas processors. We
transport NGLs using Martin Resource Management’s land transportation fleet or by contracting with common carriers, owner-
operators and railroad tank cars. We typically enter into annual contracts with independent retail propane distributors to deliver
their estimated annual volume requirements based on prevailing market prices. We believe dependable delivery is very
important to these customers and in some cases may be more important than price. We ensure adequate supply of NGLs
through:
•
•
•
storage of NGLs purchased in off-peak months;
efficient use of the transportation fleet of vehicles owned by Martin Resource Management; and
product management expertise to obtain supplies when needed.
The following is a summary description of our owned and leased NGL facilities:
NGL Facility
Wholesale terminals
Retail terminals
__________
Location
Capacity
Description
Arcadia, Louisiana (1)
Breaux Bridge, Louisiana (2)
Hattiesburg, Mississippi (2)
Mt. Belvieu, Texas (2)
Kilgore, Texas
Longview, Texas
Henderson, Texas
2,200,000 barrels
415,000 barrels
60,000 barrels
65,000 barrels
90,000 gallons
30,000 gallons
12,000 gallons
Underground storage
Underground storage
Underground storage
Underground storage
Retail propane distribution
Retail propane distribution
Retail propane distribution
(1) We lease our underground storage at Arcadia, Louisiana, from Martin Resource Management under a three-year product
storage agreement, which is renewable on a yearly basis thereafter subject to a re-determination of the lease rate for each
subsequent year.
(2) We lease our underground storage at Breaux Bridge, Louisiana, Hattiesburg, Mississippi, and Mont Belvieu, Texas, from
third parties under one-year lease agreements.
Our NGL customers that utilize these assets consist of retail propane distributors, industrial processors and refiners.
For the year ended December 31, 2012, we sold approximately 87% of our NGL volume to refiners and industrial processors
13
and approximately 13% of our NGL volume to independent retail propane distributors located in Texas and the southeastern
U.S.
NGL Competition. We compete with large integrated NGL producers and marketers, as well as small local
independent marketers. NGLs compete primarily with natural gas, electricity and fuel oil as an energy source, principally on the
basis of price, availability and portability.
NGL Seasonality. The level of NGL supply and demand is subject to changes in domestic production, weather,
inventory levels and other factors. While production is not seasonal, residential, refinery, and wholesale demand is highly
seasonal. This imbalance causes increases in inventories during summer months when consumption is low and decreases in
inventories during winter months when consumption is high. If inventories are low at the start of the winter, higher prices are
more likely to occur during the winter. Additionally, abnormally cold weather can put extra upward pressure on prices during
the winter because there are less readily available sources of additional supply except for imports, which are less accessible and
may take several weeks to arrive. General economic conditions and inventory levels have a greater impact on industrial and
refinery use of NGLs than the weather.
We generally maintain consistent margins in our natural gas services business because we attempt to pass increases
and decreases in the cost of NGLs directly to our customers. We generally try to coordinate our sales and purchases of NGLs
based on the same daily price index of NGLs in order to decrease the impact of NGL price volatility on our profitability.
Redbird Gas Storage
Through our ownership interests in Redbird, we formed Cardinal, a joint venture with ECP, which is focused on the
development, construction, operation and management of natural gas storage facilities across northern Louisiana and
Mississippi. At December 31, 2012, we owned an unconsolidated 41.28% interest in Cardinal. Through Redbird, we have the
ability to invest in gas storage development projects at the Cardinal level. The Cardinal facilities are discussed below as
follows:
Arcadia Gas Storage, LLC ("Arcadia"), located in Bienville Parish, Louisiana, is in service with 7.85 billion cubic feet
("bcf") of working storage capacity, of which 100% is contracted under firm storage service agreements. As of December 31,
2012, the weighted average remaining term of our existing portfolio of third party firm storage contracts was approximately 2.7
years. Additional capacity of 6.5 bcf is under development and is expected to be in service in the third quarter of 2013.
Monroe Gas Storage Company, LLC ("Monroe"), located in Monroe County, Mississippi, is in operation with
approximately 9.0 bcf of working storage capacity, of which 100% is contracted under firm storage service agreements. As of
December 31, 2012, the weighted average remaining term of our existing portfolio of third party firm storage contracts was
approximately 1.5 years.
Perryville Gas Storage, LLC ("Perryville"), located in Franklin Parish, Louisiana, is under development with
approximately 8.5 bcf of working storage capacity, of which 100% is contracted under firm storage service agreements with an
average contract term of 5.6 years. The project is expected to be in service in the third quarter of 2013.
Cadeville Gas Storage, LLC ("Cadeville"), located in Ouachita Parish, Louisiana, is under development with
approximately 17.0 bcf of working storage capacity, of which 100% is contracted under firm storage service agreements with
an average contract term of 10.0 years. The project is expected to be in service in the third quarter of 2013.
These facilities are being developed to provide producers, end users, local distribution companies, pipelines and
energy marketers with high deliverability storage services and hub services.
Natural gas storage facilities provide a staging and warehousing function for seasonal swings in demand relative to
supply, as well as an essential reliability cushion against disruptions in natural gas supply, demand and transportation by
allowing natural gas to be injected into, withdrawn from or warehoused in such storage facilities as dictated by market
conditions. The long term demand for storage services in the U.S. is driven primarily by the long-term demand for natural gas
and the overall lack of balance between the supply of and demand for natural gas on a seasonal, monthly, daily or other basis. In
general and on a long term basis, to the extent the overall demand for natural gas increases and such growth includes higher
demand from seasonal or weather-sensitive end-users (such as gas-fired power generators and residential and commercial
consumers), demand for natural gas storage services should also grow. In addition, any factors that contribute to more frequent
and severe imbalances between the supply of and demand for natural gas, whether caused by supply or demand fluctuations,
14
should increase the need for and the value of storage services. On a short term basis, storage demand and values are also
significantly influenced by operational imbalances, near term seasonal spreads, shorter term spreads and basis differentials.
Sulfur Services Segment
Industry Overview. Sulfur is a natural element and is required to produce a variety of industrial products. In the U.S.,
approximately 10 million tons of sulfur are consumed annually with the Tampa, Florida area being the largest single market.
Currently, all sulfur produced in the U.S. is “recovered sulfur,” or sulfur that is a by-product from oil refineries and natural gas
processing plants. Sulfur production in the U.S. is principally located along the Gulf Coast, along major inland waterways and
in some areas of the western U.S.
Sulfur is an important plant nutrient and is primarily used in the manufacture of phosphate fertilizers with the balance
used for industrial purposes. The primary application of sulfur in fertilizers occurs in the form of sulfuric acid. Burning sulfur
creates sulfur dioxide, which is subsequently oxidized and dissolved in water to create sulfuric acid. The sulfuric acid is then
combined with phosphate rock to make phosphoric acid, the base material for most high-grade phosphate fertilizers.
Sulfur-based fertilizers are manufactured chemicals containing nutrients known to improve the fertility of soils.
Nitrogen, phosphorus, potassium and sulfur are the four most important nutrients for crop growth. These nutrients are found
naturally in soils. However, soils used for agriculture become depleted of these nutrients and frequently require fertilizers rich
in these essential nutrients to restore fertility.
Industrial sulfur products (including sulfuric acid) are used in a wide variety of industries. For example, these products
are used in power plants, paper mills, auto and tire manufacturing plants, food processing plants, road construction, cosmetics
and pharmaceuticals.
Our Operations and Products. We have an integrated system of transportation assets and facilities relating to our
sulfur services. We gather molten sulfur from refiners, primarily located on the Gulf Coast, and from natural gas processing
plants, primarily located in the southwestern U.S. We transport sulfur by inland and offshore barges, railcars and trucks. In the
U.S., recovered sulfur is mainly kept in liquid form from production to usage at a temperature of approximately 275 degrees
Fahrenheit. Because of the temperature requirement, the sulfur industry uses specialized equipment to store and transport
molten sulfur. We have the necessary assets and expertise to handle the unique requirements for transportation and storage of
molten sulfur.
The terms of our commercial sulfur contracts typically range from one to five years in length. We handle molten sulfur
on cost-plus contracts and margin-based contracts and the prices in such contracts are usually tied to a published market
indicator and fluctuate according to the price movement of the indicator. We also provide barge transportation and tank storage
to large integrated oil companies that produce sulfur and fertilizer manufacturers that consume sulfur under transportation and
storage contracts with remaining lives from one to two years in duration.
The sulfur prilling assets located at the Port of Stockton in California are used to process (prill) molten sulfur into
pellets. The Stockton facility can process approximately 1,000 metric tons of molten sulfur per day and the resulting dry pellets
are stored in bulk until sold into certain U.S. and international agricultural markets. In 2006, we completed the construction of a
sulfur priller at our Neches facility in Beaumont, Texas with construction of a second priller completed in 2009. Forming
capacity was further increased in 2012 with the addition of a granulator. The two Beaumont prillers along with the granulator
have the capacity to process approximately 5,500 metric tons of molten sulfur per day. We process molten sulfur into formed
sulfur on take-or-pay fee contracts, providing refiners access to the export market for the sale of their residual sulfur.
We entered the sulfur based fertilizer manufacturing business through acquisitions in 1990 and 1998. We have
expended significant resources to replace and update facilities and other assets and to integrate each of the acquired businesses
into our existing business resulting in increased the profitability of our fertilizer business. In December 2005, sulfur fertilizer
production capacity was added with the purchase of the net operating assets of A & A Fertilizer, Ltd. (“A & A Fertilizer”). This
production capacity is located at our Neches deep-water marine terminal near Beaumont, Texas.
In September 2007, we completed construction of a sulfuric acid production facility at our Plainview, Texas
location. This facility processes molten sulfur to produce approximately 150,000 tons of sulfuric acid per year. This acid
production provides a dedicated supply of raw material sulfuric acid to our ammonium sulfate production plant that was
completed in March of 2011. The ammonium sulfate plant produces approximately 400 tons per day of quality ammonium
sulfate and is marketed to our customers throughout the U.S. The sulfuric acid produced and not consumed by the captive
ammonium sulfate production is sold to Martin Resource Management which markets the excess production to third parties.
15
Fertilizer and related sulfur products are a natural extension of our molten sulfur business because of our access to
sulfur and our distribution capabilities. These products allow us to leverage the Sulfur Services segment of our business. Our
annual fertilizer and industrial sulfur products sales have grown from approximately 62,000 tons in 1997 to approximately
306,000 tons in 2012 as a result of acquisitions and internal growth.
In the U.S., fertilizer is generally sold to farmers through local dealers. These dealers are typically owned and
supplied by much larger wholesale distributors. We sell to these wholesale distributors. Our industrial sulfur products are
marketed primarily in the southern U.S., where many paper manufacturers and power plants are located. Our products are sold
in accordance with price lists that vary from state to state. These price lists are updated periodically to reflect changes in
seasonal or competitive prices. We transport our fertilizer and industrial sulfur products to our customers using third-party
common carriers. We utilize rail shipments for large volume and long distance shipments where available.
We manufacture and market the following sulfur-based fertilizer and related sulfur products:
•
Plant nutrient sulfur products. We produce plant nutrient and agricultural ground sulfur products at our two
facilities in Odessa, Texas. We also produce plant nutrient sulfur at our facility in Seneca, Illinois. Our plant nutrient
sulfur product is a 90% degradable sulfur product marketed under the Disper-Sul® trade name and sold throughout
the U.S. to direct application agricultural markets. Our agricultural ground sulfur products are used primarily in the
western U.S. on grapes and vegetable crops.
• Ammonium sulfate products. We produce various grades of ammonium sulfate including granular, coarse and
standard grades, a 40% ammonium sulfate solution and a Kosher-approved food grade material. These products
primarily serve direct application agricultural markets. We blend our ammonium sulfate to make custom grades of
lawn and garden fertilizer at our facility in Salt Lake City, Utah. We package these custom grade products under
both proprietary and private labels and sell them to major retail distributors and other retail customers of these
products.
•
Industrial sulfur products. We produce industrial sulfur products such as elemental pastille sulfur, industrial ground
sulfur products, and emulsified sulfur. We produce elemental pastille sulfur at our two Odessa, Texas facilities and
at our Seneca, Illinois facility. Elemental pastille sulfur is used to increase the efficiency of the coal-fired
precipitators in the power industry. These industrial ground sulfur products are also used in a variety of dusting and
wettable sulfur applications such as rubber manufacturing, fungicides, sugar and animal feeds. We produce
emulsified sulfur at our Texarkana, Texas facility. Emulsified sulfur is primarily used to control the sulfur content in
the pulp and paper manufacturing processes.
• Liquid sulfur products. We produce ammonium thiosulfate at our Neches terminal facility in Beaumont, Texas. This
agricultural sulfur product is a clear liquid containing 12% nitrogen and 26% sulfur. This product serves as a liquid
plant nutrient used directly through spray rigs or irrigation systems. It is also blended with other NPK liquids or
suspensions as well. Our market is predominantly the Mid-South U.S. and Coastal Bend area of Texas.
Our Sulfur Services Facilities.
We own 56 railcars and lease 120 railcars equipped to transport molten sulfur. We own the following major marine
assets and use them to transport molten sulfur from our Beaumont, Texas terminal to our Tampa, Florida terminal as well as
provide third party marine transportation services to others:
Asset
Margaret Sue
M/V Martin Explorer
M/V Martin Express
MGM 101
MGM 102
Class of Equipment
Offshore tank barge
Offshore tugboat
Inland push boat
Inland tank barge
Inland tank barge
Capacity/Horsepower
10,450 long tons
7,200 horsepower
1,200 horsepower
2,450 long tons
2,450 long tons
Products Transported
Molten sulfur
N/A
N/A
Molten sulfur
Molten sulfur
We own the following sulfur forming facilities as part of our sulfur services business:
16
Terminal
Location
Daily Production Capacity
Products Stored
Neches
Stockton
Beaumont, Texas
5,500 metric tons per day
Molten, prilled and
granulated sulfur
Stockton, California
1,000 metric tons per day
Molten and prilled sulfur
We lease 79 railcars to transport our fertilizer products. We own the following manufacturing plants as part of our
sulfur services business:
Facility
Location
Capacity
Description
Fertilizer plant
Plainview, Texas
150,000 tons/year
Fertilizer production
Fertilizer plant
Beaumont, Texas
120,000 tons/year
Fertilizer plants (two)
Odessa, Texas
70,000 tons/year
Fertilizer plant
Seneca, Illinois
36,000 tons/year
Fertilizer plant
Industrial sulfur plant
Sulfuric acid plant
Salt Lake City, Utah
Texarkana, Texas
Plainview Texas
25,000 tons/year
18,000 tons/year
150,000 tons/year
Liquid sulfur fertilizer
production
Dry sulfur fertilizer
production
Dry sulfur fertilizer
production
Blending and packaging
Emulsified sulfur production
Sulfuric acid production
Competition. We own one of the four vessels currently used to transport molten sulfur between U.S. ports on the Gulf
of Mexico and Tampa, Florida. Six phosphate fertilizer manufacturers together consume a vast majority of the sulfur produced
in the U.S. and these buy from resellers as well as directly from producers. We compete primarily with U.S. producers that sell
directly to consumers with access to transportation and storage assets as well as foreign suppliers from Mexico or Venezuela
that may sell into the Florida market. Our sulfur-based fertilizer products compete with several large fertilizer and sulfur
products manufacturers. However, the close proximity of our manufacturing plants to our customer base is a competitive
advantage for us in the markets we serve and allows us to minimize freight costs and respond quickly to customer requests.
Our sulfuric acid products compete with regional producers and importers in the South and Southwest portion of the U.S. from
Louisiana to California.
Seasonality. Sales of our agricultural fertilizer products are partly seasonal as a result of increased demand during the
growing season.
Marine Transportation Segment
Industry Overview. The U.S. inland waterway system is a vast and heavily used transportation system. This inland
waterway system is composed of a network of interconnected rivers and canals that serve as water highways and is used to
transport vast quantities of products annually. This waterway system extends approximately 26,000 miles, of which 12,000
miles are generally considered significant for domestic commerce.
The Gulf Coast region is a major hub for petroleum refining. The petroleum refining process generates products and
by-products that require transportation in large quantities from the refinery or processor. Convenient access to and use of this
waterway system by the petroleum and petrochemical industry is a major reason for the current location of U.S. refineries and
petrochemical facilities. The marine transportation industry uses push boats and tugboats as power sources and tank barges for
freight capacity. The combination of the power source and tank barge freight capacity is called a tow.
Marine Fleet. We utilize a fleet of inland and offshore tows that provide marine transportation of petroleum products
and by-products produced in oil refining and natural gas processing. Our marine transportation business operates coastwise
along the Gulf of Mexico and East Coast and on the U.S. inland waterway system, primarily between domestic ports along the
Gulf of Mexico, Intracoastal Waterway, the Mississippi River system and the Tennessee-Tombigbee Waterway
system. Additionally, we participate in Caribbean, Central America, and South American transport. Our inland tows generally
consist of one push boat and one to three tank barges, depending upon the horsepower of the push boat, the river or canal
capacity and conditions, and customer requirements. Each of our offshore tows consist of one tugboat, with much greater
horsepower than an inland push boat, and one large tank barge. We transport asphalt, fuel oil, gasoline, sulfur and other bulk
liquids.
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The following is a summary description of the marine vessels we use in our marine transportation business:
Class of Equipment
Inland tank barges
Number in Class
23
Capacity/Horsepower
20,000 bbl and under
Inland tank barges
Inland push boats
Offshore tank barges
Offshore tugboats
31
29
4
4
20,000 - 30,000 bbl
400 - 3,800 horsepower
45,000 bbl and 95,000 bbl
2,400 - 7,200 horsepower
Description of Products
Carried
Asphalt, crude oil, fuel oil,
gasoline and sulfur
Asphalt, crude oil, fuel oil and
gasoline
N/A
Asphalt, fuel oil and NGLs
N/A
Our largest marine transportation customers include major and independent oil and gas refining companies, petroleum
marketing companies and Martin Resource Management. We conduct our marine transportation services on a fee basis
primarily under annual contracts.
We are a party to a marine transportation agreement 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.
Competition. We compete primarily with other marine transportation companies. The marine barging industry has
experienced significant consolidation in past years. The total number of tank barges that operate in the inland waters of the
U.S. has declined over the past 30 years, primarily resulting from:
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the increasing age of the domestic tank barge fleet, resulting in retirements;
a reduction in tax incentives, which previously encouraged speculative construction of new equipment;
stringent operating standards to adequately address safety and environmental risks;
the elimination of government programs supporting small refineries;
an increase in environmental regulations mandating expensive equipment modification; and
• more restrictive and expensive insurance.
There are several barriers to entry into the marine transportation industry that discourage the emergence of new
competitors. Examples of these barriers to entry include:
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significant start-up capital requirements;
the costs and operational difficulties of complying with stringent safety and environmental regulations;
the cost and difficulty in obtaining insurance; and
the number and expertise of personnel required to support marine fleet operations.
We believe the reduction of the number of tank barges, the consolidation among barging companies and the significant
barriers to entry in the industry have resulted in a more stabilized and favorable pricing environment for our marine
transportation services.
We believe we compete favorably with our competitors. Historically, competition within the marine transportation
business was based primarily on price. However, we believe customers are placing an increased emphasis on safety,
environmental compliance, quality of service and the availability of a single source of supply of a diversified package of
services. In particular, we believe customers are increasingly seeking transportation vendors that can offer marine, land, rail and
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terminal distribution services, as well as provide operational flexibility, safety, environmental and financial responsibility,
adequate insurance, and quality of service consistent with the customer’s own operations and policies. We operate a diversified
asset base that, together with the services provided by Martin Resource Management, enables us to offer our customers an
integrated distribution network consisting of transportation, terminalling, distribution and midstream logistical services for
petroleum products and by-products.
In addition to competitors that provide marine transportation services, we also compete with providers of other modes
of transportation, such as rail tank cars, tractor-trailer tank trucks and, to a limited extent, pipelines. We believe we offer a
competitive advantage over rail tank cars and tractor-trailer tank trucks because marine transportation is a more efficient, and
generally less expensive, mode of transporting petroleum products and by-products. For example, a typical two inland barge
unit carries a volume of product equal to approximately 80 raiilcars or 250 tanker trucks. Pipelines generally provide a less
expensive form of transportation than marine transportation. However, pipelines are not able to transport most of the products
we transport and are generally a less flexible form of transportation because they are limited to the fixed point-to-point
distribution of commodities in high volumes over extended periods of time.
Seasonality. The demand for our marine transportation business is subject to some seasonality factors. Our asphalt
shipments are generally higher during April through November when weather allows for efficient road construction. However,
demand for marine transportation of sulfur, fuel oil and gasoline is directly related to production of these products in the oil
refining and natural gas processing business, which is fairly stable.
Our Relationship with Martin Resource Management
•
•
•
•
•
•
•
•
•
•
•
•
Martin Resource Management is engaged in the following principal business activities:
providing land transportation of various liquids using a fleet of trucks and road vehicles and road trailers;
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;
building and marketing of sulfur processing equipment;
supplying employees and services for the operation of our business;
operating, for its account and our account, the docks, roads, loading and unloading facilities and other common use
facilities or access routes at our Stanolind terminal; and
operating, solely for our account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas and South Houston,
Texas.
We are and will continue to be closely affiliated with Martin Resource Management as a result of the following
relationships.
Ownership
As of December 31, 2012, Martin Resource Management owned 19.2% of our total outstanding common limited
partner units and a 2% general partnership interest in us and all of our incentive distribution rights.
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Management
Martin Resource Management directs our business operations through its ownership and control of our general
partner. We benefit from our relationship with Martin Resource Management through access to a significant pool of
management expertise and established relationships throughout the energy industry. We do not have employees. Martin
Resource Management’s employees are responsible for conducting our business and operating our assets on our behalf.
Related Party Agreements
The Omnibus Agreement with Martin Resource Management requires us to reimburse Martin Resource Management
for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. We
reimbursed Martin Resource Management for $157.8 million, $142.0 million and $107.9 million of direct costs and expenses
for the years ended December 31, 2012, 2011 and 2010, respectively. There is no monetary limitation on the amount we are
required to reimburse Martin Resource Management for direct expenses.
In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource
Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2012,
2011, and 2010, the Conflicts Committee of our general partner approved reimbursement amounts of $7.6 million, $4.8 million
and $3.8 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
covered the centralized corporate functions Martin Resource Management provides for us, 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’s retained
businesses. the Omnibus Agreement also contains significant non-compete provisions and indemnity obligations. Martin
Resource Management also licenses certain of its trademarks and trade names to us under the Omnibus Agreement.
The agreements include, but are not limited to, a motor carrier agreement, a terminal services agreement, a marine
transportation agreement, a product storage agreement, a product supply agreement, a throughput agreement, and a purchaser
use easement, ingress-egress easement and utility facilities easement. Pursuant to the terms of the Omnibus Agreement, we are
prohibited from entering into certain material agreements with Martin Resource Management without the approval of the
Conflicts Committee of our general partner’s board of directors.
For a more comprehensive discussion concerning the Omnibus Agreement and the other agreements that we have
entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions, and
Director Independence – Agreements.”
Commercial
We have been and anticipate that we will continue to be both a significant customer and supplier of products and
services offered by Martin Resource Management. Our motor carrier agreement with Martin Resource Management provides us
with access to Martin Resource Management’s fleet of road vehicles and road trailers to provide land transportation in the areas
served by Martin Resource Management. Our ability to utilize Martin Resource Management’s land transportation operations is
currently a key component of our integrated distribution network.
We also use the underground storage facilities owned by Martin Resource Management in our natural gas services
operations. We lease an underground storage facility from Martin Resource Management in Arcadia, Louisiana with a storage
capacity of 2.2 million barrels. Our use of this storage facility gives us greater flexibility in our operations by allowing us to
store a sufficient supply of product during times of decreased demand for use when demand increases.
In the aggregate, our purchases of land transportation services, NGL storage services, lube oil product purchases and
sulfur services payroll reimbursements from Martin Resource Management accounted for approximately 8% of our total cost of
products sold during the years ended December 31, 2012 and 2011, and 9% for the year ended December 31, 2010. We also
purchase marine fuel from Martin Resource Management, which we account for as an operating expense.
Correspondingly, Martin Resource Management is one of our significant customers. It primarily uses our terminalling,
marine transportation and NGL distribution services for its operations. We provide terminalling and storage services under a
terminal services agreement. We provide marine transportation services to Martin Resource Management under a charter
agreement on a spot-contract basis at applicable market rates. Our sales to Martin Resource Management accounted for
approximately 6%, 7% and 9% of our total revenues for the years ended December 31, 2012, 2011 and 2010, respectively. We
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have entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage
and marine transportation services to its subsidiary, MES, and MES provides terminal services to us to handle lubricants,
greases and drilling fluids. Additionally, we have entered into a long-term, fee for services-based Tolling Agreement with
Martin Resource Management where Martin Resource Management agrees to pay us for the processing of its crude oil into
finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts.
For a more comprehensive discussion concerning the Omnibus Agreement and the other agreements that we have
entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions, and
Director Independence – Agreements.”
Approval and Review of Related Party Transactions
If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in
which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to
the board of directors of our general partner or to our management, as appropriate. If the board of directors is involved in the
approval process, it determines whether to refer the matter to the Conflicts Committee of our general partner's board of
directors, as constituted under our limited partnership agreement. If a matter is referred to the Conflicts Committee, it obtains
information regarding the proposed transaction from management and determines whether to engage independent legal counsel
or an independent financial advisor to advise the members of the committee regarding the transaction. If the Conflicts
Committee retains such counsel or financial advisor, it considers such advice and, in the case of a financial advisor, such
advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.
Insurance
Our deductible for onshore physical damage resulting from named windstorms is 5% of the total value located at an
individual location subject to an overall minimum deductible of $4.0 million for damage caused by the named windstorm at all
locations. Our onshore program currently provides $30.0 million per occurrence for named windstorm events. For non-
windstorm events, our deductible applicable to onshore physical damage is $1.5 million per occurrence. Business interruption
coverage in connection with a windstorm event is subject to the same $30.0 million per occurrence and aggregate limit as the
property damage coverage and a waiting period of 45 days. For non-windstorm events, our waiting period applicable to
business interruption is 30 days.
Our deductible for physical damage at our refining, blending and packaging division in Smackover, Arkansas is $0.5
million per occurrence. The waiting period applicable to business interruption is 30 days.
Loss of, or damage to, our vessels and cargo is insured through hull and cargo insurance policies. Vessel operating
liabilities such as collision, cargo, environmental and personal injury are insured primarily through our participation in mutual
insurance associations and other reinsurance arrangements, pursuant to which we are potentially exposed to assessments in the
event claims by us or other members exceed available funds and reinsurance. Protection and indemnity (“P&I”) insurance
coverage is provided by P&I associations and other insurance underwriters. Our vessels are entered in P&I associations that are
parties to a pooling agreement, known as the International Group Pooling Agreement (“Pooling Agreement”) through which
approximately 90% of the world's ocean-going tonnage is reinsured through a group reinsurance policy. With regard to collision
coverage, the first $1.0 million of coverage is insured by our hull policy and any excess is insured by a P&I association. We
insure our owned cargo through a domestic insurance company. We insure cargo owned by third parties through our P&I
coverage. As a member of P&I associations that are parties to the Pooling Agreement, we are subject to supplemental calls
payable to the associations of which we are a member, based on our claims record and the other members of the other P&I
associations that are parties to the Pooling Agreement. Except for our marine operations, we self-insure against liability
exposure up to a pre-determined amount, beyond which we are covered by catastrophe insurance coverage.
For marine claims, our insurance covers up to $1.0 billion of liability per accident or occurrence. We believe our
current insurance coverage is adequate to protect us against most accident related risks involved in the conduct of our business.
However, there can be no assurance that all risks are adequately insured against, that any particular claim will be paid by the
insurer, or that we will be able to procure adequate insurance coverage at commercially reasonable rates in the future.
Environmental and Regulatory Matters
Our activities are subject to various federal, state and local laws and regulations, as well as orders of regulatory bodies,
governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the
environment, safety and other matters.
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Environmental
We are subject to complex federal, state, and local environmental laws and regulations governing the discharge of
materials into the environment or otherwise relating to protection of human health, natural resources and the environment.
These laws and regulations can impair our operations that affect the environment in many ways, such as requiring the
acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the
environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and
imposing substantial liabilities on us for pollution resulting from our operations. Many environmental laws and regulations can
impose joint and several, strict liability, and any failure to comply with environmental laws and regulations may result in the
assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and, in
some circumstances, the issuance of injunctions that can limit or prohibit our operations.
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect
the environment, and, thus, any changes in environmental laws and regulations that result in more stringent and costly waste
handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and
financial position. Moreover, there is inherent risk of incurring significant environmental costs and liabilities in the performance
of our operations due to our handling of petroleum products and by-products, chemical substances, and wastes as well as the
accidental release or spill of such materials into the environment. Consequently, we cannot assure you that we will not incur
significant costs and liabilities as result of such handling practices, releases or spills, including those relating to claims for
damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our
customers. While we believe that we are in substantial compliance with current environmental laws and regulations and that
continued compliance with existing requirements would not have a material adverse impact on us, we cannot provide any
assurance that our environmental compliance expenditures will not have a material adverse impact on us in the future.
Superfund
The Federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”),
also known as the “Superfund” law, and similar state laws, impose liability without regard to fault or the legality of the original
conduct, on certain classes of “responsible persons,” including the owner or operator of a site where regulated hazardous
substances have been released into the environment and companies that disposed or arranged for the disposal of the hazardous
substances found at such site. Under CERCLA, these responsible persons may be subject to joint and several, strict liability for
the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural
resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties
to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the
environment. Although certain hydrocarbons are not subject to CERCLA’s reach because “petroleum” is excluded from
CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we will generate wastes that may fall
within the definition of a “hazardous substance.” We are not subject to any notification that we may be potentially responsible
for cleanup costs under CERCLA.
Solid Waste
We generate both hazardous and nonhazardous solid wastes which are subject to requirements of the federal Resource
Conservation and Recovery Act, as amended (“RCRA”) and comparable state statutes. From time to time, the U.S.
Environmental Protection Agency (“EPA”) has considered making changes in nonhazardous waste standards that would result
in stricter disposal requirements for these wastes. Furthermore, it is possible some wastes generated by us that are currently
classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more
rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital
expenditures or operating expenses.
We currently own or lease, and have in the past owned or leased, properties that have been used for the manufacturing,
processing, transportation and storage of petroleum products and by-products. Solid waste disposal practices within oil and gas
related industries have improved over the years with the passage and implementation of various environmental laws and
regulations. Nevertheless, a possibility exists that hydrocarbons and other solid wastes may have been disposed of on or under
various properties owned or leased by us during the operating history of those facilities. In addition, a number of these
properties have been operated by third parties over whom we had no control as to such entities’ handling of hydrocarbons,
hydrocarbon by-products or other wastes and the manner in which such substances may have been disposed of or released.
State and federal laws and regulations applicable to oil and natural gas wastes and properties have gradually become more strict
and, under such laws and regulations, we could be required to remove or remediate previously disposed wastes or property
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contamination, including groundwater contamination, even under circumstances where such contamination resulted from past
operations of third parties.
Clean Air Act
Our operations are subject to the federal Clean Air Act ("CAA"), as amended, and comparable state statutes.
Amendments to the CAA adopted in 1990 contain provisions that may result in the imposition of increasingly stringent
pollution control requirements with respect to air emissions from the operations of our terminal facilities, processing and
storage facilities and fertilizer and related products manufacturing and processing facilities. Such air pollution control
requirements may include specific equipment or technologies to control emissions, permits with emissions and operational
limitations, pre-approval of new or modified projects or facilities producing air emissions, and similar measures. For example,
the Neches Terminal we use is located in an EPA-designated ozone non-attainment area, referred to as the Beaumont/Port
Arthur non-attainment area, which is subject to a EPA-adopted 8-hour standard for complying with the national standard for
ozone. In addition, existing sources of air emissions in the Beaumont/Port Arthur area are already subject to stringent emission
reduction requirements. Failure to comply with applicable air statutes or regulations may lead to the assessment of
administrative, civil or criminal penalties, and/or result in the limitation or cessation of construction or operation of certain air
emission sources. We believe our operations, including our manufacturing, processing and storage facilities and terminals, are
in substantial compliance with applicable requirements of the CAA and analogous state laws.
Global Warming and Climate Change. Recent scientific studies have suggested that emissions of certain gases,
commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the
Earth’s atmosphere. In response to such studies, the U.S. Congress has from time to time considered climate change-related
legislation to restrict greenhouse gas emissions. At least 17 states have already taken legal measures to reduce emissions of
greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional
greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007, in
Massachusetts, et al. v. EPA, the EPA eventually concluded that it is required to regulate greenhouse gas emissions from mobile
sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse
gases. The Court's holding in Massachusetts that greenhouse gases fall under the federal CAA's definition of air pollutant has
also led the EPA to determine that regulation of greenhouse gas emissions from stationary sources under various Clean Air Act
programs is required. To that end, EPA promulgated regulations, referred to as the Tailoring Rule, 75 Fed. Red. 31514, to begin
gradually subjecting stationary greenhouse gas emission sources to various Clean Air Act programs, including permitting
programs applicable to new and existing major sources of greenhouse gas emissions. To date, such requirements have not had a
substantial effect upon our operations. Still, new legislation or regulatory programs that restrict emissions of greenhouse gases
in areas in which we conduct business could adversely affect our operations and demand for our services.
Clean Water Act
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws
impose restrictions and controls on the discharge of pollutants into federal and state waters. Regulations promulgated under
these laws require entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System
(“NPDES”) and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess penalties
for releases of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such
waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general
permits be obtained by covered facilities for discharges of storm water runoff and that applicable facilities develop and
implement plans for the management of storm water runoff (referred to as storm water pollution prevention plans (“SWPPPs”))
as well as for the prevention and control of oil spills (referred to as spill prevention, control and countermeasure (“SPCC”)
plans). As part of the regular overall evaluation of our on-going operations, we are reviewing and, as necessary, updating
SWPPPs for certain of our facilities, including facilities recently acquired. In addition, we have reviewed our SPCC plans and,
where necessary, amended such plans to comply with applicable regulations adopted by the EPA. We believe that compliance
with the conditions of such permits and plans will not have a material effect on our operations.
Oil Pollution Act
The Oil Pollution Act of 1990, as amended (“OPA”) imposes a variety of regulations on “responsible parties” related
to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. A “responsible party” includes
the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The
OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages including
natural resource damages. Under OPA, vessels and shore facilities handling, storing, or transporting oil are required to develop
and implement oil spill response plans, and vessels greater than 300 tons in weight must provide to the U.S. Coast Guard
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evidence of financial responsibility to cover the costs of cleaning up oil spills from such vessels. The OPA also requires that all
newly constructed tank barges engaged in oil transportation in the U.S. be double hulled and all existing single hull tank barges
be retrofitted with double hulls or phased out by 2015. We believe we are in substantial compliance with all of the oil spill-
related and financial responsibility requirements. Nonetheless, in the aftermath of the Deepwater Horizon incident in 2010,
Congress has from time to time considered oil spill related legislation that could have the effect of substantially increasing
financial responsibility requirements and potential fines and damages for violations and discharges subject to the Oil Pollution
Act, and similar legislation. Any such changes in law affecting areas where we conduct business could materially affect our
operations.
Safety Regulation
The Company’s marine transportation operations are subject to regulation by the U.S. Coast Guard, federal laws, state
laws and certain international treaties. Tank ships, push boats, tugboats and barges are required to meet construction and repair
standards established by the American Bureau of Shipping, a private organization, and the U.S. Coast Guard and to meet
operational and safety standards presently established by the U.S. Coast Guard. We believe our marine operations and our
terminals are in substantial compliance with current applicable safety requirements.
Occupational Health Regulations
The workplaces associated with our manufacturing, processing, terminal and storage facilities are subject to the
requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. We believe we have
conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record
keeping requirements and monitoring of occupational exposure to regulated substances. Our marine vessel operations are also
subject to safety and operational standards established and monitored by the U.S. Coast Guard.
In general, we expect to increase our expenditures relating to compliance with likely higher industry and regulatory
safety standards such as those described above. These expenditures cannot be accurately estimated at this time, but we do not
expect them to have a material adverse effect on our business.
Jones Act
The Jones Act is a federal law that restricts maritime transportation between locations in the U.S. to vessels built and
registered in the U.S. and owned and manned by U.S. citizens. Since we engage in maritime transportation between locations in
the U.S., we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of our
subsidiaries that engage in maritime transportation and for taking any remedial action necessary to insure that no violation of
the Jones Act ownership restrictions occurs. The Jones Act also requires that all U.S.-flagged vessels be manned by U.S.
citizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by U.S. citizen seamen. This
requirement significantly increases operating costs of U.S.-flagged vessel operations compared to foreign-flagged vessel
operations. Certain foreign governments subsidize their nations’ shipyards. This results in lower shipyard costs both for new
vessels and repairs than those paid by U.S.-flagged vessel owners. The U.S. Coast Guard and American Bureau of Shipping
maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory compliance
costs for U.S.-flagged operators than for owners of vessels registered under foreign flags of convenience.
Merchant Marine Act of 1936
The Merchant Marine Act of 1936 is a federal law that provides that, upon proclamation by the President of the U.S. of
a national emergency or a threat to the national security, the U.S. Secretary of Transportation may requisition or purchase any
vessel or other watercraft owned by U.S.’ citizens (including us, provided that we are considered a U.S. citizen for this
purpose). If one of our push boats, tugboats or tank barges were purchased or requisitioned by the U.S. government under this
law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition,
the fair market value of charter hire. However, if one of our push boats or tugboats is requisitioned or purchased and its
associated tank barge is left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the
idled barge. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the
requisition or purchase of any of our push boats, tugboats or tank barges.
Employees
We do not have any employees. Under our Omnibus Agreement with Martin Resource Management, Martin Resource
Management provides us with corporate staff and support services. These services include centralized corporate functions, such
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as accounting, treasury, engineering, information technology, insurance, administration of employee benefit plans and other
corporate services. Martin Resource Management employs approximately 835 individuals including 55 employees represented
by labor unions who provide direct support to our operations as of March 4, 2013.
Financial Information about Segments
Information regarding our operating revenues and identifiable assets attributable to each of our segments is presented
in Note 19 to our consolidated financial statements included in this annual report on Form 10-K.
Access to Public Filings
We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K, and amendments to these reports filed with the Securities and Exchange Commission (“SEC”) under the Securities
and Exchange Act of 1934. These documents may be accessed free of charge on our website at the following address:
www.martinmidstream.com. These documents are provided as soon as is reasonably practicable after their filing with the
SEC. This website address is intended to be an inactive, textual reference only, and none of the material on this website is part
of this report. These documents may also be found at the SEC’s website at www.sec.gov.
Item 1A. Risk Factors
Limited partner interests are inherently different from the capital stock of a corporation, although many of the
business risks to which we are subject are similar to those that would be faced by a corporation engaged in a business similar
to ours. If any of the following risks were actually to occur, our business, financial condition or results of operations could be
materially adversely affected. In this case, we might not be able to pay distributions on our common units, the trading price of
our common units could decline and unitholders could lose all or part of their investment. These risk factors should be read in
conjunction with the other detailed information concerning us set forth herein.
Risks Relating to Our Business
Important factors that could cause actual results to differ materially from our expectations include, but are not limited
to, the risks set forth below. The risks described below should not be considered to be comprehensive and all-inclusive. Many
of such factors are beyond our ability to control or predict. Unitholders are cautioned not to put undue reliance on forward-
looking statements. Additional risks that we do not yet know of or that we currently think are immaterial may also impair our
business operations, financial condition and results of operations.
We may not have sufficient cash after the establishment of cash reserves and payment of our general partner's expenses to
enable us to pay the minimum quarterly distribution each quarter.
We may not have sufficient available cash each quarter in the future to pay the minimum quarterly distribution on all
our units. Under the terms of our partnership agreement, we must pay our general partner's expenses and set aside any cash
reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our common units
principally depends upon the amount of net cash generated from our operations, which will fluctuate from quarter to quarter
based on, among other things:
•
•
•
•
•
•
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the costs of acquisitions, if any;
the prices of petroleum products and by-products;
fluctuations in our working capital;
the level of capital expenditures we make;
restrictions contained in our debt instruments and our debt service requirements;
our ability to make working capital borrowings under our credit facility; and
the amount, if any, of cash reserves established by our general partner in its discretion.
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Unitholders should also be aware that the amount of cash we have available for distribution depends primarily on our
cash flow, including cash flow from working capital borrowings, and not solely on profitability, which will be affected by non-
cash items. In addition, our general partner determines the amount and timing of asset purchases and sales, capital
expenditures, borrowings, issuances of additional partnership securities and the establishment of reserves, each of which can
affect the amount of cash available for distribution to our unitholders. As a result, we may make cash distributions during
periods when we record losses and may not make cash distributions during periods when we record net income.
Restrictions in our credit facility may prevent us from making distributions to our unitholders.
The payment of principal and interest on our indebtedness reduces the cash available for distribution to our
unitholders. In addition, we are prohibited by our credit facility from making cash distributions during a default or an event of
default under our credit facility or if the payment of a distribution would cause a default or an event of default thereunder. Our
leverage and various limitations in our credit facility may reduce our ability to incur additional debt, engage in certain
transactions, and capitalize on acquisition or other business opportunities that could increase cash flows and distributions to our
unitholders.
If we do not have sufficient capital resources for acquisitions or opportunities for expansion, our growth will be limited.
We intend to explore acquisition opportunities in order to expand our operations and increase our profitability. We may
finance acquisitions through public and private financing, or we may use our limited partner interests for all or a portion of the
consideration to be paid in acquisitions. Distributions of cash with respect to these equity securities or limited partner interests
may reduce the amount of cash available for distribution to the common units. In addition, in the event our limited partner
interests do not maintain a sufficient valuation, or potential acquisition candidates are unwilling to accept our limited partner
interests as all or part of the consideration, we may be required to use our cash resources, if available, or rely on other financing
arrangements to pursue acquisitions. If we use funds from operations, other cash resources or increased borrowings for an
acquisition, the acquisition could adversely impact our ability to make our minimum quarterly distributions to our unitholders.
Additionally, if we do not have sufficient capital resources or are not able to obtain financing on terms acceptable to us for
acquisitions, our ability to implement our growth strategies may be adversely impacted.
We may not be able to obtain funding on acceptable terms or at all because of the deterioration of the credit and capital markets.
This may hinder or prevent us from meeting our future capital needs.
Although the domestic capital markets have been available to us, global financial markets and economic conditions
have been, and continue to be, disrupted and volatile due to a variety of factors, including uncertainty in the financial services
sector, low consumer confidence, continued high unemployment, geopolitical issues and the current weak economic conditions.
In addition, the fixed-income markets have experienced periods of extreme volatility, which have negatively impacted market
liquidity conditions.
As a result of these conditions, the availability of funds from the credit and capital markets has diminished
significantly, and the cost of raising money in the debt and equity capital markets has increased substantially. In particular, as a
result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the
cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates,
enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to
provide, funding to borrowers. In addition, lending counterparties under our existing revolving credit facility and other debt
instruments may be unwilling or unable to meet their funding obligations. These conditions have made, and may continue to
make, it difficult to obtain funding for our capital needs. Due to these conditions, we cannot be certain that new debt or equity
financing will be available on acceptable terms or at all. If funding is not available when needed, or is available only on
unfavorable terms, we may be unable to execute our growth strategy, meet our obligations as they come due or complete future
acquisitions or expansion and maintenance capital projects, any of which could have a material adverse effect on our revenues
and results of operations.
We are exposed to counterparty risk in our credit facility and related interest rate protection agreements.
We rely on our credit facility to assist in financing a significant portion of our working capital, acquisitions and capital
expenditures. Our ability to borrow under our credit facility may be impaired because:
•
one or more of our lenders may be unable or otherwise fail to meet its funding obligations;
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•
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the lenders do not have to provide funding if there is a default under the credit facility or if any of the
representations or warranties included in the credit facility are false in any material respect; and
if any lender refuses to fund its commitment for any reason, whether or not valid, the other lenders are not
required to provide additional funding to make up for the unfunded portion.
If we are unable to access funds under our credit facility, we will need to meet our capital requirements, including
some of our short-term capital requirements, using other sources. Alternative sources of liquidity may not be available on
acceptable terms, if at all. If the cash generated from our operations or the funds we are able to obtain under our credit facility
or other sources of liquidity are not sufficient to meet our capital requirements, then we may need to delay or abandon capital
projects or other business opportunities, which could have a material adverse effect on our business, financial condition and
results of operations.
In addition, we have from time to time entered into interest rate protection agreements to manage our interest rate risk
exposure by fixing a portion of the interest expense we pay on our long-term debt under our credit facility. Uncertainty in the
global economy and banking markets exists, which could affect whether the counterparties to such interest rate protection
agreements are able to honor their agreements. If the counterparties fail to honor their commitments, we could experience
higher interest rates, which could have a material adverse effect on our business, financial condition and results of operations.
In addition, if the counterparties fail to honor their commitments, we also may be required to replace such interest rate
protection agreements with new interest rate protection agreements, and such replacement interest rate protection agreements
may be at higher rates than our current interest rate protection agreements, which could have a material adverse effect on our
business, financial condition and results of operations.
The impacts of climate-related initiatives at the international, federal and state levels remain uncertain at this time.
Currently, there are numerous international, federal and state-level initiatives and proposals addressing domestic and
global climate issues. Within the U.S., most of these proposals would regulate and/or tax, in one fashion or another, the
production of carbon dioxide and other "greenhouse gases" to facilitate the reduction of carbon compound emissions to the
atmosphere, and provide tax and other incentives to produce and use more "clean energy."
Our recent and future acquisitions may not be successful, may substantially increase our indebtedness and contingent
liabilities and may create integration difficulties.
As part of our business strategy, we intend to acquire businesses or assets we believe complement our existing
operations. We may not be able to successfully integrate recent or any future acquisitions into our existing operations or
achieve the desired profitability from such acquisitions. These acquisitions may require substantial capital expenditures and the
incurrence of additional indebtedness. If we make acquisitions, our capitalization and results of operations may change
significantly. Further, any acquisition could result in:
•
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post-closing discovery of material undisclosed liabilities of the acquired business or assets;
the unexpected loss of key employees or customers from the acquired businesses;
difficulties resulting from our integration of the operations, systems and management of the acquired
business; and
•
an unexpected diversion of our management's attention from other operations.
If recent or any future acquisitions are unsuccessful or result in unanticipated events or if we are unable to successfully
integrate acquisitions into our existing operations, such acquisitions could adversely affect our results of operations, cash flow
and ability to make distributions to our unitholders.
Adverse weather conditions, including droughts, hurricanes, tropical storms and other severe weather, could reduce our
results of operations and ability to make distributions to our unitholders.
Our distribution network and operations are primarily concentrated in the Gulf Coast region and along the Mississippi
River inland waterway. Weather in these regions is sometimes severe (including tropical storms and hurricanes) and can be a
major factor in our day-to-day operations. Our marine transportation operations can be significantly delayed, impaired or
postponed by adverse weather conditions, such as fog in the winter and spring months and certain river conditions.
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Additionally, our marine transportation operations and our assets in the Gulf of Mexico, including our barges, push boats,
tugboats and terminals, can be adversely impacted or damaged by hurricanes, tropical storms, tidal waves or other related
events. Demand for our lubricants and the diesel fuel we throughput in our Terminalling and Storage segment can be affected if
offshore drilling operations are disrupted by weather in the Gulf of Mexico.
National weather conditions have a substantial impact on the demand for our products. Unusually warm weather
during the winter months can cause a significant decrease in the demand for NGL products. Likewise, extreme weather
conditions (either wet or dry) can decrease the demand for fertilizer. For example, an unusually wet spring can delay planting
of seeds, which can leave insufficient time to apply fertilizer at the planting stage. Conversely, drought conditions can kill or
severely stunt the growth of crops, thus eliminating the need to nurture plants with fertilizer. Any of these or similar conditions
could result in a decline in our net income and cash flow, which would reduce our ability to make distributions to our
unitholders.
If we incur material liabilities that are not fully covered by insurance, such as liabilities resulting from accidents on rivers
or at sea, spills, fires or explosions, our results of operations and ability to make distributions to our unitholders could be
adversely affected.
Our operations are subject to the operating hazards and risks incidental to terminalling and storage, marine
transportation and the distribution of petroleum products and by-products and other industrial products. These hazards and
risks, many of which are beyond our control, include:
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accidents on rivers or at sea and other hazards that could result in releases, spills and other environmental
damages, personal injuries, loss of life and suspension of operations;
leakage of NGLs and other petroleum products and by-products;
fires and explosions;
damage to transportation, terminalling and storage facilities and surrounding properties caused by natural
disasters; and
•
terrorist attacks or sabotage.
Our insurance coverage may not be adequate to protect us from all material expenses related to potential future claims
for personal-injury and property damage, including various legal proceedings and litigation resulting from these hazards and
risks. If we incur material liabilities that are not covered by insurance, our operating results, cash flow and ability to make
distributions to our unitholders could be adversely affected.
Changes in the insurance markets attributable to the effects of Hurricanes Katrina, Rita and Ike and their aftermath
may make some types of insurance more difficult or expensive for us to obtain. As a result, we may be unable to secure the
levels and types of insurance we would otherwise have secured prior to such events. Moreover, the insurance that may be
available to us may be significantly more expensive than our existing insurance coverage.
The price volatility of petroleum products and by-products could reduce our liquidity and results of operations and ability to
make distributions to our unitholders.
We purchase petroleum products and by-products, such as molten sulfur, sulfur derivatives, fuel oils, NGLs,
lubricants, asphalt and other bulk liquids and sell these products to wholesale and bulk customers and to other end users. We
also generate revenues through the terminalling and storage of certain products for third parties. The price and market value of
petroleum products and by-products could be, and has recently been, volatile. Our liquidity and revenues have been adversely
affected by this volatility during periods of decreasing prices because of the reduction in the value and resale price of our
inventory. In addition, our liquidity and costs have been adversely affected during periods of increasing prices because of the
increased costs associated with our purchase of petroleum products and by-products. Future price volatility could have an
adverse impact on our liquidity and results of operations, cash flow and ability to make distributions to our unitholders.
Increasing energy prices could adversely affect our results of operations.
Increasing energy prices 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,
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which could adversely affect our results of operations including net income and cash flows. We cannot assure unitholders that
we will be able to pass along increased operating expenses to our customers.
Increased competition from alternative natural gas transportation and storage options and alternative fuel sources could
have a significant financial impact on us.
Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could
be adversely affected by activities of other interstate and intrastate pipelines and storage facilities that may expand or construct
competing transportation and storage systems. In addition, future pipeline transportation and storage capacity could be
constructed in excess of actual demand and with lower fuel requirements, operating and maintenance costs than our facilities,
which could reduce the demand for and the rates that we receive for our services in particular areas. Further, natural gas also
competes with alternative energy sources available to our customers that are used to generate electricity, such as hydroelectric
power, solar, wind, nuclear, coal and fuel oil.
Demand for our terminalling and storage services is substantially dependent on the level of offshore oil and gas exploration,
development and production activity.
The level of offshore oil and gas exploration, development and production activity historically has been volatile and is
likely to continue to be so in the future. The level of activity is subject to large fluctuations in response to relatively minor
changes in a variety of factors that are beyond our control, including:
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prevailing oil and natural gas prices and expectations about future prices and price volatility;
the cost of offshore exploration for and production and transportation of oil and natural gas;
• worldwide demand for oil and natural gas;
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consolidation of oil and gas and oil service companies operating offshore;
availability and rate of discovery of new oil and natural gas reserves in offshore areas;
local and international political and economic conditions and policies;
technological advances affecting energy production and consumption;
• weather conditions;
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environmental regulation; and
the ability of oil and gas companies to generate or otherwise obtain funds for exploration and production.
We expect levels of offshore oil and gas exploration, development and production activity to continue to be volatile
and affect demand for our terminalling and storage services.
Our NGL and sulfur-based fertilizer products are subject to seasonal demand and could cause our revenues to vary.
The demand for NGLs and natural gas is highest in the winter. Therefore, revenue from our natural gas services
business is higher in the winter than in other seasons. Our sulfur-based fertilizer products experience an increase in demand
during the spring, which increases the revenue generated by this business line in this period compared to other periods. The
seasonality of the revenue from these products may cause our results of operations to vary on a quarter-to-quarter basis and thus
could cause our cash available for quarterly distributions to fluctuate from period to period.
The highly competitive nature of our industry could adversely affect our results of operations and ability to make
distributions to our unitholders.
We operate in a highly competitive marketplace in each of our primary business segments. Most of our competitors in
each segment are larger companies with greater financial and other resources than we possess. We may lose customers and
future business opportunities to our competitors and any such losses could adversely affect our results of operations and ability
to make distributions to our unitholders.
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Our business is subject to compliance with environmental laws and regulations that may expose us to significant costs and
liabilities and adversely affect our results of operations and ability to make distributions to our unitholders.
Our business is subject to federal, state and local environmental laws and regulations governing the discharge of
materials into the environment or otherwise relating to protection of human health, natural resources and the environment.
These laws and regulations may impose numerous obligations that are applicable to our operations, such: as requiring the
acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the
environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and
imposing substantial liabilities on us for pollution resulting from our operations. Numerous governmental authorities, such as
the U.S. Environmental Protection Agency and analogous state agencies, have the power to enforce compliance with these laws
and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Many environmental laws
and regulations can impose joint and several strict liability, and any failure to comply with environmental laws, regulations and
permits may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory and
remedial obligations and, in some circumstances, the issuance of injunctions that can limit or prohibit our operations. The clear
trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment,
and, thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage,
transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position.
The loss or insufficient attention of key personnel could negatively impact our results of operations and ability to make
distributions to our unitholders.
Our success is largely dependent upon the continued services of members of the senior management team of Martin
Resource Management. Those senior officers have significant experience in our businesses and have developed strong
relationships with a broad range of industry participants. The loss of any of these executives could have a material adverse
effect on our relationships with these industry participants, our results of operations and our ability to make distributions to our
unitholders.
We do not have employees. We rely solely on officers and employees of Martin Resource Management to operate and
manage our business. Martin Resource Management operates businesses and conducts activities of its own in which we have no
economic interest. There could be competition for the time and effort of the officers and employees who provide services to our
general partner. If these officers and employees do not or cannot devote sufficient attention to the management and operation of
our business, our results of operation and ability to make distributions to our unitholders may be reduced.
Our loss of significant commercial relationships with Martin Resource Management could adversely impact our results of
operations and ability to make distributions to our unitholders.
Martin Resource Management provides us with various services and products pursuant to various commercial
contracts. The loss of any of these services and products provided by Martin Resource Management could have a material
adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders. Additionally, we
provide terminalling and storage, processing and marine transportation services to Martin Resource Management to support its
businesses under various commercial contracts. The loss of Martin Resource Management as a customer could have a material
adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.
Our business would be adversely affected if operations at our transportation, terminalling and storage and distribution
facilities experienced significant interruptions. Our business would also be adversely affected if the operations of our
customers and suppliers experienced significant interruptions.
Our operations are dependent upon our terminalling and storage facilities and various means of transportation. We are
also dependent upon the uninterrupted operations of certain facilities owned or operated by our suppliers and customers. Any
significant interruption at these facilities or inability to transport products to or from these facilities or to or from our customers
for any reason would adversely affect our results of operations, cash flow and ability to make distributions to our unitholders.
Operations at our facilities and at the facilities owned or operated by our suppliers and customers could be partially or
completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control,
such as:
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catastrophic events, including hurricanes;
environmental remediation;
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labor difficulties; and
disruptions in the supply of our products to our facilities or means of transportation.
Additionally, terrorist attacks and acts of sabotage could target oil and gas production facilities, refineries, processing
plants, terminals and other infrastructure facilities. Any significant interruptions at our facilities, facilities owned or operated
by our suppliers or customers, or in the oil and gas industry as a whole caused by such attacks or acts could have a material
adverse effect on our results of operations, cash flow and ability to make distributions to our unitholders.
Political, regulatory and economic factors may significantly affect our operations, the manner in which we conduct our
business and slow our rate of growth.
Due to changes in the political climate as a result of the outcome of recent state elections and the Congressional
election in the U.S., we cannot predict with any certainty the nature and extent of the changes in federal, state and local laws,
regulations and policy we will face, or the effect of such elections on any pending legislation. Any increased regulation, new
policy initiatives, increased taxes or any other changes in federal law may have an adverse effect on our business, financial
condition and results of operations.
Our marine transportation business would be adversely affected if we do not satisfy the requirements of the Jones Act or if
the Jones Act were modified or eliminated.
The Jones Act is a federal law that restricts domestic marine transportation in the U.S. to vessels built and registered in
the U.S. Furthermore, the Jones Act requires that the vessels be manned and owned by U.S. citizens. If we fail to comply with
these requirements, our vessels lose their eligibility to engage in coastwise trade within U.S. domestic waters.
The requirements that our vessels be U.S. built and manned by U.S. citizens, the crewing requirements and material
requirements of the Coast Guard and the application of U.S. labor and tax laws significantly increase the costs of U.S. flagged
vessels when compared with foreign-flagged vessels. During the past several years, certain interest groups have lobbied
Congress to repeal the Jones Act to facilitate foreign flag competition for trades and cargoes reserved for U.S. flagged vessels
under the Jones Act and cargo preference laws. If the Jones Act were to be modified to permit foreign competition that would
not be subject to the same U.S. government imposed costs, we may need to lower the prices we charge for our services in
order to compete with foreign competitors, which would adversely affect our cash flow and ability to make distributions to our
unitholders.
Our marine transportation business would be adversely affected if the U.S. Government purchases or requisitions any of
our vessels under the Merchant Marine Act.
We are subject to the Merchant Marine Act of 1936, which provides that, upon proclamation by the President of the
U.S. of a national emergency or a threat to the national security, the U.S. Secretary of Transportation may requisition or
purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen
for this purpose). If one of our push boats, tugboats or tank barges were purchased or requisitioned by the U.S. government
under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a
requisition, the fair market value of charter hire. However, if one of our push boats or tugboats is requisitioned or purchased
and its associated tank barge is left idle, we would not be entitled to receive any compensation for the lost revenues resulting
from the idled barge. We also would not be entitled to be compensated for any consequential damages we suffer as a result of
the requisition or purchase of any of our push boats, tugboats or tank barges. If any of our vessels are purchased or
requisitioned for an extended period of time by the U.S. government, such transactions could have a material adverse effect on
our results of operations, cash flow and ability to make distributions to our unitholders.
Regulations affecting the domestic tank vessel industry may limit our ability to do business, increase our costs and
adversely impact our results of operations and ability to make distributions to our unitholders.
The Oil Pollution Act of 1990 ("OPA") provides for the phase out of single-hull vessels and the phase-in of the
exclusive operation of double-hull tank vessels in U.S. waters for barges that carry petroleum products that are regulated under
OPA. Under OPA, substantially all tank vessels that do not have double hulls will be phased out by 2015 and will not be
permitted to enter United States ports or trade in U.S. waters. The phase-out dates vary based on the age of the vessel and
other factors. All but one of our offshore tank barges are double-hull vessels that have no phase out date. We have one single-
hull barge that will be phased out of the petroleum product trade by the year 2015. The phase out of these single-hull vessels
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in accordance with OPA may require us to make substantial capital expenditures, which could adversely affect our operations
and market position and reduce our cash available for distribution.
Our interest rate swap activities may have a material adverse effect on our earnings, profitability, liquidity, cash flows and
financial condition.
We enter into interest rate swap agreements from time to time to manage some of our exposure to interest rate
volatility. These swap agreements involve risks, such as the risk that counterparties may fail to honor their obligations under
these arrangements. In addition, these arrangements may not be effective in reducing our exposure to changes in interest rates.
When we use forward-starting interest rate swaps, there is a risk that we will not complete the long-term borrowing against
which the swap is intended to hedge. If such events occur, our results of operations may be adversely affected.
The industry in which we operate is highly competitive, and increased competitive pressure could adversely affect our
business and operating results.
We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil,
natural gas and petrochemical companies that have greater financial resources and access to supplies of NGLs than we do. In
addition, our customers who are significant producers of natural gas may develop their own gathering, processing and
transportation systems in lieu of using ours. Likewise, our customers who produce NGLs may develop their own systems to
transport NGLs in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to
maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers.
All of these competitive pressures could have a material adverse effect on our business, results of operations, financial
condition and ability to make cash distributions to our unitholders.
Risks Relating to an Investment in the Common Units
Units available for future sales by us or our affiliates could have an adverse impact on the price of our common units or on
any trading market that may develop.
Common units will generally be freely transferable without restriction or further registration under the Securities Act,
except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the
registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise.
Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type
without a vote of the unitholders. Our general partner may also cause us to issue an unlimited number of additional common
units or other equity securities of equal rank with the common units, without unitholder approval, in a number of
circumstances such as:
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the issuance of common units in additional public offerings or in connection with acquisitions that increase
cash flow from operations on a pro forma, per unit basis;
the conversion of subordinated units into common units;
the conversion of units of equal rank with the common units into common units under some circumstances;
or
the conversion of our general partner's general partner interest in us and its incentive distribution rights into
common units as a result of the withdrawal of our general partner.
Our partnership agreement does not restrict our ability to issue equity securities ranking junior to the common units at
any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the
proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of,
common units then outstanding.
Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the
Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and
conditions of our partnership agreement, these registration rights allow the general partner and its affiliates or their assignees
holding any units to require registration of any of these units and to include any of these units in a registration by us of other
units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for
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two years following its withdrawal or removal as a general partner. In connection with any registration of this kind, we will
indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against
any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or
prospectus. Except as described below, the general partner and its affiliates may sell their units in private transactions at any
time, subject to compliance with applicable laws. Our general partner and its affiliates, with our concurrence, have granted
comparable registration rights to their bank group to which their partnership units have been pledged.
The sale of any common or subordinated units could have an adverse impact on the price of the common units or on
any trading market that may develop.
Unitholders have less power to elect or remove management of our general partner than holders of common stock in a
corporation. It is unlikely that our common unitholders will have sufficient voting power to elect or remove our general
partner without the consent of Martin Resource Management and its affiliates.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting
our business and therefore limited ability to influence management's decisions regarding our business. Unitholders did not elect
our general partner or its directors and will have no right to elect our general partner or its directors on an annual or other
continuing basis. Martin Resource Management elects the directors of our general partner. Although our general partner has a
fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders, the directors of our general partner
also have a fiduciary duty to manage our general partner in a manner beneficial to Martin Resource Management and its
shareholders.
If unitholders are dissatisfied with the performance of our general partner, they will have a limited ability to remove
our general partner. Our general partner generally may not be removed except upon the vote of the holders of at least 66 2/3%
of the outstanding units voting together as a single class. As of December 31, 2012, Martin Resource Management owned
19.2% of our total outstanding common limited partner units.
Unitholders' voting rights are further restricted by our partnership agreement provision prohibiting any units held by a
person owning 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees
and persons who acquired such units with the prior approval of our general partner's directors, from voting on any matter. In
addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire
information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or
direction of management.
As a result of these provisions, it will be more difficult for a third party to acquire our partnership without first
negotiating the acquisition with our general partner. Consequently, it is unlikely the trading price of our common units will ever
reflect a takeover premium.
Our general partner's discretion in determining the level of our cash reserves may adversely affect our ability to make cash
distributions to our unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus cash reserves it determines in
its reasonable discretion to be necessary to fund our future operating expenditures. In addition, our partnership agreement
permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to
comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners.
These cash reserves will affect the amount of cash available for distribution to our unitholders.
Unitholders may not have limited liability if a court finds that we have not complied with applicable statutes or that
unitholder action constitutes control of our business.
The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have
not been clearly established in some states. The holder of one of our common units could be held liable in some circumstances
for our obligations to the same extent as a general partner if a court were to determine that:
• we had been conducting business in any state without compliance with the applicable limited partnership
statute or
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•
the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to
approve some amendments to our partnership agreement, or to take other action under our partnership
agreement constituted participation in the “control” of our business.
Our general partner generally has unlimited liability for our obligations, such as our debts and environmental
liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. In addition,
under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of nine years from the
date of the distribution.
Our partnership agreement contains provisions that reduce the remedies available to unitholders for actions that might
otherwise constitute a breach of fiduciary duty by our general partner.
Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to the unitholders.
Our partnership agreement also restricts the remedies available to unitholders for actions that would otherwise constitute
breaches of our general partner's fiduciary duties. For example, our partnership agreement:
•
•
•
•
permits our general partner to make a number of decisions in its “sole discretion.” This entitles our general
partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any
consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;
provides that our general partner is entitled to make other decisions in its “reasonable discretion,” which may
reduce the obligations to which our general partner would otherwise be held;
generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required
vote of unitholders must be “fair and reasonable” to us and that, in determining whether a transaction or
resolution is “fair and reasonable,” our general partner may consider the interests of all parties involved,
including its own; and
provides that our general partner and its officers and directors will not be liable for monetary damages to us,
our limited partners or assignees for errors of judgment or for any acts or omissions if our general partner and
those other persons acted in good faith.
Unitholders are treated as having consented to the various actions contemplated in our partnership agreement and
conflicts of interest that might otherwise be considered a breach of fiduciary duties under applicable state law.
We may issue additional common units without unitholder approval, which would dilute unitholder ownership interests.
Our general partner may also cause us to issue an unlimited number of additional common units or other equity
securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:
•
•
•
•
the issuance of common units in additional public offerings or in connection with acquisitions that increase
cash flow from operations on a pro forma, per unit basis;
the conversion of subordinated units into common units;
the conversion of units of equal rank with the common units into common units under some circumstances;
or
the conversion of our general partner's general partner interest in us and its incentive distribution rights into
common units as a result of the withdrawal of our general partner.
We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders.
Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to
the common units at any time.
The issuance of additional common units or other equity securities of equal or senior rank will have the following
effects:
•
our unitholders' proportionate ownership interest in us will decrease;
34
•
•
•
•
•
the amount of cash available for distribution on a per unit basis may decrease;
because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the
payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
the relative voting strength of each previously outstanding unit will diminish;
the market price of the common units may decline; and
the ratio of taxable income to distributions may increase.
The control of our general partner may be transferred to a third party and that party could replace our current management
team, without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or
substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership
agreement on the ability of the owner of our general partner to transfer its ownership interest in our general partner to a third
party. A new owner of our general partner could replace the directors and officers of our general partner with its' own designees
and control the decisions taken by our general partner.
Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time
or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will
have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of
the remaining common units held by unaffiliated persons at a price not less than the then-current market price. As a result,
unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their
investment. Unitholders may also incur a tax liability upon a sale of their units. No provision in our partnership agreement, or
in any other agreement we have with our general partner or Martin Resource Management, prohibits our general partner or its
affiliates from acquiring more than 80% of our common units. For additional information about this call right and unitholders'
potential tax liability, please see “Risk Factors - Tax Risks - Tax gain or loss on the disposition of our common units could be
different than expected.”
Our common units have a limited trading volume compared to other publicly traded securities.
Our common units are quoted on the Nasdaq Global Select Market (“NASDAQ”) under the symbol “MMLP.”
However, daily trading volumes for our common units are, and may continue to be, relatively small compared to many other
securities quoted on the NASDAQ. The price of our common units may, therefore, be volatile.
Failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could
have a material adverse effect on our unit price.
In order to comply with Section 404 of the Sarbanes-Oxley Act, we periodically document and test our internal control
procedures. Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the effectiveness of our
internal controls over financial reporting addressing these assessments. During the course of our testing we may identify
deficiencies, which we may not be able to address in time to meet the deadline imposed by the Sarbanes-Oxley Act for
compliance with the requirements of Section 404. In addition, if we fail to maintain the adequacy of our internal controls, as
such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude
on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the
Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could have a material adverse
effect on the price of our common units.
Risks Relating to Our Relationship with Martin Resource Management
Cash reimbursements due to Martin Resource Management may be substantial and will reduce our cash available for
distribution to our unitholders.
Under our Omnibus Agreement with Martin Resource Management, Martin Resource Management provides us with
corporate staff and support services on behalf of our general partner that are substantially identical in nature and quality to the
35
services it conducted for our business prior to our formation. The Omnibus Agreement requires us to reimburse Martin
Resource Management for the costs and expenses it incurs in rendering these services, including an overhead allocation to us of
Martin Resource Management's indirect general and administrative expenses from its corporate allocation pool. These
payments may be substantial. Payments to Martin Resource Management will reduce the amount of available cash for
distribution to our unitholders.
Martin Resource Management has conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its
own interests to the detriment of our unitholders.
As of December 31, 2012, Martin Resource Management owned 19.2% of our total outstanding common limited
partner units and a 2% general partnership interest in us and all of our incentive distribution rights. Conflicts of interest may
arise between Martin Resource Management and our general partner, on the one hand, and our unitholders, on the other hand.
As a result of these conflicts, our general partner may favor its' own interests and the interests of Martin Resource Management
over the interests of our unitholders. Potential conflicts of interest between us, Martin Resource Management and our general
partner could occur in many of our day-to-day operations including, among others, the following situations:
• Officers of Martin Resource Management who provide services to us also devote significant time to the
businesses of Martin Resource Management and are compensated by Martin Resource Management for that
time;
• Neither our partnership agreement nor any other agreement requires Martin Resource Management to pursue
a business strategy that favors us or utilizes our assets or services. Martin Resource Management's directors
and officers have a fiduciary duty to make these decisions in the best interests of the shareholders of Martin
Resource Management without regard to the best interests of the unitholders;
• Martin Resource Management may engage in limited competition with us;
• Our general partner is allowed to take into account the interests of parties other than us, such as Martin
Resource Management, in resolving conflicts of interest, which has the effect of reducing its fiduciary duty to
our unitholders;
• Under our partnership agreement, our general partner may limit its liability and reduce its fiduciary duties,
while also restricting the remedies available to our unitholders for actions that, without the limitations and
reductions, might constitute breaches of fiduciary duty. As a result of purchasing units, our unitholders will
be treated as having consented to some actions and conflicts of interest that, without such consent, might
otherwise constitute a breach of fiduciary or other duties under applicable state law;
• Our general partner determines which costs incurred by Martin Resource Management are reimbursable by
us;
• Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for
any services rendered on terms that are fair and reasonable to us or from entering into additional contractual
arrangements with any of these entities on our behalf;
• Our general partner controls the enforcement of obligations owed to us by Martin Resource Management;
• Our general partner decides whether to retain separate counsel, accountants or others to perform services for
us;
• The audit committee of our general partner retains our independent auditors;
•
In some instances, our general partner may cause us to borrow funds to permit us to pay cash distributions,
even if the purpose or effect of the borrowing is to make incentive distributions; and
• Our general partner has broad discretion to establish financial reserves for the proper conduct of our business.
These reserves also will affect the amount of cash available for distribution.
36
Martin Resource Management and its affiliates may engage in limited competition with us.
Martin Resource Management and its affiliates may engage in limited competition with us. For a discussion of the
non-competition provisions of the Omnibus Agreement, please see “Item 13. Certain Relationships and Related Transactions,
and Director Independence.” If Martin Resource Management does engage in competition with us, we may lose customers or
business opportunities, which could have an adverse impact on our results of operations, cash flow and ability to make
distributions to our unitholders.
If Martin Resource Management were ever to file for bankruptcy or otherwise default on its obligations under its credit facility,
amounts we owe under our credit facility may become immediately due and payable and our results of operations could be
adversely affected.
If Martin Resource Management were ever to commence or consent to the commencement of a bankruptcy proceeding
or otherwise defaults on its obligations under its credit facility, its lenders could foreclose on its pledge of the interests in our
general partner and take control of our general partner. If Martin Resources Management no longer controls our general partner,
the lenders under our credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition,
either a judgment against Martin Resource Management or a bankruptcy filing by or against Martin Resource Management
could independently result in an event of default under our credit facility if it could reasonably be expected to have a material
adverse effect on us. If our lenders do declare us in default and accelerate repayment, we may be required to refinance our debt
on unfavorable terms, which could negatively impact our results of operations and our ability to make distributions to our
unitholders. A bankruptcy filing by or against Martin Resource Management could also result in the termination or material
breach of some or all of the various commercial contracts between us and Martin Resource Management, which could have a
material adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.
Tax Risks
The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for
distribution to unitholders.
The anticipated after-tax economic benefit of an investment in us depends largely on our classification as a partnership
for federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, it is
possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes.
In order for us to be classified as a partnership for U.S. federal income tax purposes, more than 90% of our gross income each
year must be “qualifying income” under Section 7704 of the U.S. Internal Revenue Code of 1986, as amended (the “Internal
Revenue Code”). “Qualifying income” includes income and gains derived from the transportation, storage, processing and
marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a
financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets
held for the production of income that otherwise constitutes qualifying income.
Although we intend to meet this gross income requirement, we may not find it possible, regardless of our efforts, to
meet this gross income requirement or may inadvertently fail to meet this gross income requirement. If we do not meet this
gross income requirement for any taxable year and the U.S. Internal Revenue Service (“IRS”) does not determine that such
failure was inadvertent, we would be treated as a corporation for such taxable year and each taxable year thereafter. Moreover,
current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us
to entity-level taxation. At the federal level, members of Congress have considered substantive changes to the existing U.S. tax
laws that would have affected certain publicly traded partnerships. Although the legislation considered would not have
appeared to affect our tax treatment, we are unable to predict whether any such change or other proposals will ultimately be
enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied
retroactively. Any such changes could negatively impact the value of an investment in our common units. At the state level,
because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are
required to pay a Texas margin tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior
year. Imposition of any such tax on us by any other state will reduce the cash available for distribution to you.
If we were treated as a corporation for federal income tax purposes, we would owe federal income tax on our income
at the corporate tax rate, which is currently a maximum of 35%, and would likely owe state income tax at varying rates.
Distributions would generally be taxed again to unitholders as corporate distributions and no income, gains, losses, or
deductions would flow through to unitholders. Because a tax would be imposed upon us as an entity, cash available for
37
distribution to unitholders would be reduced. Treatment of us as a corporation would result in a reduction in the anticipated
cash flow and after-tax return to unitholders and therefore would likely result in a reduction in the value of the common units.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that
subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax
purposes, then the minimum quarterly distribution amount and the target distribution amount will be adjusted to reflect the
impact of that law on us.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units
and the costs of any contest will be borne by our unitholders, debt security holders and our general partner.
The IRS may adopt positions that differ from our counsel's conclusions. It may be necessary to resort to administrative
or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with
some or all our counsel's conclusions or the positions we take. Any contest with the IRS may materially and adversely impact
the market for our common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be
borne directly or indirectly by all of our unitholders, debt security holders and our general partner.
Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.
Unitholders may be required to pay federal income taxes and, in some cases, state, local and foreign income taxes on
their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash
distributions from us equal to their share of our taxable income or even the tax liability that results from the taxation of their
share of our taxable income.
Tax gain or loss on the disposition of our common units could be different than expected.
If our unitholders sell their common units, they will recognize gain or loss equal to the difference between the amount
realized and their tax basis in those common units. Prior distributions in excess of the total net taxable income unitholders
were allocated for a common unit, which decreased unitholder tax basis in that common unit, will, in effect, become taxable
income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price
they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may
be ordinary income to our unitholders. Should the IRS successfully contest some positions we take, our unitholders could
recognize more gain on the sale of units than would be the case under those positions without the benefit of decreased income
in prior years. In addition, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash they
receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax
consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts
(known as IRAs), Keogh plans and other retirement plans, regulated investment companies, real estate investment trusts,
mutual funds and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to
organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business income
and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable
effective tax rate, and non-U.S persons will be required to file U.S. federal income tax returns and pay tax on their share of our
taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisor regarding their investment in our
common units.
We treat a purchaser of our common units as having the same tax benefits without regard to the seller's identity. The IRS
may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted
depreciation positions that may not conform to all aspects of the Treasury regulations. Any position we take that is inconsistent
with applicable Treasury regulations may have to be disclosed on our federal income tax return. This disclosure increases the
likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders. A successful IRS
challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect
the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the
value of our common units or result in audit adjustments to our unitholders' tax returns.
38
Unitholders may be subject to state, local and foreign taxes and return filing requirements as a result of investing in our
common units.
In addition to federal income taxes, unitholders may be subject to other taxes, such as state, local and foreign income
taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in
which we do business or own property. Unitholders may be required to file state, local and foreign income tax returns and pay
state and local income taxes in some or all of the various jurisdictions in which we do business or own property and may be
subject to penalties for failure to comply with those requirements. We own property and/or conduct business in Alabama,
Arkansas, California, Georgia, Florida, Illinois, Louisiana, Mississippi, Nebraska, Texas and Utah. We may do business or own
property in other states or foreign countries in the future. It is the unitholder's responsibility to file all federal, state, local and
foreign tax returns. Our counsel has not rendered an opinion on the state, local or foreign tax consequences of an investment in
our common units.
There are limits on the deductibility of our losses that may adversely affect our unitholders.
There are a number of limitations that may prevent unitholders from using their allocable share of our losses as a deduction
against unrelated income. In cases when our unitholders are subject to the passive loss rules (generally, individuals and closely-
held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset
income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder
disposes of its entire investment in us in a fully taxable transaction with an unrelated party. A unitholder's share of our net passive
income may be offset by unused losses from us carried over from prior years but not by losses from other passive activities,
including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses
by a unitholder include the at-risk rules and the prohibition against loss allocations in excess of the unitholder's tax basis in its
units.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial
or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our
common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the
U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more
difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not
taxable as a corporation (referred to as the “Qualifying Income Exception”), affect or cause us to change our business activities,
affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely
affect an investment in our common units. For example, in response to certain events that occurred in previous years, members
of Congress have considered substantive changes to the existing U.S. tax laws including the definition of qualifying income
under Section 7704(d) of the Internal Revenue Code and the treatment of certain types of income earned from profits interests
in partnerships. Although the legislation considered would not have appeared to affect our tax treatment, we are unable to
predict whether any such change or other proposals will ultimately be enacted. Moreover, President Obama has recently urged
Congress to consider tax reform pursuant to a Joint Report by The White House and The Department of the Treasury titled The
President's Framework for Business Tax Reform released February 2012. Among the President's proposals is to establish
greater parity between large corporations and large non-corporate counterparts which could include entity level taxation for
publicly traded partnerships, including us. It is possible that these efforts could result in changes to the existing U.S. tax laws
that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes or other proposals
will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
The sale or exchange of 50% or more of our capital and profits interests during any 12-month period will result in the termination
of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or
more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things,
result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year.
For purposes of determining whether the 50% threshold is met, multiple sales of the same units are counted only once. Our
termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of
a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also
result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination.
Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we
would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and
could be subject to penalties if we are unable to determine that a termination occurred. The IRS recently announced a relief
39
procedure whereby, if a publicly traded partnership that has technically terminated requests and the IRS grants special relief,
among other things, the partnership will be allowed to provide only a single Schedule K-1 to unitholders for the tax year in
which the termination occurred.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based
upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred.
The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among
our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month
based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is
transferred. The use of this proration method may not be permitted under existing Treasury regulations. Recently, however, the
U.S. Treasury Department issued proposed Treasury regulations that provide a safe harbor pursuant to which publicly traded
partnerships may use a similar monthly convention to allocate tax items among transferor and transferee unitholders.
Nonetheless, the proposed Treasury regulations do not specifically authorize the use of the proration method we have adopted.
Therefore, the use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our
counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury
regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our
unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of
those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of
the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as
having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during
the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during
the period of the loan to the short seller any of our income, gain, loss or deduction with respect to those units may not be
reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as
ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are
loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners
and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account
agreements to prohibit their brokers from borrowing their units.
40
Item 1B. Unresolved Staff Comments
None.
Item 2.
Properties
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.
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 proceeding is included in Item 8. Financial Statements and Supplementary Data, Note 21. Commitments and
Contingencies, and is incorporated herein by reference.
Item 4. Mine Safety Disclosures
Not applicable.
41
PART II
Item 5. Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Our common units are traded on the NASDAQ under the symbol “MMLP.” As of March 1, 2013 there were
approximately 100 holders of record and approximately 24,166 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 and subordinated units during those periods:
Fiscal 2012:
March 31, 2012
June 30, 2012
September 30, 2012
December 31, 2012
Fiscal 2011:
March 31, 2011
June 30, 2011
September 30, 2011
December 31, 2011
Quarters Ended
Quarters Ended
Common Units
High
Low
37.91
35.75
35.65
36.72
$
$
$
$
32.77
29.46
32.39
30.03
Distributions Declared per
Unit
Common
0.7625
0.7625
0.7625
0.7700
$
$
$
$
Subordinated1
—
$
—
$
—
$
—
$
Common Units
High
Low
42.35
41.44
40.05
36.22
$
$
$
$
37.21
36.24
28.43
30.06
Distributions Declared per
Unit
Common
0.7600
0.7625
0.7625
0.7625
$
$
$
$
Subordinated1
—
$
—
$
—
$
—
$
$
$
$
$
$
$
$
$
(1) All of our original 4,253,362 subordinated units which were issued upon the formation of the Partnership and subsequently
converted into common units on a one-for-one basis received distributions prior to their conversion. The 889,444 subordinated
units issued to Cross Oil Refining & Marketing, Inc. in connection with the November 2009 acquisition of the Smackover
refining assets converted to common units in November 2011 and began receiving cash distributions in February 2012.
On March 1, 2013, the last reported sales price of our common units as reported on the NASDAQ was $34.77 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.
In February 2011, in connection with our public offering of 1,874,500 common units, our general partner contributed
$1.5 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
42
the next $18.0 million in incentive distributions that it would otherwise be entitled to receive. As of March 4, 2013, the amount
of incentive distributions the general partner has foregone is $3.4 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.”
43
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, 2012, 2011, 2010, 2009 and 2008 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 and Combined Financial Statements and Notes thereto and “Management’s Discussion and Analysis
of Financial Condition and Results of Operations” included elsewhere in this document.
44
Income Statement Data:
Revenues
Cost of product sold
Operating expenses
Selling, general, and administrative
Depreciation and amortization
Total costs and expenses
Other operating income (loss)
Operating income
Equity in earnings (loss) of unconsolidated
entities
Gain from ownership change in
unconsolidated entity
Gain from contribution of assets to
Redbird
Interest expense
Debt Prepayment Premium
Other, net
Income before income taxes
Income taxes
Income from continuing operations
Income from discontinued operations, net
of tax
Net income
Net income per limited partner unit –
continuing operations
Net income per limited partner unit –
discontinued operations
Net income per limited partner unit
Weighted average limited partner units
Balance Sheet Data (at Period End):
Total assets
Due to affiliates
Long-term debt
Partners' capital (owners' equity)
Cash Flow Data:
Net cash flow provided by (used in):
Operating activities
Investing activities
Financing activities
Other Financial Data:
Maintenance capital expenditures
Expansion capital expenditures
Total capital expenditures
Cash dividends per common unit (in
dollars)
$
$
$
$
$
$
$
20121
20111
20101
(Dollars in thousands, except per unit amounts)
20091
$
$
1,490,361
1,197,531
151,020
25,494
42,063
1,416,108
(418)
73,835
1,242,490
997,972
137,685
20,531
40,276
1,196,464
1,326
47,352
(1,113)
(4,752)
—
—
—
(30,665)
(2,470)
1,092
40,679
(3,557)
37,122
—
(26,781)
—
420
16,239
(2,872)
13,367
880,115
665,086
113,426
16,865
36,884
832,261
228
48,082
2,536
6,413
—
(35,322)
—
385
22,094
(2,622)
19,472
20081
1,162,749
941,266
123,308
17,887
31,895
1,114,356
209
48,602
$
$
651,174
448,799
113,074
16,005
36,183
614,061
6,025
43,138
(5,053)
(2,160)
3,028
—
(20,357)
—
443
21,199
(3,524)
17,675
—
24,271
(23,131)
—
3,839
51,421
(2,496)
48,925
16,816
65,741
1.65
1.07
2.72
64,865
101,987
$
9,392
22,759
$
8,061
27,533
$
5,268
22,943
$
1.32
$
0.57
$
0.25
$
0.86
$
2.64
3.96
$
0.35
0.92
$
0.38
0.63
$
0.31
1.17
$
23,361,551
19,545,427
17,525,089
14,680,807
14,529,826
$
$
1,012,996
3,316
474,992
357,962
1,069,108
74,654
458,941
337,187
$
864,425
24,578
372,862
327,960
$
739,161
20,073
304,372
306,594
763,211
32,350
295,000
287,282
32,678
(15,036)
(12,746)
91,362
(202,655)
100,179
39,178
(91,016)
57,262
48,673
(41,600)
(9,100)
93,080
(54,071)
(35,139)
9,195
85,549
94,744
$
10,947
67,540
78,487
$
4,653
14,916
19,569
$
7,601
29,653
37,254
$
17,998
117,929
135,927
3.06
$
3.05
$
3.00
$
3.00
$
2.91
45
1We acquired all of the remaining Class A interests of Redbird Gas Storage LLC ("Redbird") and certain specialty lubricant
product blending and packaging assets ("Blending and Packaging Assets") of Cross Oil Refining and Marketing, Inc. ("Cross")
from Martin Resource Management in October 2012. 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 acquisition of the
Redbird Class A interests and the Blending and Packaging Assets are recorded at amounts based on the historical carrying value
of the assets at that date, and we are required to update our historical financial statements to include the activities of the assets
as of the date of common control. Our historical financial statements for 2012, 2011, 2010, 2009 and 2008, 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 we owned these assets for these periods.
46
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 U.S. Gulf Coast
region. Our four primary business lines include:
• Terminalling and storage services for petroleum and by-products;
• Natural gas services;
•
Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution; and
• Marine transportation services for petroleum products and by-products.
The petroleum products and by-products we collect, transport, store and market are produced primarily by major and
independent oil and gas companies who often turn to third parties, such as us, for the transportation and disposition of these
products. In addition to these major and independent oil and gas companies, our primary customers include independent
refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. We operate
primarily in the Gulf Coast region of the U.S. 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. As of December 31,
2012, Martin Resource Management owned 19.2% of our total outstanding common limited partner units and a 2% general
partnership interest in us and all of our incentive distribution rights.
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 growth capital expenditures
primarily in our Terminalling and Storage and Natural Gas Services segments.
During the past year, we continued to experience positive market dynamics in our Terminalling and Storage segment.
This is in large part to the rapid development of the Eagle Ford shale basin in South Texas and its need for off-take
infrastructure. In addition, we purchased certain specialty lubricant blending and packaging assets as further integration into
our existing assets.
We also purchased all remaining Class A interests in Redbird. Redbird was formerly a joint venture between us and
Martin Resource Management formed in 2011 to invest in Cardinal, a joint venture between Martin Resource Management and
Energy Capital Partners ("ECP") that is focused on the development, construction, operation and management of natural gas
storage facilities in northern Louisiana and Mississippi. As a result of this transaction, Redbird is now a wholly-owned
subsidiary of us. We believe natural gas storage assets are ideally suited for the master limited partnership structure.
47
Recent Acquisitions
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 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 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. 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.
Acquisition of Redbird Interests. On October 2, 2012, we acquired the remaining Class A interests in Redbird for
$150.0 million in cash from Martin Underground Storage, Inc., a subsidiary of Martin Resource Management. Redbird was
formed by us and Martin Resource Management in 2011 to invest in Cardinal. Cardinal is a joint venture between Redbird and
ECP that is focused on the development, construction, operation and management of natural gas storage facilities across
northern Louisiana and Mississippi.
Acquisition of Specialty Lubricant Blending and Product 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.
Other Developments
Litigation Settlement. On October 2, 2012, we announced that the ongoing litigation and disputes since May 2008
involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The
settlement, among other things, provided for a resolution of all the lawsuits and disputes. In connection with the settlement,
Martin Resource Management transferred 1,500,000 of our common units to KCM, LLC. Martin Resource Management
continues to own 5,093,267 of our common units.
Amendment No. 2 to Omnibus Agreement. In connection with the purchase of the Blending and Packaging Assets
acquired from Cross, on October 2, 2012, we entered into Amendment No. 2 to to our Omnibus Agreement (the “Amendment”)
with Martin Resource Management, Martin Midstream GP LLC (the "General Partner"), and Martin Operating Partnership L.P.
(the "Operating Partnership"). The Amendment allows us to provide certain products and services to Martin Resource
Management under the Omnibus Agreement by amending the definition of the term “Business” to reflect the operation of the
blending and packaging assets acquired by the Partnership pursuant to the purchase agreement.
Amendment No. 3 to the Second Amendment and Restated Agreement of Limited Partnership. In conjunction with the
Redbird purchase agreement, on October 2, 2012, the 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 the 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.
Disposition of Natural Gas Gathering Assets. On June 18, 2012, we and a subsidiary of CenterPoint Energy Inc.
(NYSE: CNP) (“CenterPoint”), entered into a definitive agreement under which CenterPoint would acquire our East Texas and
Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas ("Prism Gas"), which include Woodlawn
Pipeline Co., Inc ("Woodlawn"), the Darco Gathering System, the Harrison Gathering System, and the East Harrison Pipeline
System, and other natural gas gathering and processing assets also owned by us, for cash in a transaction valued at
approximately $275.0 million excluding any transaction costs and purchase price adjustments. The asset sale included our 50%
operating interest in Waskom Gas Processing Company (“Waskom”). A subsidiary of CenterPoint owned the other 50% percent
interest. On July 31, 2012, we completed the sale of our East Texas and Northwest Louisiana natural gas gathering and
processing assets for net cash proceeds of $273.3 million. Additionally, on September 18, 2012, we completed the sale of our
interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy, LLC (“PIPE”) to a
private investor group for $1.5 million in cash (the assets described above, collectively, are herein referred to as the "Prism
Assets"). Prism Gas Systems I, L.P. and all of its subsidiaries were liquidated and dissolved prior to December 31, 2012.
Public 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.
48
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.
Debt Financing Activities. On May 24, 2012, we redeemed $25.0 million of the Senior 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 May 10, 2012, we increased the maximum amount of borrowings and
letters of credit available under our revolving credit facility from $375.0 million to $400.0 million. See subsequent events
section in Item 1. "Business" for discussion surrounding our February 2013 issuance of senior unsecured notes.
For a more detailed discussion regarding our credit facility, see “Description of Our Long-Term Debt—Credit
Facility” within this Item.
Critical Accounting Policies
Our discussion and analysis of our financial condition and results of operations are based on the historical
consolidated and condensed financial statements included elsewhere herein. We prepared these financial statements in
conformity with generally accepted accounting principles. The preparation of these financial statements required us to make
estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and
the reported amounts of revenues and expenses during the reporting periods. We based our estimates on historical experience
and on various other assumptions we believe to be reasonable under the circumstances. Our results may differ from these
estimates. Currently, we believe that our accounting policies do not require us to make estimates using assumptions about
matters that are highly uncertain. However, we have described below the critical accounting policies that we believe could
impact our consolidated and condensed financial statements most significantly.
You should also read Note 2, “Significant Accounting Policies” in Notes to Consolidated Financial Statements
contained in this annual report on Form 10-K. Some of the more significant estimates in these financial statements include the
amount of the allowance for doubtful accounts receivable and the determination of the fair value of our reporting units as it
relates to our annual goodwill evaluation.
Derivatives
All derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value
and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative
qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item
through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.
Our hedging policy allows us to use hedge accounting for financial transactions that are designated as hedges. Derivative
instruments not designated as hedges or hedges that become ineffective are being marked to market with all market value
adjustments being recorded in the consolidated statements of operations.
Product Exchanges
We enter into product exchange agreements with third parties whereby we agree to exchange NGLs and sulfur with
third parties. We record the balance of exchange products due to other companies under these agreements at quoted market
product prices and the balance of exchange products due from other companies at the lower of cost or market. Cost is
determined using the first-in, first-out (“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” on the Consolidated Statement of Operations.
Revenue Recognition
Revenue for our four operating segments is recognized as follows:
Terminalling and storage - Revenue is recognized for storage contracts based on the contracted monthly tank fixed
fee. For throughput contracts, revenue is recognized based on the volume moved through our terminals at the contracted rate.
49
For our tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes
moved through the facility. When lubricants and drilling fluids are sold by truck 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 our NGL
customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline,
we recognize NGL distribution revenue when the customer receives the product from either the storage facility or pipeline.
Sulfur services - Revenue from sulfur product sales is recognized when the customer takes title to the product at our
plant or the customer facility. Revenues 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.
Equity Method Investments
We use the equity method of accounting for investments in unconsolidated entities where the ability to exercise
significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and
advances plus the our share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and
distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to
property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity
method goodwill is not amortized but is evaluated for impairment, annually. Under certain provisions of the Financial
Accounting Standards Board ("FASB") Accounting Standards Codification ("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 our operating income.
We own 100% of the Class A and Class B equity interests in Redbird. Redbird, as of December 31, 2012 and 2011,
owned a 41.28% and 40.08% interest in Cardinal, respectively. We own an unconsolidated 50% interest in Caliber Gathering,
LLC ("Caliber").
Goodwill
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. We are required to identify our reporting units and determine the carrying value of each
reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. We are required to
determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the
carrying amount of a reporting unit exceeds the fair value of the reporting unit, we would be required to perform the second
step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired.
All four of our “reporting units”, terminalling and storage, natural gas services, sulfur services and marine
transportation, contain goodwill.
We have historically performed our annual impairment testing of goodwill and indefinite-lived intangible assets as of
September 30 of each year. During the third quarter of fiscal 2011, we changed the annual impairment testing date from
September 30 to August 31. We believe this change, which represents a change in the method of applying an accounting
principle, is preferable in the circumstances as the earlier date provides additional time prior to our quarter-end to complete the
goodwill impairment testing and report the results in our quarterly report on Form 10-Q.
We have performed the annual impairment tests as of August 31, 2012, August 31, 2011, and September 30, 2010, and
we have determined fair value in each reporting unit based on the weighted average of three valuation techniques: (i) the
discounted cash flow method; (ii) the guideline public company method; and (iii) the guideline transaction method. At August
31, 2012, August 31, 2011, and September 30, 2010, the estimated fair value of each of our four reporting units was in excess
of its carrying value, resulting in no impairment.
No triggering events occurred that would cause us to perform an impairment test at either December 31, 2012 or 2011.
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
50
be limited to, varying commodity prices, volume changes and operating costs due to market conditions and/or alternative
providers of services.
Environmental Liabilities and Litigation
We have not historically experienced circumstances requiring us to account for environmental remediation obligations.
If such circumstances arise, we would estimate remediation obligations utilizing a remediation feasibility study and any other
related environmental studies that we may elect to perform. We would record changes to our estimated environmental liability
as circumstances change or events occur, such as the issuance of revised orders by governmental bodies or court or other
judicial orders and our evaluation of the likelihood and amount of the related eventual liability.
Because the outcomes of both contingent liabilities and litigation are difficult to predict, when accounting for these
situations, significant management judgment is required. Amounts paid for contingent liabilities and litigation have not had a
materially adverse effect on our operations or financial condition, and we do not anticipate they will in the future.
Allowance for Doubtful Accounts
In evaluating the collectability of our accounts receivable, we assess a number of factors, including a specific
customer's ability to meet its financial obligations to us, the length of time the receivable has been past due and historical
collection experience. Based on these assessments, we record specific and general reserves for bad debts to reduce the related
receivables to the amount we ultimately expect to collect from customers.
Our management closely monitors potentially uncollectible accounts. Estimates of uncollectible amounts are revised
each period, and changes are recorded in the period they become known. If there is a deterioration of a major customer's
creditworthiness or actual defaults are higher than the historical experience, management's estimates of the recoverability of
amounts due us could potentially be adversely affected. These charges have not had a materially adverse effect on our
operations or financial condition.
Asset Retirement Obligations
We recognize and measure our asset and conditional asset retirement obligations and the associated asset retirement
cost upon acquisition of the related asset and based upon the estimate of the cost to settle the obligation at its anticipated future
date. The obligation is accreted to its estimated future value and the asset retirement cost is depreciated over the estimated life
of the asset.
Estimates of future asset retirement obligations include significant management judgment and are based on projected
future retirement costs. Such costs could differ significantly when they are incurred. Revisions to estimated asset retirement
obligations can result from changes in retirement cost estimates due to surface repair, and labor and material costs, revisions to
estimated inflation rates and changes in the estimated timing of abandonment. For example, we do not have access to natural
gas reserve information related to our gathering systems to estimate when abandonment will occur.
Our Relationship with Martin Resource Management
Martin Resource Management directs our business operations through its ownership and control of our general partner
and under 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, 2012, 2011 and 2010, the Conflicts Committee of our general partner approved reimbursement
amounts of $7.6 million, $4.8 million and $3.8 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, sulfuric acid and marine fuel from Martin Resource
51
Management. All of these services and goods are purchased and sold pursuant to the terms of a number of agreements between
us and Martin Resource Management.
For a more comprehensive discussion concerning the Omnibus Agreement and the other agreements that we have
entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions, and
Director Independence – Agreements.”
Results of Operations
The results of operations for the years ended December 31, 2012, 2011, and 2010 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, 2012, 2011,
and 2010.
The natural gas services segment information below excludes the discontinued operations of the Prism Assets for all
periods.
Operating
Revenues
Revenues
Intersegment
Eliminations
Operating
Revenues
after
Eliminations
Operating
Income
(loss)
Operating
Income
Intersegment
Eliminations
Operating
Income (loss)
after
Eliminations
(In thousands)
Year Ended December 31,
2012:
Terminalling and storage
$
322,175
$
(4,652) $
317,523
$
27,944
$
Natural gas services
Sulfur services
Marine transportation
Indirect selling, general and
administrative
Total
Year Ended December 31,
2011:
Terminalling and storage
Natural gas services
Sulfur services
Marine transportation
Indirect selling, general and
administrative
Total
Year Ended December 31,
2010:
825,506
261,584
88,815
—
1,498,080
283,175
611,749
275,044
83,971
$
$
$
$
—
—
(3,067)
825,506
261,584
85,748
—
(7,719) $
—
1,490,361
(4,414) $
—
—
(7,035)
278,761
611,749
275,044
76,936
$
$
13,924
37,262
6,751
(12,046)
73,835
21,567
6,267
27,651
731
$
$
—
1,253,939
$
$
—
(11,449) $
—
1,242,490
$
(8,864)
47,352
$
Terminalling and storage
$
199,744
$
(4,354) $
195,390
$
21,810
$
442,005
165,078
82,635
—
—
(4,993)
442,005
165,078
77,642
6,780
15,886
9,992
Natural gas services
Sulfur services
Marine transportation
Indirect selling, general and
administrative
Total
(2,541) $
1,471
4,647
(3,577)
25,403
15,395
41,909
3,174
—
— $
(12,046)
73,835
(948) $
1,220
6,944
(7,216)
—
— $
20,619
7,487
34,595
(6,485)
(8,864)
47,352
(1,776) $
964
4,280
(3,468)
20,034
7,744
20,166
6,524
—
889,462
$
$
—
(9,347) $
—
880,115
$
(6,386)
48,082
$
—
— $
(6,386)
48,082
52
Our results of operations are discussed on a comparative basis below. There are certain items of income and expense
which we do not allocate on a segment basis. These items, including equity in earnings (loss) of unconsolidated entities, interest
expense, and indirect selling, general and administrative expenses, are discussed after the comparative discussion of our results
within each segment.
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Our total revenues before eliminations were $1,498.1 million for the year ended December 31, 2012 compared to
$1,253.9 million for the year ended December 31, 2011 an increase of $244.2 million, or 19%. Our operating income before
eliminations was $73.8 million for the year ended December 31, 2012 compared to $47.4 million for the year ended December 31,
2011 an increase of $26.4 million, or 56%.
The results of operations are described in greater detail on a segment basis below.
Terminalling and Storage Segment
The following table summarizes our results of operations in our terminalling and storage segment.
Revenues:
Services
Products
Total revenues
Cost of products sold
Operating expenses
Selling, general and administrative expenses
Depreciation and amortization
Other operating loss
Operating income
Years Ended December 31,
2012
2011
(In thousands)
$
$
$
94,895
227,280
322,175
81,697
201,478
283,175
202,966
63,499
4,671
22,976
28,063
(119)
27,944
$
182,928
54,992
3,343
19,814
22,098
(531)
21,567
Revenues. Our terminalling and storage revenues increased $39.0 million, or 14%, for the year ended December 31, 2012
compared to the year ended December 31, 2011. The increase is comprised of service revenue of $13.2 million and $25.8 million
of product revenue. The service revenue increase is due principally to $12.4 million related to two significant projects, one of
which commenced operations in 2012. The other project became operational in late 2011. The increase in product revenue is
primarily due to $20.0 million in increased revenues associated with the Blending and Packaging Assets acquired from Cross.
Higher volumes accounted for $12.5 million of this increase, and higher prices provided the remaining $7.5 million increase. The
remaining product sales increase is due primarily to the conversion of a consigned product delivery agreement to a purchase and
sale arrangement.
Cost of products sold. Our cost of products increased $20.0 million, or 11%, for the year ended December 31, 2012
compared to the year ended December 31, 2011. This increase consists of $16.7 attributable to the Blending and Packaging Assets.
This increase is comprised of $11.3 million due to higher volumes and $5.4 million due to higher costs. The remaining increase is
due principally to the conversion of a consigned product delivery agreement to a purchase and sale arrangement.
Operating Expenses. Operating expenses increased $8.5 million, or 15%, for the year ended December 31, 2012 as
compared to the year ended December 31, 2011. The increase includes $6.3 million attributable to new projects placed in service
in 2012 and 2011. The remainder of the increase consists primarily of higher repair and maintenance costs of $1.4 million and
compensation expense of $0.6 million.
Selling, general and administrative expenses. Selling, general, and administrative expenses increased $1.3 million, or
40% for the year ended December 31, 2012 compared to the year ended December 31, 2011. An increase of $1.0 million is due to
53
increased marketing expenses related to the Blending and Packaging Assets. The remaining $0.3 million is primarily attributable to
increased compensation expense.
Depreciation and amortization. Depreciation and amortization increased $3.2 million, or 16%, for the year ended
December 31, 2012 compared to the year ended December 31, 2011. The increase is fully attributable to capital expenditures for
new projects.
Other operating loss. Other operating loss for the year ended December 31, 2012 and the year ended December 31, 2011
represents losses on the disposal of property, plant and equipment.
In summary, our terminalling and storage operating income increased $6.4 million, or 30%, for the year ended December
31, 2012 compared to the year ended December 31, 2011.
Natural Gas Services Segment
The following table summarizes our results of operations in our natural gas services segment.
Revenues
Cost of products sold
Operating expenses
Selling, general and administrative expenses
Depreciation and amortization
Operating income
NGLs Volumes (Bbls)
Years Ended December 31,
2012
2011
(In thousands)
$
$
825,506
803,195
3,550
4,236
601
13,924
$
$
611,749
600,034
2,994
1,876
578
6,267
12,080
7,866
Revenues. Our natural gas services revenues increased $213.8 million, or 35% for the year ended December 31, 2012,
compared to the same period of 2011. This is primarily attributable to increased sale volumes, somewhat offset by decreased sales
prices. NGL sales volumes for the year ended December 31, 2012 increased 54% compared to the same period of 2011, resulting
in a positive impact on revenues of $288.2 million. Our NGL average sales price per barrel for the year ended December 31, 2012,
decreased $9.44, or 12% compared to the same period of 2011, resulting in a decrease in revenue of $76.1 million.
Cost of products sold. Our cost of products sold increased $203.2 million, or 34%, for the year ended December 31,
2012, compared to the same period of 2011. The percentage increase in NGL cost of products sold was slightly lower than our
percentage increase in NGL revenues, resulting in increased margins per barrel of 24% for the year ended December 31, 2012,
compared to the same period of 2011.
Operating expenses. Operating expenses increased $0.6 million, or 19%, for the year ended December 31, 2012
compared to the same period of 2011. This is primarily due to 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 $2.4 million, or
126%, for the year ended December 31, 2012, as compared to the same period of 2011. This is primarily due to 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 for the year ended December 31,
2012, as compared to the same period of 2011.
In summary, our natural gas services operating income increased $7.7 million, or 122%, for the year ended December 31,
2012, compared to the same period of 2011.
54
Sulfur Services Segment
The following table summarizes our results of operations in our sulfur segment.
Revenues:
Services
Products
Total revenues
Cost of products sold
Operating expenses
Selling, general and administrative expenses
Depreciation and amortization
Other operating income (loss)
Operating income
Sulfur (long tons)
Fertilizer (long tons)
Sulfur services volumes (long tons)
Years Ended December 31,
2012
2011
(In thousands)
$
$
$
11,702
249,882
261,584
195,314
17,404
3,975
7,371
37,520
(258)
37,262
1,066.1
306.1
1,372.2
$
11,400
263,644
275,044
220,059
19,328
3,361
6,725
25,571
2,080
27,651
1,314.5
271.8
1,586.3
Revenues. Our total sulfur services revenues decreased $13.5 million, or 5%, for the year ended December 31, 2012,
compared to the year ended December 31, 2011. Product revenue decreased $13.8 million, or 5%, for the year ended December
31, 2012, compared to the year ended December 31, 2011. A revenue decrease of $35.6 million was the result of a 13% reduction
in volumes, offset partially by $21.8 of increased revenue generated by a 10% increase in price. The volume reduction was
primarily related to the conversion of a buy/sell contract with a major customer to a fee-based handling contract. Service revenues
remained basically the same for both years.
Cost of products sold. Our cost of products sold decreased $24.7 million, or 11%, for the year ended December 31, 2012,
compared to the year ended December 31, 2011. The percentage decrease in cost of products sold was higher than our percentage
decrease in revenues, resulting in an increase in our margin per ton of 39%.
Operating expenses. Our operating expenses decreased $1.9 million, or 10%, for the year ended December 31, 2012,
compared to the year ended December 31, 2011. This was primarily a result of decreased outside towing expenses of $1.8 million
and $0.4 million in workers compensation claims. Offsetting that decrease is an increase of $0.3 million in marine fuel expense.
Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.6 million, or
18%, for the year ended December 31, 2012, compared to the year ended December 31, 2011. This increase is related to an
increase of $0.3 million in allocated overhead expense and $0.3 million in compensation expense.
Depreciation and amortization. Depreciation and amortization expense increased $0.6 million, or 10%, for the year
ended December 31, 2012, compared to the year ended December 31, 2011. This increase is a result of capital expenditures made
during the past twelve months.
Other operating income (loss). Other operating income (loss) was ($0.3) million for the year ended December 31, 2012,
compared to $2.1 million for the year ended December 31, 2011. The change is due primarily to 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.
In summary, our sulfur operating income increased $9.6 million, or 35%, for the year ended December 31, 2012,
compared to the year ended December 31, 2011.
55
Marine Transportation Segment
The following table summarizes our results of operations in our marine transportation segment.
Years Ended December 31,
2012
2011
Revenues
Operating expenses
Selling, general and administrative expenses
Depreciation and amortization
Other operating (loss)
Operating income
$
$
$
(In thousands)
88,815
70,342
566
11,115
6,792
(41)
6,751
$
83,971
66,771
3,087
13,159
954
(223)
731
Revenues. Our marine transportation revenues increased $4.8 million, or 6%, for the year ended December 31, 2012,
compared to the same period of 2011. This increase was primarily a result of an increase in our offshore marine operations
somewhat offset by a decrease in our inland marine operations. Offshore revenues increased $5.5 million due to increased demand
for our two offshore tows, which operate in the spot market. Revenue from inland operations decreased $2.8 million due to a
reduction in utilization. Ancillary revenue, primarily fuel, increased $2.2 million.
Operating expenses. Operating expenses increased $3.6 million, or 5%, for the year ended December 31, 2012, compared
to the same period of 2011. This increase in operating expenses is due to increased fuel costs of $2.4 million, compensation
expense of $1.3 million, repair and maintenance expense of $0.9 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 $2.5 million, or
82%, for the year ended December 31, 2012, compared to the same period of 2011. This reduction was attributable to 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 $2.0 million, or 16%, for the year ended
December 31, 2012, compared to the same period of 2011. This decrease was primarily a result of certain assets becoming fully
depreciated and a reduction in depreciation from disposal of equipment made in 2012. These reductions are somewhat offset by
capital expenditures made in 2012.
Other operating income. Other operating income for the years ended December 31, 2012 and 2011 represents losses on
asset dispositions.
In summary, our marine transportation operating income increased $6.0 million for the year ended December 31, 2012
compared to the same period of 2011.
Equity in Earnings of Unconsolidated Entities
Equity in losses from unconsolidated entities was ($1.1) million for the year ended December 31, 2012, compared to
($4.8) million for the year ended December 31, 2011. This $3.7 million decrease in equity in loss is partially attributable to a $2.2
million milestone payment in 2012, while no milestone payment was received in 2011. The positive milestone impact is offset
somewhat by ($0.2) million in loss associated with investments entered into during 2012. The remaining $1.7 million decrease in
equity in loss is due to the improved operating results of Cardinal in 2012.
Interest Expense
Our interest expense for all operations was $30.1 million for the year ended December 31, 2012 compared to $26.8
million for the same period of 2011, an increase of $3.3 million, or 15%. This increase over 2011 was primarily due to fees
received related to the termination of all our interest rate swaps of $2.8 million, reducing interest expense, during third quarter
56
2011 and decreases in interest expense related to the difference between the fixed rate and the floating rate of interest on the
interest rate swaps.
Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses were $12.0 million for the year ended December 31, 2012 compared
to $8.9 million for 2011, an increase of $3.1 million or 35%.
Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses for
services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general
office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource
Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management
personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for
allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation
of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of
the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most
accurate or appropriate method of allocation 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.
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, 2012
and 2011, the Conflicts Committee of our general partner approved reimbursement amounts of $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.
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
Our total revenues before eliminations were $1,253.9 million for the year ended December 31, 2011 compared to $889.5
million for the year ended December 31, 2010, an increase of $364.4 million, or 41%. Our operating income before eliminations
was $47.4 million for the year ended December 31, 2011 compared to $48.1 million for the year ended December 31, 2010, a
decrease of $0.7 million, or 2%.
The results of operations are described in greater detail on a segment basis below.
Terminalling and Storage Segment
The following table summarizes our results of operations in our terminalling and storage segment.
Revenues:
Services
Products
Total revenues
Cost of products sold
Operating expenses
Selling, general and administrative expenses
Depreciation and amortization
Other operating income (loss)
Operating income
57
Years Ended December 31,
2011
2010
(In thousands)
$
$
$
81,697
201,478
283,175
182,928
54,992
3,343
19,814
22,098
(531)
21,567
$
71,471
128,273
199,744
115,308
43,360
2,180
17,330
21,566
244
21,810
Revenues. Our terminalling and storage revenues increased $83.4 million, or 42%, for the year ended December 31, 2011
compared to the year ended December 31, 2010. Of the increase in total revenues, $10.2 million is attributable to services revenue
and $73.2 million pertains to product revenues. The increase in services revenue of $10.2 million is primarily related to the
acquisition of certain terminalling assets from Martin Resource Management in February 2011. Product revenue increased $73.2
million compared to the prior year. An increase of $46.3 million is related to product revenues associated with historical
operations of the Blending and Packaging Assets. Packaging operations saw an increase in sales volumes of 16%, resulting in an
impact on revenues of $33.3 million and an increase in sales prices of 34%, resulting in an impact on revenues of $13.0 million.
Of the remaining $26.9 million increase, this is primarily due to the conversion of consigned product delivery agreements with two
of our customers to buy/sell product delivery agreements of $22.8 million. The remaining $4.1 million of the increase was due to
increases in average selling prices at our Mega Lubricants facility.
Cost of products sold. Our cost of products sold increased $67.6 million, or 59% for the year ended December 31, 2011
compared to the year ended December 31, 2010. Of this increase, $41.5 million relates to the historical operations of the Blending
and Packaging Assets. Packaging operations saw an increase in volumes of 16%, resulting in an impact on cost of products sold of
$30.3 million and an increase in prices of 37%, resulting in an impact on cost of products sold of $11.2 million. Of the remaining
$26.1 million increase, $20.6 million is due to the conversion of consigned product delivery agreements with two of our customers.
The remaining increase was due to a $3.9 million increase in our average purchase price of products at our Mega Lubricants
facility and $1.5 million of additional marine freight related to the acquisition of certain terminalling assets from Martin Resource
Management in February 2011.
Operating expenses. Operating expenses increased $11.6 million, or 27%, for the year ended December 31, 2011
compared to the year ended December 31, 2010. Of this increase, $1.4 million is related to the historical operations of the
Blending and Packaging Assets. Of this $1.4 million increase, $0.9 is related to increased manufacturing expenses and $0.5
million relates to increased product development expenses. Of the remaining $10.2 million increase, $5.1 million was due
primarily to operating expenses associated with the acquisition of certain terminalling assets from Martin Resource Management in
February 2011. Additionally, operating expenses associated with our Blending and Packaging Assets increased $1.6 million,
primarily due to $0.7 million related to labor and burden, $0.4 million related to repairs and maintenance, and $0.3 million
associated with increased materials and supply expense. The remaining balance of $3.5 million pertains to increases in various
areas of operations including $0.9 million related to a new pipeline lease in November 2011 and increases in operating expenses at
our specialty terminals of $2.1, of which $0.4 million was for the deductible accrued for expenses associated with the Stanolind
tank fire on September 11, 2011.
Selling, general and administrative expenses. Selling, general and administrative expenses increased $1.2 million, or
53%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. This is primarily due to increased
marketing expenses related to historical operations of the Blending and Packaging Assets.
Depreciation and amortization. Depreciation and amortization increased $2.5 million, or 14%, for the year ended
December 31, 2011 compared to the year ended December 31, 2010. Of the increase $1.5 million relates to additional depreciation
expense associated with the acquisition of certain terminalling assets from Martin Resource Management in February 2011.
Additionally, $0.2 million is related to capital expenditures associated with the historical operations of the Blending and Packaging
Assets. The balance of the increase was a result of capital expenditures made in the past 12 months.
Other operating income (loss). Other operating loss for the year ended December 31, 2011 primarily consists of a loss of
$0.7 million on the disposition of certain property, plant and equipment at our terminal located in Corpus Christi, Texas. The
disposition was executed to facilitate the construction of a new crude terminal adjacent to our existing facility. The loss was
partially offset by business interruption insurance recoveries of $0.1 million received.
In summary, terminalling and storage operating income decreased $0.2 million, or 1%, for the year ended December 31,
2011 compared to the year ended December 31, 2010.
Natural Gas Services Segment
The following table summarizes our results of operations in our natural gas services segment.
58
Revenues
Cost of products sold
Operating expenses
Selling, general and administrative expenses
Depreciation and amortization
Other operating loss
Operating income
NGLs Volumes (Bbls)
Years Ended December 31,
2011
2010
(In thousands)
$
$
611,749
600,034
2,994
1,876
578
6,267
—
6,267
$
$
442,005
428,843
3,210
2,581
571
6,800
(20)
6,780
7,866
6,997
Revenues. Our natural gas services revenues increased $169.7 million, or 38%, for the year ended December 31, 2011
compared to the year ended December 31, 2010. During 2011, our NGL average sales price per barrel increased $14.60, or 23%,
compared to the same period in 2010. NGL sales volumes increased 12% compared to the same period of 2010.
Costs of product sold. Our cost of products increased $171.2 million, or 40%, for the year ended December 31, 2011
compared to the same period in 2010. The increase in NGL revenues was slightly lower than our increase in NGL cost of products
sold as our NGL margins fell $0.39 per barrel, or 21%.
Operating expenses. Operating expenses decreased $0.2 million, or 7% for the year ended December 31, 2011 compared
to the same period of 2010 primarily as a result of decreased pipeline maintenance expenses.
Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.7 million, or
27%, for the year ended December 31, 2011 compared to the same period of 2010. This decrease was primarily a result of the
write-off of an uncollectible customer receivable of $0.7 million.
Depreciation and amortization. Depreciation and amortization remained consistent for the year ended December 31, 2011
compared to the same period of 2010.
In summary, our natural gas services operating income decreased $0.5 million, or 8%, for the year ended December 31,
2011, compared to the year ended December 31, 2010.
Sulfur Services Segment
The following table summarizes our results of operations in our sulfur services segment.
59
Revenues:
Services
Products
Total revenues
Cost of products sold
Operating expenses
Selling, general and administrative expenses
Depreciation and amortization
Other operating income (loss)
Operating income
Sulfur (long tons)
Fertilizer (long tons)
Sulfur services volumes (long tons)
Years Ended December 31,
2011
2010
(In thousands)
$
$
$
11,400
263,644
275,044
—
165,078
165,078
220,059
19,328
3,361
6,725
25,571
2,080
27,651
1,314.5
271.8
1,586.3
$
122,483
17,013
3,422
6,262
15,898
(12)
15,886
1,129.2
274.9
1,404.1
Revenues. Our sulfur services revenues increased $110.0 million, or 67%, for the year ended December 31, 2011
compared to the year ended December 31, 2010. This increase was a result of higher market prices in 2011 compared to 2010.
The services revenue relates to a new contract that began on January 1, 2011.
Cost of products sold. Our cost of products sold increased $97.6 million, or 80%, for the year ended December 31, 2011
compared to the year ended December 31, 2010. This increase was directly related to the increased price of our raw materials in
2011 compared to 2010. Our overall gross margin per ton increased to $34.66 in 2011 from $30.34 in 2010.
Operating expenses. Our operating expenses increased $2.3 million, or 14%, for the year ended December 31, 2011
compared to the year ended December 31, 2010. This increase consists of marine fuel expense increasing $0.8 million, workers
compensation claims of $0.8 million, outside towing of $0.4 million, and property taxes of $0.2 million.
Selling, general, and administrative expenses. Our selling, general, and administrative expenses remained flat for the
year ended December 31, 2011, compared to the year ended December 31, 2010.
Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 6%, for the year ended
December 31, 2011 compared to the year ended December 31, 2010. This increase was primarily a result of normal capital
expenditure activity during the current year.
Other operating income. Other operating income increased $2.1 million for the year ended December 31, 2011 consisting
of $1.4 million received for the termination of a rail services agreement and $0.7 million for business interruption insurance recoveries
from Hurricane Ike.
In summary, our sulfur services operating income increased $11.8 million, or 74%, for the year ended December 31, 2011
compared to the year ended December 31, 2010.
Marine Transportation Segment
The following table summarizes our results of operations in our marine transportation segment.
60
Years Ended December 31,
2011
2010
Revenues
Operating expenses
Selling, general and administrative expenses
Depreciation and amortization
Other operating income (loss)
Operating income
$
$
$
(In thousands)
83,971
66,771
3,087
13,159
954
(223)
731
$
82,635
57,642
2,296
12,721
9,976
16
9,992
Revenues. Our marine transportation revenues increased $1.3 million, or 2%, for the year ended December 31, 2011
compared to the year ended December 31, 2010. This increase was primarily a result of an increase in our inland marine
operations, offset by a decrease in our offshore marine operations. Our inland marine operations increased $7.2 million, of which
$2.8 million is attributed to increased utilization of the inland fleet through the utilization of new leased equipment and increases in
contract rates. The remaining $4.4 million is due to an increase in ancillary charges. Our offshore revenues decreased $6.3 million
primarily due to decreased utilization of the offshore fleet in 2011 of $8.1 million due to various dry dockings and reduced demand
for our two offshore tows which operate in the spot market, offset by an increase in ancillary charges of $1.8 million.
Operating expenses. Operating expenses increased $9.1 million, or 16%, for the year ended December 31, 2011
compared to the year ended December 31, 2010, primarily as a result of increased fuel expense of $4.4 million, outside towing
expense of $1.7 million, increased repairs and maintenance expense of $1.7 million, operating supplies of $1.0 million, and
increased wages and burden costs of $1.7 million. Offsetting these increases was a decrease in barge lease expense of $2.0 million.
Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.8 million, or
34%, for the year ended December 31, 2011 compared to the year ended December 31, 2010, primarily due to the reserve of an
uncollectible customer receivable of $0.7 million.
Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 3%, for the year ended
December 31, 2011 compared to the year ended December 31, 2010. This increase was primarily a result of capital expenditures
made in the last twelve months.
Other operating income. Other operating income for the year ended December 31, 2011 and the year ended December
31, 2010 consisted of gains and losses on the disposal of assets.
In summary, our marine transportation operating income decreased $9.3 million, or 93%, for the year ended December 31,
2011 compared to the year ended December 31, 2010.
Equity in Earnings of Unconsolidated Entities
For the years ended December 31, 2011 and 2010, equity in earnings (loss) of unconsolidated entities relates to our
unconsolidated interests in Cardinal.
Equity in earnings (loss) of unconsolidated entities was ($4.8) million for the year ended December 31, 2011, compared to
$2.5 million for the year ended December 31, 2010, a decrease of $7.3 million. This decrease is primarily a result of milestone
payments received in the amount of $6.6 million during 2010. There were no milestone payments received during 2011. The
remaining decrease of $0.7 million is related to changes in the Partnership’s share of earnings in Cardinal.
Gain from change in ownership of unconsolidated entities was $0 for the year ended December 31, 2011, compared to
$6.4 million for the year ended December 31, 2010. This change is a result of our share of Redbird’s interest in Cardinal
decreasing during 2010 as a result of disproportionate contributions during 2010.
Interest Expense
Our interest expense for all operations was $26.8 million for 2011 compared to $35.3 million for 2010, a decrease of $8.5
million, or 24%. This decrease was primarily due to the termination of all our interest rate swaps at a cost of $3.8 million during
61
the first quarter 2010, the termination of all our interest rate swaps at a benefit of $2.8 million during the third quarter 2011, and
decreases in interest expense related to the difference between the fixed rate and the floating rate of interest on the interest rate
swaps, offset by increases due to the issuance of our senior notes at the end of the first quarter 2010. Additionally, offsetting the
overall decrease was an increase in interest expense of $0.7 million attributable to the historical operations of the Blending and
Packaging Assets.
Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses were $8.9 million for 2011 compared to $6.4 million for 2010, an
increase of $2.5 million or 39%.
Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses for
services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general
office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource
Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management
personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for
allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation
of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of
the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most
accurate or appropriate method of allocation 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.
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, 2011
and 2010, the Conflicts Committee of our general partner approved reimbursement amounts of $4.8 million and $3.8 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.
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. During
2012 and 2011, we completed several transactions that have improved our liquidity position, helping fund our acquisitions and
organic growth projects. In July 2012, we completed the sale of certain gas gathering and processing assets for approximately
$273.3 million. We received $102.8 and $91.4 from follow on public offerings of common units in November and January
2012, respectively. In February 2011, we received net proceeds of $70.3 million from a public offering of common
units. Additionally, we made certain strategic amendments to our credit facility which provides for a maximum borrowing
capacity of $400.0 million under 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 11, 2013, we completed a private placement of $250.0 million in aggregate principal amount of 7.25%
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 the Partnership's revolving credit facility.
62
On May 24, 2012, we redeemed $25.0 million of the Senior 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 May 10, 2012, we increased the maximum amount of borrowings and letters of credit available under our
revolving credit facility from $375.0 million to $400.0 million.
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.
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 $70.3 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. On February 9, 2011, we made a $65.0 million payment to
reduce the outstanding balance under our revolving credit facility.
Due to the foregoing, we believe that cash generated from operations and our borrowing capacity under our credit
facility will be sufficient to meet our working capital requirements, anticipated maintenance capital expenditures and scheduled
debt payments in 2013.
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 and Capital Expenditures
In 2012, cash increased $4.9 million as a result of $32.6 million provided by operating activities ($34.0 million
provided by continuing operating activities and $1.4 million used in discontinued operating activities), $15.0 million used in
investing activities ($286.6 million used in continuing investing activities and $271.6 million provided by discontinued
investing activities), and $12.7 million used in financing activities. 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. In 2011, cash decreased $11.1 million as a result of $91.4 million provided by operating activities ($77.3
million provided by continuing operating activities and $14.1 million provided by discontinued operating activities), $202.7
million used in investing activities ($188.8 million used in continuing investing activities and $13.9 million used in
discontinued investing activities), and $100.2 million provided by financing activities. Working capital positively affected cash
provided by operating activities in 2011 due to increases 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. In 2010, cash increased
$5.4 million as a result of $39.1 million provided by operating activities ($29.0 million provided by continuing operating
activities and $10.1 million provided by discontinued operating activities), $91.0 million used in investing activities ($47.6
million used in continuing investing activities and $43.4 million used in discontinued investing activities), and $57.3 million
provided by financing activities. Working capital negatively affected cash provided by operating activities in 2010 principally
due to increases in accounts and other receivables, product exchange receivables and inventories caused by higher prices in our
natural gas services and sulfur services segments which exceeded the increase in trade and other accounts payable and product
exchange payables.
63
For 2012, our cash used in continuing investing activities of $286.6 million consisted primarily of capital
expenditures, acquisitions, investments in and contributions to unconsolidated entities. For 2012, cash provided by
discontinued investing activities of $271.6 million consisted primarily of the disposal of assets, capital expenditures, and
investments in and returns of investments from unconsolidated entities. For 2011, our cash used in continuing investing
activities of $188.8 million consisted primarily of capital expenditures, acquisitions, and investments in and contributions to
unconsolidated entities. For 2011, our cash used in discontinued investing activities of $13.9 million consisted primarily of
capital expenditures, and investments in and returns of investments from unconsolidated entities. For 2010, our cash used in
continuing investing activities of $47.6 million consisted primarily of capital expenditures, acquisitions, and contributions to
unconsolidated entities. For 2010, our cash used in discontinued investing activities of $43.4 million consisted primarily of
capital expenditures, acquisitions, and investments in and returns of investments from unconsolidated entities.
For 2012, 2011 and 2010 our capital expenditures for property and equipment and plant turnaround costs related to
continuing activities were $95.7 million, $79.3 million, and $19.2 million, respectively. For 2012, 2011 and 2010 our capital
expenditures for property and equipment related to discontinued activities were $1.1 million, $1.3 million, and $1.4 million,
respectively.
As to each period:
•
•
•
In 2012, we spent $85.0 million for expansion capital expenditures and $8.6 million for maintenance capital
expenditures (including $5.0 million for maintenance in the fourth quarter of 2012), and $2.1 million for plant
turnaround costs related to continuing operations. Our expansion capital expenditures were made in connection with
marine vessel conversions and construction projects associated with our terminalling and storage and sulfur services
businesses. Our maintenance capital expenditures were primarily made in our terminalling and storage, marine and
sulfur services divisions for routine operating equipment improvements. In 2012, we spent $0.6 million for expansion
and $0.5 million for maintenance capital expenditures (no maintenance capital expenditures were made in the fourth
quarter of 2012) related to discontinued operations.
In 2011, we spent $67.4 million for expansion capital expenditures and $9.8 million for maintenance capital
expenditures (including $0.3 million for maintenance in the fourth quarter of 2011), and $2.1 million for plant
turnaround costs related to continuing operations. Our expansion capital expenditures were made in connection with
marine vessel conversions and construction projects associated with our terminalling and storage and sulfur services
businesses. Our maintenance capital expenditures were primarily made in our marine and sulfur services divisions for
routine operating equipment improvements. In 2011, we spent $0.2 million for expansion and $1.1 million for
maintenance capital expenditures (including $0.5 million for maintenance in the fourth quarter of 2011) related to
discontinued operations.
In 2010, we spent $14.1 million for expansion capital expenditures and $4.1 million for maintenance (including $0.9
million for maintenance in the fourth quarter of 2010), and $1.1 million for plant turnaround costs related to
continuing operations. Our expansion capital expenditures were made in connection with marine vessel conversions
and construction projects associated with our terminalling and storage and sulfur services businesses. Our maintenance
capital expenditures were primarily made in our terminalling and storage and sulfur services divisions for routine
operating equipment improvements. In 2010, we spent $0.8 million for expansion and $0.6 million for maintenance
capital expenditures (including $0.3 million for maintenance in the fourth quarter of 2010) related to discontinued
operations.
In 2012, our financing activities consisted of payments of long-term debt under our credit facilities and senior notes of
$706.0 million and borrowings of long-term debt under our credit facilities of $727.0 million, cash distributions paid to
common and subordinated unitholders of $76.5 million, payments of notes payable and capital lease obligations of $6.6
million, purchase of treasury units of $0.2 million, funding from affiliate for investments in Cardinal of $2.2 million and
payments of debt issuance costs of $0.2 million. Additional financing activities consisted of contributions of $4.2 million from
our general partner to maintain its 2% general partner interest, net proceeds from follow on public offering of $194.2 million,
excess purchase price over carrying value of acquired assets of $142.1 million, and excess carrying value of assets over the
purchase price paid by Martin Resource Management of $4.3 million.
In 2011, our financing activities consisted of payments of long-term debt under our credit facilities and senior notes of
$442.0 million and borrowings of long-term debt under our credit facilities of $529.0 million, cash distributions paid to
common and subordinated unitholders of $64.5 million, payments of notes payable and capital lease obligations of $1.1
million, purchase of treasury units of $0.5 million, funding from affiliate for investments in Cardinal of $30.8 million and
64
payments of debt issuance costs of $3.6 million. Additional financing activities consisted of contributions of $1.5 million from
our general partner to maintain its 2% general partner interest, net proceeds from follow on public offering of $70.3 million and
excess purchase price over carrying value of acquired assets of $19.7 million.
In 2010, our financing activities consisted of payments of long-term debt under our credit facilities and senior notes of
$441.9 million and borrowings of long-term debt under our credit facilities of $503.9 million, cash distributions paid to
common and subordinated unitholders of $56.7 million, payments of notes payable and capital lease obligations of $0.1
million, purchase of treasury units of $0.1 million, funding from affiliate for investments in Cardinal of $12.6 million and
payments of debt issuance costs of $7.4 million. Additional financing activities consisted of contributions of $1.1 million from
our general partner to maintain its 2% general partner interest, net proceeds from follow on public offering of $78.6 million,
redemption of common units of $28.1 million and excess purchase price over carrying value of acquired assets of $4.6 million.
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, 2012, we had $478.2 million of outstanding indebtedness, consisting of outstanding borrowings
of $173.4 million (net of unamortized discount) under our Senior Notes, $296.0 million under our revolving credit facility, $3.0
million under a note payable, and $5.8 million under capital lease obligations.
Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2012, is
as follows (dollars in
thousands):
Type of Obligation
Revolving credit facility
Senior unsecured notes
Note payable
Capital leases including current maturities
Non-competition agreements
Throughput commitment
Operating leases
Interest expense: ¹
Revolving credit facility
Senior unsecured notes
Note payable
Capital leases
Total
Obligation
296,000
$
173,388
2,971
5,839
100
49,151
58,215
27,442
82,832
71
3,112
699,121
Payments due by period
1-3
Years
Less than
One Year
$
$
— $
—
2,971
235
50
4,796
12,781
8,347
15,531
71
912
45,694
$
— $
—
—
651
50
10,059
31,818
16,694
31,062
—
1,688
92,022
$
3-5
Years
296,000
—
—
4,953
—
10,716
8,054
2,401
31,062
—
512
353,698
Due
Thereafter
—
$
173,388
—
—
—
23,580
5,562
—
5,177
—
—
207,707
$
Total contractual cash obligations
$
¹Interest commitments are estimated using our current interest rates for the respective credit agreements over their
remaining terms.
Letter of Credit. At December 31, 2012, 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
Senior Notes
We and Martin Midstream Finance Corp. (“FinCo”), a subsidiary of us (collectively, the “Issuers”), entered into (i) a
Purchase Agreement, dated as of March 23, 2010 (the “Purchase Agreement”), by and among the Issuers, certain subsidiary
65
guarantors (the “Guarantors”) and Wells Fargo Securities, LLC, RBC Capital Markets Corporation and UBS Securities, LLC, as
representatives of a group of initial purchasers (collectively, the “Initial Purchasers”), (ii) an Indenture, dated as of March 26, 2010
(the “Indenture”), among the Issuers, the Guarantors and Wells Fargo Bank, National Association, as trustee (the “Trustee”) and
(iii) a Registration Rights Agreement, dated as of March 26, 2010 (the “Registration Rights Agreement”), among the Issuers, the
Guarantors and the 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 “Senior Notes”). We completed the aforementioned
Senior 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.
Indenture
Interest and Maturity. On March 26, 2010, the Issuers issued the Senior Notes pursuant to the Indenture in a
transaction exempt from registration requirements under the Securities Act. The Senior 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 Senior 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 Senior Notes issued under the 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 Senior 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 Senior
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 Senior 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 Senior Notes.
On April 24, 2012 we notified the Trustee of our intention to exercise a partial redemption of the our Senior Notes
pursuant to the Indenture. On May 24, 2012, we redeemed $25.0 million of the Senior 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.
Certain Covenants. The 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 Senior 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
Indenture) has occurred and is continuing, many of these covenants will terminate.
Events of Default. The 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 Senior Notes; (ii) default in payment when due of the principal of, or premium, if any,
on the Senior Notes; (iii) our failure to comply with certain covenants relating to asset sales, repurchases of the Senior 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 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 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 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 Indenture with respect to the Issuers or any of our restricted subsidiaries that is a significant
66
subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary of us. Upon a
continuing Event of Default, the Trustee, by notice to the Issuers, or the holders of at least 25% in principal amount of the then
outstanding Senior Notes, by notice to the Issuers and the Trustee, may declare the Senior 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 Senior Notes to become due and payable.
Registration Rights Agreement. Under the Registration Rights Agreement, the Issuers and the Guarantors filed with
the SEC a registration statement to exchange the Senior Notes for substantially identical notes that are registered under the
Securities Act. We exchanged the Senior Notes for registered 8.875% senior unsecured notes due April 2018.
Credit Facility
On November 10, 2005, we entered into a $225.0 million multi-bank credit facility, which has subsequently been
amended, including most recently on May 10, 2012 (the "Credit Facility"), when we increased the maximum amount of
borrowings and letters of credit available under our revolving credit facility from $375.0 million to $400.0 million.
As of December 31, 2012, we had approximately $296.0 million outstanding under the revolving credit facility and
$0.1 million of letters of credit issued, leaving approximately $103.9 million available under our credit facility for future
revolving credit borrowings and letters of credit.
The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to
finance permitted investments, acquisitions and capital expenditures. During the current fiscal year, draws on our credit
facility have ranged from a low of $35.0 million to a high of $361.0 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. We used
the proceeds from our disposition of the Prism Assets to pay down outstanding indebtedness.
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 which ranges from 0.375% to 0.50% per
annum on the unused revolving credit availability under the credit facility. The letter of credit fee and the applicable margins
for our interest rate vary quarterly based on our leverage ratio (as defined in the new credit facility, being generally computed
as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-
cash charges) and are as follows:
Leverage Ratio
Less than 2.25 to 1.00
Greater than or equal to 2.25 to 1.00 and less than 3.00 to 1.00
Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00
Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00
Greater than or equal to 4.50 to 1.00
Base Rate
Loans
Eurodollar
Rate
Loans
Letters of
Credit
1.00%
1.25%
1.50%
1.75%
2.00%
2.25%
2.00%
2.25%
2.50%
2.75%
3.00%
3.25%
2.00%
2.25%
2.50%
2.75%
3.00%
3.25%
The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.25% and the applicable
margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.25%. The applicable margin for existing
67
LIBOR borrowings is 3.00%. Effective January 1, 2013, the applicable margin for existing LIBOR borrowings decreased to
2.25%. Effective April 1, 2013, the applicable margin for existing LIBOR borrowings will increase to 2.75%.
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 5.00 to 1.00. The maximum
permitted senior leverage ratio (as defined in the new credit facility, but generally computed as the ratio of total secured funded
debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.25 to
1.00. The minimum consolidated interest coverage ratio (as defined in the new credit facility, but generally computed as the
ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to
consolidated interest charges) is 2.75 to 1.00.
In addition, the credit facility contains various covenants that, among other restrictions, limit our and our subsidiaries’
ability to:
•
grant or assume liens;
• make investments (including investments in our joint ventures) and acquisitions;
•
•
•
•
•
•
•
enter into certain types of hedging agreements;
incur or assume indebtedness;
sell, transfer, assign or convey assets;
repurchase our equity, make distributions and certain other restricted payments, but the credit facility permits us to
make quarterly distributions to unitholders so long as no default or event of default exists under the credit facility;
change the nature of our business;
engage in transactions with affiliates;
enter into certain burdensome agreements;
• make certain amendments to the Omnibus Agreement and our material agreements;
• make capital expenditures; and
•
permit our joint ventures to incur indebtedness or grant certain liens.
Each of the following will be an event of default under the credit facility:
•
•
•
•
•
•
•
•
•
failure to pay any principal, interest, fees, expenses or other amounts when due;
failure to meet the quarterly financial covenants;
failure to observe any other agreement, obligation, or covenant in the credit facility or any related loan document,
subject to cure periods for certain failures;
the failure of any representation or warranty to be materially true and correct when made;
our or any of our subsidiaries’ default under other indebtedness that exceeds a threshold amount;
bankruptcy or other insolvency events involving us or any of our subsidiaries;
judgments against us or any of our subsidiaries, in excess of a threshold amount;
certain ERISA events involving us or any of our subsidiaries, in excess of a threshold amount;
a change in control (as defined in the credit facility);
68
•
•
the termination of any material agreement or certain other events with respect to material agreements;
the invalidity of any of the loan documents or the failure of any of the collateral documents to create a lien on the
collateral; and
•
any of our joint ventures incurs debt or liens in excess of a threshold amount.
The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin
Resource Management no longer controls our general partner, or if Ruben Martin is not the chief executive officer of our
general partner and a successor acceptable to the administrative agent and lenders providing more than 50% of the
commitments under our credit facility is not appointed, the lenders under our credit facility may declare all amounts
outstanding thereunder immediately due and payable. In addition, either a bankruptcy event with respect to Martin Resource
Management or a judgment with respect to Martin Resource Management could independently result in an event of default
under our credit facility if it is deemed to have a material adverse effect on us.
If an event of default relating to bankruptcy or other insolvency events occurs with respect to us or any of our
subsidiaries, all indebtedness under our credit facility will immediately become due and payable. If any other event of default
exists under our credit facility, the lenders may terminate their commitments to lend us money, accelerate the maturity of the
indebtedness outstanding under the credit facility and exercise other rights and remedies. In addition, if any event of default
exists under our credit facility, the lenders may commence foreclosure or other actions against the collateral. Any event of
default and corresponding acceleration of outstanding balances under our credit facility could require us to refinance such
indebtedness on unfavorable terms and would have a material adverse effect on our financial condition and results of operations
as well as our ability to make distributions to unitholders.
If any default occurs under our credit facility, or if we are unable to make any of the representations and warranties in
the credit facility, we will be unable to borrow funds or have letters of credit issued under our credit facility.
As of March 4, 2013, our outstanding indebtedness includes $72.0 million under our credit facility.
We are subject to interest rate risk on our credit facility and may enter into interest rate swaps to reduce this risk.
Effective September 2010, we entered into an interest rate swap that swapped $40.0 million of fixed rate to floating
rate. The floating rate cost is the applicable three-month LIBOR rate. This interest rate swap was not accounted for using
hedge accounting. This swap was scheduled to mature in April 2018, but was terminated in August 2011.
Effective September 2010, we entered into an interest rate swap that swapped $60.0 million of fixed rate to floating
rate. The floating rate cost is the applicable three-month LIBOR rate. This interest rate swap was not accounted for using
hedge accounting. This swap was scheduled to mature in April 2018, but was terminated in August 2011.
Subsequent Event - Senior Unsecured Notes Issuance
On February 11, 2013, we completed a private placement of $250.0 million in aggregate principal amount of 7.25%
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 the Partnership's revolving credit facility.
Seasonality
A substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and fertilizers,
which fluctuate in part based on winter and spring weather conditions. The demand for NGLs is strongest during the winter
heating season 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. We expect to derive a majority of our net income 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.
69
Impact of Inflation
Inflation did not have a material impact on our results of operations in 2012, 2011 or 2010. 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 2012, 2011 or 2010.
70
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 3.58% as of December 31, 2012. As of March 4, 2013, we had total indebtedness outstanding under our
credit facility of $72.0 million, all of which was unhedged floating rate debt. Based on the amount of unhedged floating rate
debt owed by us on December 31, 2012, the impact of a 1% increase in interest rates on this amount of debt would result in an
increase in interest expense and a corresponding decrease in net income of approximately $0.7 million annually.
We are not exposed to changes in interest rates with respect to our Senior Notes as these obligations are fixed
rate. The estimated fair value of the Senior Notes was approximately $187.1 million as of December 31, 2012, based on
market prices of similar debt at December 31, 2012. 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 $6.2 million decrease in fair value of our long-term debt at December 31, 2012.
71
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
Report of Independent Registered Public Accounting Firm on Internal Controls
Consolidated Balance Sheets as of December 31, 2012 and 2011
Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010
Consolidated Statements of Changes in Capital for the years ended December 31, 2012, 2011 and 2010
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010
Notes to Consolidated Financial Statements
Page
73
74
75
76
79
80
81
82
72
Report of Independent Registered Public Accounting Firm
The Board of Directors
Martin Midstream GP LLC:
We have audited the accompanying consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as
of December 31, 2012 and 2011, 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, 2012. 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, 2012 and 2011 and the
results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, 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, 2012, based on
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated March 4, 2013 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 4, 2013
73
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, 2012, based on criteria established in Internal Control—Integrated Framework 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, 2012, based on criteria established in Internal Control – Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (U.S.),
the consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2012 and 2011, 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, 2012, and our report dated March 4, 2013 expressed an unqualified opinion on
those consolidated financial statements.
/s/ KPMG LLP
Dallas, Texas
March 4, 2013
74
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
Cash
Accounts and other receivables, less allowance for doubtful accounts of $2,805 and
$
5,162
$
266
Assets
December 31, 2012
2012
20111
$3,384, respectively
Product exchange receivables
Inventories
Due from affiliates
Fair value of derivatives
Other current assets
Assets held for sale
Total current assets
Property, plant and equipment, at cost
Accumulated depreciation
Property, plant and equipment, net
Goodwill
Investment in unconsolidated entities
Debt issuance costs, net
Other assets, net
Liabilities and Partners’ Capital
Current portion of long-term debt and capital lease obligations
Trade and other accounts payable
Product exchange payables
Due to affiliates
Income taxes payable
Fair value of derivatives
Other accrued liabilities
Liabilities held for sale
Total current liabilities
Long-term debt and capital leases, less current maturities
Deferred income taxes
Other long-term obligations
Total liabilities
Partners’ capital
Accumulated other comprehensive income
Total partners’ capital
Commitments and contingencies
$
$
190,652
3,416
95,987
13,343
—
2,777
3,578
314,915
767,344
(256,963)
510,381
19,616
154,309
10,244
3,531
1,012,996
3,206
140,045
12,187
3,316
10,239
—
9,489
—
178,482
474,992
—
1,560
655,034
357,962
—
357,962
$
$
143,036
17,646
93,254
5,968
622
4,366
212,787
477,945
651,460
(218,202)
433,258
8,337
132,605
13,330
3,633
1,069,108
1,261
136,124
37,313
74,654
926
362
11,054
501
262,195
458,941
9,697
1,088
731,921
336,561
626
337,187
1Financial information has been revised to include balances attributable to Redbird Class A interests and the Blending and Packaging Assets
acquired from Cross. See Note 2(a) – Principles of Presentation and Consolidation.
$
1,012,996
$
1,069,108
See accompanying notes to consolidated financial statements.
75
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit amounts)
Revenues:
Terminalling and storage *
Marine transportation *
Sulfur services *
Product sales: *
Natural gas services
Sulfur services
Terminalling and storage
Total revenues
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *
Sulfur services *
Terminalling and storage
Expenses:
Operating expenses *
Selling, general and administrative *
Depreciation and amortization
Total costs and expenses
Other operating income (loss)
Operating income
Other income (expense):
Equity in earnings (loss) of unconsolidated entities
Gain from ownership change in unconsolidated entity
Debt prepayment premium
Interest expense
Other, net
Total other income (expense)
Net income before taxes
Income tax expense
Income from continuing operations
Income from discontinued operations, net of income taxes
Net income
Less general partner's interest in net income
Less pre-acquisition (income) loss allocated to Parent
Less beneficial conversion feature
Limited partner's interest in net income
Year Ended December 31,
2011¹
2010¹
2012¹
$
$
90,243
85,748
11,702
$
77,283
76,936
11,400
825,506
249,882
227,280
1,302,668
1,490,361
801,724
194,952
200,855
1,197,531
151,020
25,494
42,063
1,416,108
(418)
73,835
(1,113)
—
(2,470)
(30,665)
1,092
(33,156)
40,679
(3,557)
37,122
64,865
101,987
(4,748)
(4,622)
—
92,617
$
611,749
263,644
201,478
1,076,871
1,242,490
598,814
219,697
179,461
997,972
137,685
20,531
40,276
1,196,464
1,326
47,352
(4,752)
—
—
(26,781)
420
(31,113)
16,239
(2,872)
13,367
9,392
22,759
(5,289)
1,583
(1,108)
17,945
$
$
67,117
77,642
—
442,005
165,078
128,273
735,356
880,115
427,657
122,121
115,308
665,086
113,426
16,865
36,884
832,261
228
48,082
2,536
6,413
—
(35,322)
385
(25,988)
22,094
(2,622)
19,472
8,061
27,533
(3,869)
(11,511)
(1,108)
11,045
¹ Financial information for 2012, 2011 and 2010 has been revised to include results attributable to the Redbird Class A interests and the
Blending and Packaging Assets acquired from Cross prior to October 2, 2012. See Note 2(a) – Principles of Presentation and Consolidation.
*Related Party Transactions Shown Below
See accompanying notes to consolidated financial statements.
76
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit amounts)
*Related Party Transactions Included Above
Revenues:
Terminalling and storage
Marine transportation
Product Sales
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services
Sulfur services
Terminalling and Storage
Expenses:
Operating expenses
Selling, general and administrative
Year Ended December 31,
2011¹
2010¹
2012¹
$
$
64,669
17,494
7,201
$
54,211
23,478
9,081
46,823
28,194
7,903
27,512
16,968
48,375
58,834
13,678
16,749
18,314
45,089
58,051
8,610
7,517
16,061
32,489
48,390
7,237
¹ Financial information for 2012, 2011, and 2010 has been revised to include results attributable to the Redbird Class A interests and the
Blending and Packaging Assets acquired from Cross prior to October 2, 2012. See Note 2(a) – Principles of Presentation and Consolidation.
See accompanying notes to consolidated financial statements.
77
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit amounts)
Year Ended December 31,
2011
2010
2012
Allocation of net income attributable to:
Limited partner interest:
Continuing operations
Discontinued operations
General partner interest:
Continuing operations
Discontinued operations
Net income attributable to:
Continuing operations
Discontinued operations
Net income attributable to limited partners:
Basic:
Continuing operations
Discontinued operations
Weighted average limited partner units - basic
Diluted:
Continuing operations
Discontinued operations
$
$
$
$
$
$
$
30,915
61,702
92,617
$
11,193
6,752
17,945
4,441
6,604
11,045
1,585
3,163
4,748
32,500
64,865
97,365
1.32
2.64
3.96
23,362
1.32
2.64
3.96
$
$
$
$
$
3,106
2,183
5,289
14,299
8,935
23,234
0.57
0.35
0.92
19,545
0.57
0.35
0.92
$
$
$
$
$
2,736
1,133
3,869
7,177
7,737
14,914
0.25
0.38
0.63
17,525
0.25
0.38
0.63
Weighted average limited partner units - diluted
23,365
19,547
17,526
See accompanying notes to consolidated financial statements.
78
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
Net income
Other comprehensive income adjustments:
Changes in fair values of commodity cash flow hedges
Commodity cash flow hedging gains reclassified to earnings
Changes in fair value of interest rate cash flow hedges
Interest rate cash flow hedging losses reclassified to earnings
Other comprehensive income (loss)
Comprehensive income
$
$
Year Ended December 31,
20111
20101
$
22,759
$
27,533
20121
101,987
126
(752)
—
—
(626)
101,361
$
1,011
(1,822)
—
18
(793)
21,966
$
143
(617)
(241)
4,210
3,495
31,028
¹ Financial information for 2012, 2011 and 2010 has been revised to include results attributable to the Redbird Class A Interests and the Blending and
Packaging Assets acquired from Cross prior to October 2, 2012. See Note 2(a) – Principles of Presentation and Consolidation.
See accompanying notes to consolidated financial statements.
79
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL
(Dollars in thousands)
Partners’ Capital
Common
Subordinated
General
Partner
Accumulated
Comprehensive
Income
Units
Amount
Units
Amount Amount
Amount
Total
Parent Net
Investment1
16,057,832
$ 245,683
889,444
$
16,613
$
4,731
$
(2,076) $
306,594
—
3,869
Balances – December 31, 2010
53,154
17,707,832
250,787
889,444
17,721
—
—
1,874,500
—
19,053
(1,108)
70,330
—
—
—
—
—
—
1,108
—
—
889,444
18,829
(889,444)
(18,829)
Balances – December 31, 2009
$
Net Income
Recognition of beneficial
conversion feature
Follow-on public offerings
41,643
11,511
—
—
—
—
2,650,000
12,153
(1,108)
78,600
Redemption of common units
— (1,000,000)
(28,070)
General partner contribution
Excess purchase price over
carrying value of acquired assets
Cash distributions ($3.00 per unit)
Unit-based compensation
Purchase of treasury units
Adjustment in fair value of
derivatives
—
—
—
—
—
—
—
—
—
3,500
(3,500)
—
(4,590)
(51,886)
113
(108)
—
—
Balances – December 31, 2011
51,571
20,471,776
279,562
Net income (loss)
Recognition of beneficial
conversion feature
Follow-on public offering
General partner contribution
Conversion of subordinated units
to common units
Cash distributions ($3.05 per unit)
Excess purchase price over
carrying value of acquired assets
Unit-based compensation
Purchase of treasury units
Adjustment in fair value of
derivatives
(1,583)
—
—
—
—
—
—
—
—
—
Net income (loss)
Follow-on public offering
General partner contribution
Cash distributions ($3.06 per unit)
Excess purchase price over
carrying value of acquired assets
Excess carrying value of assets
over the purchase price paid by
Martin Resource Management
Unit-based compensation
Purchase of treasury units
Contributions to parent
Adjustment in fair value of
derivatives
(56,193)
—
—
—
14,850
(14,850)
(58,252)
(19,685)
190
(582)
—
—
4,622
—
92,617
—
—
—
—
—
—
—
6,095,000
194,170
—
—
—
(70,679)
— (142,075)
—
—
—
—
—
(4,268)
385
(222)
—
—
—
—
—
—
—
—
—
—
—
—
1,108
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,089
—
(4,810)
—
—
—
4,879
5,289
—
—
1,505
—
(6,245)
—
—
—
—
5,428
4,748
—
4,145
(5,849)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
27,533
—
78,600
(28,070)
1,089
(4,590)
(56,696)
113
(108)
3,495
1,419
3,495
327,960
—
—
—
—
—
—
—
—
—
(793)
626
—
—
—
—
—
—
—
—
—
22,759
—
70,330
1,505
—
(64,497)
(19,685)
190
(582)
(793)
337,187
101,987
194,170
4,145
(76,528)
(142,075)
(4,268)
385
(222)
(56,193)
(626)
(626)
Balances – December 31, 2012
$
— 26,566,776
$ 349,490
— $
— $
8,472
$
— $
357,962
1Financial information for 2012, 2011 and 2010 has been revised to include results attributable to the Redbird Class A interests and the Blending and Packaging
Assets acquired from Cross prior to October 2, 2012. See Note 2(a) – Principles of Presentation and Consolidation.
See accompanying notes to consolidated financial statements.
80
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
Year Ended December 31,
2011¹
2012¹
2010¹
$
$
101,987
(64,865)
37,122
$
22,759
(9,392)
13,367
Cash flows from operating activities:
Net income
Less: Income from discontinued operations
Net income from continuing operations
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization
Amortization of deferred debt issue costs
Amortization of discount on notes payable
Deferred income taxes
(Gain) loss on disposition or sale of property, plant, and equipment
Gain on sale of equity method investment
Equity in (earnings) loss of unconsolidated entities
Gain on ownership change in unconsolidated entity
Other
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables
Product exchange receivables
Inventories
Due from affiliates
Other current assets
Trade and other accounts payable
Product exchange payables
Due to affiliates
Income taxes payable
Other accrued liabilities
Change in other non-current assets and liabilities
Net cash provided by continuing operating activities
Net cash provided by (used in) discontinued operating activities
Net cash provided by operating activities
Cash flows from investing activities:
Payments for property, plant, and equipment
Acquisitions, net of cash acquired
Proceeds from sale of acquired assets
Payments for plant turnaround costs
Proceeds from sale of property, plant, and equipment
Proceeds from sale of equity method investment
Investments in unconsolidated entities
Milestone distributions from ECP
Return of investments from unconsolidated entities
(Contributions to) unconsolidated entities for operations
Net cash (used in) continuing investing activities
Net cash provided by (used in) discontinued investing activities
Net cash (used in) investing activities
Cash flows from financing activities:
Payments of long-term debt
Payments of notes payable and capital lease obligations
Proceeds from long-term debt
Net proceeds from follow on public offerings
General partner contributions
Redemption of common units
Excess purchase price over carrying value of acquired assets
Excess carrying value of assets over the purchase price paid by Martin Resource Management
Purchase of treasury units
Increase (decrease) in affiliate funding of investments in unconsolidated entities
Payments of debt issuance costs
Cash distributions paid
Net cash provided by (used in) financing activities
Net increase (decrease) in cash
Cash at beginning of period
Cash at end of period
Supplemental schedule of non-cash investing and financing activities:
Purchase of assets under note payable
$
$
42,063
3,290
581
402
795
(486)
1,113
—
385
(56,856)
14,230
(2,733)
(20,135)
3,046
17,595
(25,126)
18,976
367
(1,463)
872
34,038
(1,360)
32,678
(93,640)
(224,603)
56,000
(2,107)
44
531
(775)
2,208
5,980
(30,279)
(286,641)
271,605
(15,036)
(706,000)
(6,556)
727,000
194,170
4,145
—
(142,075)
(4,268)
(222)
(2,208)
(204)
(76,528)
(12,746)
4,896
266
5,162
—
$
$
40,276
3,755
351
622
898
—
4,752
—
190
(34,626)
(8,547)
(28,714)
5,551
(1,996)
50,904
14,961
11,874
(943)
1,063
3,500
77,238
14,124
91,362
(77,202)
(16,815)
—
(2,103)
1,025
—
(59,319)
—
1,432
(35,765)
(188,747)
(13,908)
(202,655)
(442,000)
(1,132)
529,000
70,330
1,505
—
(19,685)
—
(582)
30,828
(3,588)
(64,497)
100,179
(11,114)
11,380
266
—
$
$
27,533
(8,061)
19,472
36,884
4,814
269
452
(229)
—
(2,536)
(6,413)
113
(20,009)
(4,967)
(20,815)
(175)
(1,455)
14,116
14,366
(5,714)
(8)
5,185
(4,307)
29,043
10,135
39,178
(18,179)
(16,747)
—
(1,090)
994
—
—
6,625
—
(19,253)
(47,650)
(43,366)
(91,016)
(441,868)
(111)
503,856
78,600
1,089
(28,070)
(4,590)
—
(108)
12,628
(7,468)
(56,696)
57,262
5,424
5,956
11,380
7,354
¹ Financial information for 2010, 2011, and 2012 has been revised to include results attributable to the Redbird Class A interests and the Blending and
Packaging Assets acquired from Cross prior to October 2, 2012. See Note 2(a) – Principles of Presentation and Consolidation.
See accompanying notes to consolidated and condensed financial statements.
81
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 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; 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 owns 100% of the Class A and Class B equity interests in Redbird. As of December 31, 2012 and
2011, Redbird owned an unconsolidated 41.28% and 40.08% interest in Cardinal, respectively. This investment is accounted
for by the equity method.
(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, 2012 or 2011.
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 classified the Prism Assets, including
related liabilities as held for sale at December 31, 2011 and has presented the results of operations and cash flows as
discontinued operations for the years ended December 31, 2012, 2011 and 2010, respectively. The Partnership has
retrospectively adjusted its prior period consolidated financial statements to comparably classify the amounts related to the net
assets and operations and cash flows of the Prism Assets as assets held for sale and discontinued operations, respectively.
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., a subsidiary of Martin
Resource Management. Redbird was formed by the Partnership and Martin Resource Management in 2011 to invest in
Cardinal.
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”).
82
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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 (2)(p).
(b) Product Exchanges
The Partnership enters into product exchange agreements with third parties, whereby the Partnership agrees to
exchange NGLs and sulfur with third parties. The Partnership records the balance of exchange products due to 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” on the Consolidated Statement 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.
(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
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.
83
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The Partnership owns 100% of the Class A and Class B equity interests in Redbird. Redbird, as of December 31, 2012
and 2011, owned a 41.28% and 40.08% interest in Cardinal, respectively. The Partnership owns an unconsolidated 50%
interest in Caliber Gathering, LLC ("Caliber").
The Partnership's subsidiary, legal name of Prism Gas Systems I, L.P., 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.
The Partnership has historically performed its annual impairment testing of goodwill and indefinite-lived intangible
assets as of September 30 of each year. During the third quarter of fiscal 2011, the Partnership changed the annual impairment
testing date from September 30 to August 31. The Partnership believes this change, which represents a change in the method of
applying an accounting principle, is preferable in the circumstances as the earlier date provides additional time prior to our
quarter-end to complete the goodwill impairment testing and report the results in our quarterly report on Form 10-Q.
The Partnership has performed the annual impairment tests as of August 31, 2012, August 31, 2011, and September
30, 2010, and determined fair value in each reporting unit based on the weighted average of three valuation techniques: (i) the
discounted cash flow method; (ii) the guideline public company method; and (iii) the guideline transaction method. At August
31, 2012, August 31, 2011, and September 30, 2010, 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,
2012 or 2011.
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 notes are deferred and amortized
over the terms of the debt arrangements.
84
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership
incurred debt issuance costs of $204, $3,588 and $7,468 in the years ended December 31, 2012, 2011 and 2010, respectively.
Due to a reduction in the number of lenders under the Partnership’s multi-bank credit agreement, $0, $494 and $634 of
the existing debt issuance costs were determined not to have continuing benefit and were expensed during 2012, 2011 and
2010, 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 $3,290, $3,755 and $4,814 for the
years ended December 31, 2012, 2011 and 2010, respectively. Accumulated amortization amounted to $6,014 and $2,723 at
December 31, 2012 and 2011, 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 2012, 2011 or 2010 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
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, 2011, the Partnership designated a portion of its
derivative instruments as qualifying cash flow hedges. As of December 31, 2012, the Partnership did not have any hedging
instruments outstanding. Fair value changes for these hedges have been recorded in accumulated other comprehensive income
as a component of equity.
(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.
85
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
(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)
Unit Grants
In April 2012, the Partnership issued 6,250 restricted common units to certain non-employee directors under its long-
term incentive plan from 6,250 treasury units purchased by the Partnership in the open market for $222. These units vest in
25% increments beginning in January 2013 and will be fully vested in January 2016.
In May 2011, the Partnership issued 6,250 restricted common units to certain non-employee directors under its long-
term incentive plan from 5,750 treasury units purchased by the Partnership in the open market for $235 and 500 treasury units
from forfeitures. These units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015.
In February 2011, the Partnership issued 9,100 restricted common units to certain Martin Resource Management
employees under its long-term incentive plan from 9,100 treasury units purchased by the Partnership in the open market for
$347. On July 31, 2012, 6,850 of these units were fully vested to certain employees in connection with the sale of the Prism
Assets. The remaining 2,250 units vest in 25% increments beginning in February 2012 and will be fully vested in February
2015.
In August 2010, the Partnership issued 1,500 restricted common units to each of two new non-employee directors
under its long-term incentive plan from 500 treasury units purchased by the Partnership in the open market for $16 and 2,500
common units from forfeited unit grants. These units vest in 25% increments beginning in January 2011 and will be fully
vested in January 2014.
In May 2010, the Partnership issued 1,000 restricted common units to each of its non-employee directors under its
long-term incentive plan from treasury units purchased by the Partnership in the open market for $92. These units vest in 25%
increments beginning in January 2011 and will be fully vested in January 2014.
The Partnership accounts for these transaction under certain provisions of ASC 505-50-55 related to equity-based
payments to non-employees. The cost resulting from the unit-based payment transactions was $385, $190, and $113 for the
years ended December 31, 2012, 2011 and 2010, respectively.
(o)
Incentive Distribution Rights
The Partnership’s general partner, Martin Midstream GP LLC, 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 of the Partnership (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 through December 31, 2012, which would have been payable to the general partner on
November 14, 2012 for the third quarter distribution and February 14, 2013 for the fourth quarter distribution.
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, 2012, 2011 and 2010, the general partner received $2,857, $4,901, and $3,623 in
incentive distributions.
86
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
(p)
Net Income per Unit
The Partnership follows the provisions of ASC 260-10 related to earnings per share, which addresses the application
of the two-class method in determining income per unit for master limited partnerships having multiple classes of securities
that may participate in partnership distributions accounted for as equity distributions. 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 IDR 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.
For purposes of computing diluted net income per unit, the Partnership uses the more dilutive of the two-class and if-
converted methods. Under the if-converted method, the beneficial conversion feature is added back to net income available to
common limited partners, the weighted-average number of subordinated units outstanding for the period is added to the
weighted-average number of common units outstanding for purposes of computing basic net income per unit and the resulting
amount is compared to the diluted net income per unit computed using the two-class method.
The following 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:
Years Ended December 31,
2011
2010
2012
Continuing operations:
Net income attributable to Martin Midstream Partners L.P.
Less pre-acquisition income (loss) allocated to Parent
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs
Distributions payable on behalf of general partner interest
Distributions payable to the general partner interest in excess of earnings
allocable to the general partner interest
Less beneficial conversion feature
Limited partners’ interest in net income
$
$
$
37,122
4,622
$
13,367
(1,583)
19,472
11,511
954
522
2,878
789
109
—
30,915
$
(561)
651
11,193
$
2,562
839
(665)
784
4,441
Years Ended December 31,
2011
2010
2012
Discontinued operations:
Net income attributable to Martin Midstream Partners L.P.
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs
Distributions payable on behalf of general partner interest
Distributions payable to the general partner interest in excess of earnings
allocable to the general partner interest
Less beneficial conversion feature
Limited partners’ interest in net income
$
64,865
$
9,392
$
8,061
1,903
1,040
220
—
61,702
$
$
2,023
555
(395)
457
6,752
$
1,061
348
(276)
324
6,604
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.
87
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The weighted average units outstanding for basic net income per unit were 23,361,551, 19,545,427 and 17,525,089 for
years ended December 31, 2012, 2011 and 2010, respectively. For diluted net income per unit, the weighted average units
outstanding were increased by 3,018, 1,278 and 900 units for the years ended December 31, 2012, 2011 and 2010, respectively,
due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.
(q) 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, 2012, 2011 and 2010, the Conflicts Committee of the
Partnership's general partner approved reimbursement amounts of $7,593, $4,771 and $3,791, 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.
(r) 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.
(s) 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.
(t) 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.
(u) 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.
(v) 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 18, 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.
(w) Prior period correction of an immaterial error
The statement of cash flows for the year ended December 31, 2010 has been revised to correct an immaterial
error of $6,625 in the equity in loss of unconsolidated entities (which is an adjustment to reconcile net income to net cash
88
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
provided by operating activities) and affiliate funding of investments in unconsolidated entities (which is included in cash
flows from financing activities). The correction of this immaterial error decreases net cash provided by operating activities,
increases net cash provided by financing activities, and had no effect on the Partnership's cash and cash equivalents,
investments in unconsolidated entities, net income or partners' capital.
(3)
Recent Accounting Pronouncements
In February 2013, the FASB amended the provisions of ASC 220 related to accumulated other comprehensive income,
which does not change the current requirements for reporting net income or other comprehensive income in financial
statements. The standard requires a company to provide information about the amounts reclassified out of accumulated other
comprehensive income by component. The company 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 accumulated other comprehensive income by the
respective line items of net income but only if the amount reclassified is required under 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. The standard is effective prospectively for reporting periods beginning after
December 15, 2012 with early adoption permitted. The adoption of this pronouncement is not anticipated to have a material
impact on Partnership’s financial position or results of operations.
In September 2011, the FASB amended the provisions of ASC 350 related to testing goodwill for impairment. This
update simplifies the goodwill impairment assessment by allowing a company to first review qualitative factors to determine
the likelihood of whether the fair value of a reporting unit is less than its carrying amount before applying the two-step
goodwill impairment test. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than
its carrying amount, the company would not be required to perform the two-step goodwill impairment test for that reporting
unit. This update is effective for interim and annual goodwill impairment tests performed for fiscal years beginning after
December 15, 2011. This amended guidance was adopted by the Partnership effective January 1, 2012.
In June 2011, the FASB amended the provisions of ASC 220 related to other comprehensive income. This newly
issued guidance: (1) eliminates the option to present the components of other comprehensive income as part of the statement of
changes in stockholders’ equity; (2) requires the consecutive presentation of the statement of net income and other
comprehensive income; and (3) requires an entity to present reclassification adjustments on the face of the financial statements
from other comprehensive income to net income. The amendments in this guidance do not change the items that must be
reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income
nor do the amendments affect how earnings per share is calculated or presented. This guidance is required to be applied
retrospectively and is effective for fiscal years and interim periods within those years beginning after December 15, 2011. This
amended guidance was adopted by the Partnership effective January 1, 2012. As this new guidance only requires enhanced
disclosure, adoption did not impact the Partnership’s financial position or results of operations.
(4)
Acquisitions
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 Quintana Energy Partners, L.P. for $103,368, subject to certain post-closing adjustments, including the
assumption of a note payable in the amount of $2,971. 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 we provide 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 partners' capital. The remaining net assets retained by the Partnership were recorded at fair value
of $43,100 in the following preliminary purchase price allocation:
89
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Purchase price paid to acquire Talen's
Less proceeds received from Martin Resource Management for assets sold (described above)
Less excess of carrying value of assets sold to Martin Resource Management over the purchase price
paid by Martin Resource Management
Total
Cash
Accounts and other receivables, net
Assets held for sale
Other current assets
Property, plant and equipment
Goodwill
Notes payable
Current liabilities
Other liabilities
Total
$
$
$
$
103,368
(56,000)
(4,268)
43,100
5,096
2,682
3,578
1,547
23,838
11,279
(2,971)
(1,480)
(469)
43,100
The Partnership has not obtained all of the information necessary to finalize the purchase price allocation. The final
purchase price allocation is expected to be completed during second quarter 2013.
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. The
purchase 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 blending and packaging assets was recorded at the
historical carrying value of the assets at the acquisition date, which were as follows:
Accounts receivable, net
Inventory
Other current assets
Property, plant and equipment, net
Current liabilities
Total
$
$
20,599
18,730
769
24,692
(2,424)
62,366
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
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.
90
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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 Gas Storage Company, LLC (“Monroe”) as well
as an option on development rights to an adjacent depleted reservoir facility. This acquisition 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 acquisition 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.
On August 26, 2010, the Partnership acquired certain shore-based marine terminalling assets from Martin Resource
Management for $11,700. The net book value of the acquired assets was $7,331 and was recorded in property, plant and
equipment. The remaining $4,395 was recorded as an adjustment to partners’ capital. These assets are located in Theodore,
Alabama and Pascagoula, Mississippi.
Marine Equipment
On December 22, 2010, the Partnership acquired a 60,000 bbl offshore tank barge from Martin Resource Management
for a total purchase price of $17,000. The Partnership paid cash in the amount of $9,600 and assumed a note payable to a third
party for $7,400. The net book value of the acquired assets was $16,805 and was recorded in property, plant, and equipment.
The remaining $195 was recorded as an adjustment to partners’ capital.
(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 Systems I, L.P. (“Prism Gas”), a wholly-owned subsidiary of the Partnership, 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 assets described above collectively are referred to herein as the Prism Assets.
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 and condensed statements of
operations for all periods presented. The assets and liabilities to be sold met the accounting criteria to be classified as held for
sale and were aggregated and reported on separate lines in the consolidated and condensed balance sheet at December 31, 2011.
The assets and liabilities classified held for sale as of December 31, 2011 were as follows:
91
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Assets
Inventories
Property, plant and equipment
Accumulated depreciation
Goodwill
Investment in unconsolidated entities
Other assets, net
Assets held for sale
Liabilities
Other long-term obligations
Liabilities held for sale
2011
486
78,324
(18,438)
28,931
107,549
15,935
212,787
501
501
$
$
$
$
The Prism Assets’ operating results, which are included in income from discontinued operations, were as follows:
Year Ended December 31,
2011
2010
2012
Total revenues from third parties1
Total costs and expenses and other, net, excluding depreciation and
amortization
Depreciation and amortization
Other operating income (loss)2
Equity in earnings of unconsolidated entities3
Income from discontinued operations before income taxes
Income tax (expense) benefit
Income from discontinued operations, net of income taxes
$
66,876
$
121,338
$
112,477
(64,562)
(2,320)
61,858
4,611
66,463
(1,598)
64,865
$
(115,957)
(5,512)
—
9,412
9,281
111
9,392
$
(110,061)
(4,452)
(92)
9,792
7,664
397
8,061
$
1 Total revenues from third parties excludes intercompany revenues of $26,431, $67,141, and $56,390 for the years ended
December 31, 2012, 2011, 2010, respectively.
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, 2011 and 2010.
(6)
Inventories
Components of inventories at December 31, 2012 and 2011 were as follows:
Natural gas liquids
Sulfur
Sulfur based products
Lubricants
Other
2012
2011
$
$
33,610
14,892
17,824
27,366
2,295
95,987
$
$
25,178
24,335
14,857
26,589
2,295
93,254
(7)
Property, Plant and Equipment
At December 31, 2012 and 2011, property, plant, and equipment consisted of the following:
92
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Land
Improvements to land and buildings
Transportation equipment
Storage equipment
Marine vessels
Operating equipment
Furniture, fixtures and other equipment
Construction in progress
Depreciable
Lives
—
10-25 years
3-7 years
5-20 years
4-25 years
3-20 years
3-20 years
2012
2011
22,235
104,788
1,757
86,870
246,536
272,192
3,510
29,456
767,344
$
$
19,790
78,815
1,787
67,360
228,043
197,661
2,674
55,330
651,460
$
$
Depreciation expense for the year ended December 31, 2012, 2011 and 2010 was $40,724, $37,869, and $34,796,
respectively, which includes amortization of fixed assets acquired under capital lease obligations of $280 for each of the years
ended 2012, 2011 and 2010. Gross assets under capital leases were $7,764 at December 31, 2012 and 2011. Accumulated
amortization associated with capital leases was $955 and $675 at December 31, 2012 and 2011, respectively.
(8)
Goodwill and Other Intangibles
The following table represents the goodwill balance at December 31, 2011, changes during the year, and the resulting
balances at December 31, 2012:
Carrying amount of goodwill:
Terminalling and storage
Natural gas services
Sulfur services
Marine transportation
Goodwill classified as held for sale
Total goodwill
2011
Talen's
Acquisition1
Disposal of
Prism Assets2
2012
$
$
883
79
5,349
2,026
8,337
28,931
37,268
$
$
9,469
—
—
1,810
11,279
—
11,279
$
$
— $
—
—
—
—
(28,931)
(28,931) $
10,352
79
5,349
3,836
19,616
—
19,616
1 These changes represent the amounts allocated to goodwill during the purchase price allocation of Talen's, of which
$9,469 and $1,810 was allocated to the Terminalling and storage and Marine transportation segments, respectively. See Note 4.
2 This change represents goodwill disposed of as part of the Partnership's divestiture of the Prism Assets. See Note 5.
Other intangible assets subject to amortization consist of covenants not-to-compete, customer contracts associated
with gathering and processing assets and a transportation contract associated with the residue gas pipeline.
The unamortized balance of other intangible assets, classified in the consolidated balance sheets as other assets, net,
amounted to $198 and $338 at December 31, 2012 and 2011, respectively. The unamortized balance of other intangible assets,
net, classified in the consolidated balance sheets as assets held for sale, amounted to $0 and $15,935 at December 31, 2012 and
2011, respectively.
Aggregate amortization expense for amortizing intangible assets included in continuing operations was $140, $140,
and $226, for the years ended December 31, 2012, 2011 and 2010, respectively, and accumulated amortization amounted to
$1,200 and $1,060 at December 31, 2012 and 2011, respectively.
Estimated amortization expenses for the years subsequent to December 31, 2012 are as follows: 2013 - $140; 2014 -
$58; 2015 - $0; 2016 - $0; 2017 - $0; subsequent years - $0.
93
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
(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. Certain of the Partnership's
marine vessels have been acquired under capital leases.
The Partnership’s future minimum lease obligations as of December 31, 2012 consist of the following:
Fiscal year
2013
2014
2015
2016
2017
Thereafter
Total
Less amounts representing interest costs
Present value of net minimum capital lease payments
Less current portion
Present value of net minimum capital lease payments, excluding
current portion
Operating
Leases
Capital
Leases
$
$
$
12,781
11,589
10,683
9,546
5,346
8,270
58,215
1,148
1,169
1,169
5,465
—
—
8,951
3,112
5,839
235
$
5,604
Rent expense for continuing operating leases for the years ended December 31, 2012, 2011 and 2010 was $15,801,
$19,280 and $15,710, respectively. The amount recognized in interest expense for capital leases was $945, $972, and $991 for
the years ended December 31, 2012, 2011 and 2010, respectively.
(10)
Investments in Unconsolidated Entities and Joint Ventures
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, 2011, and 2010.
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, 2012, 2011 and 2010. The remaining basis difference is a
permanent difference that will be realized upon sale of the investment in Cardinal.
ECP is also required to make $25,000 in cash contributions to Cardinal once certain “milestones” are met, which relate
to future progress on projects currently underway. The agreement requires such contributions be made to Cardinal and then
distributed to the Partnership. These are the equivalent of additional purchase price for the assets originally contributed by the
Partnership and, therefore, are recognized as equity in earnings of equity method investees in the consolidated statements of
operations. Milestone payments totaling $2,208, $0, and $6,625 were made during 2012, 2011 and 2010, respectively. As of
December 31, 2012, ECP has made $13,249 in cumulative milestone payments.
94
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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 Gas Storage Company, LLC 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, 2011, and 2010 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.
Due to different funding levels to Cardinal by the partners in 2010, the initial 50% ownership by the Company has
decreased. Because of that decrease in ownership, the Company has realized a partial sale of its ownership to ECP which has
resulted in gains in the statement of operations for the year ending December 31, 2010 of $6,413. As of December 31, 2012,
Redbird owns an unconsolidated 41.28% interest in Cardinal.
During the second quarter of 2012, the Partnership acquired an unconsolidated 50% interest in Caliber Gathering, LLC
(“Caliber”) and Pecos Valley Producer Services, LLC (“Pecos Valley”). 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.
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:
Investment in Waskom1
Investment in PIPE1
Investment in Matagorda1
Investment in unconsolidated entities classified as assets held for sale
Investment in Cardinal
Investment in Caliber
Investment in unconsolidated entities
Total Investment in unconsolidated entities
December 31,
2012
December 31,
2011
$
$
— $
—
—
—
153,749
560
154,309
154,309
$
102,896
1,291
3,362
107,549
132,605
—
132,605
240,154
1 As of December 31, 2011, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated balance
sheets as assets held for sale.
95
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Years Ended December 31,
2011
2010
2012
Equity in earnings of Waskom1
Equity in loss of PIPE1
Equity in earnings of Matagorda1
Equity in earnings of discontinued operations
Equity in earnings (loss) of Cardinal
Equity in loss of Caliber
Equity in earnings (loss) of Pecos Valley
Equity in earnings (loss) of unconsolidated entities
Total equity in earnings of unconsolidated entities
$
$
4,172
(60)
499
4,611
(943)
(190)
20
(1,113)
3,498
$
$
9,143
(45)
314
9,412
(4,752)
—
—
(4,752)
4,660
$
$
9,831
(180)
141
9,792
2,536
—
—
2,536
12,328
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.
Select financial information for significant unconsolidated equity method investees is as follows:
2012
Waskom
2011
Waskom
2010
Waskom
2012
Cardinal
2011
Cardinal
2010
Cardinal
As of December 31,
Years ended December 31,
Total Assets
Partners’
Capital
Revenues
Net Income
$
$
$
— $
— $
66,662
146,655
122,057
$
$
126,863
107,508
$
$
129,119
124,122
$
$
$
8,986
19,385
20,762
As of December 31,
Years ended December 31,
Total Assets
Long-Term
Debt
Members’
Equity
Revenues
Net Loss
$
$
$
690,491
561,375
313,802
$
$
$
211,180
122,064
98,112
$
$
$
457,316
422,935
200,815
$
$
$
31,999
19,471
4,751
$
$
$
(5,932)
(11,534)
(15,150)
As of December 31, 2012 and 2011, the Partnership’s interest in cash of the unconsolidated equity method investees is
$1,265 and $1,155, respectively.
(11) Fair Value Measurements
The Partnership follows the provisions of ASC 820 related to fair value measurements and disclosures, which
established a framework for measuring fair value and expanded disclosures about fair value measurements. The adoption of this
guidance had no impact on the Partnership’s financial position or results of operations.
ASC 820 applies to all assets and liabilities that are being measured and reported on a fair value basis. This statement
enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a
hierarchy for ranking the quality and reliability of the information used to determine fair values. ASC 820 establishes a three-
tier fair value hierarchy, which prioritizes the inputs used in measuring fair value of each asset and liability carried at fair value
into one of the following categories:
Level 1: Quoted market prices in active markets for identical assets or liabilities.
Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.
96
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Level 3: Unobservable inputs that are not corroborated by market data.
The Partnership’s derivative instruments, which consist of commodity and interest rate swaps, are required to be
measured at fair value on a recurring basis. The fair value of the Partnership’s derivative instruments is determined based on
inputs that are readily available in public markets or can be derived from information available in publicly quoted markets,
which is considered Level 2. Refer to Note 12 for further information on the Partnership’s derivative instruments and hedging
activities.
The following items are measured at fair value on a recurring and non-recurring basis and are subject to the
disclosure requirements of ASC 820 at December 31, 2012 and 2011:
Fair Value Measurements at Reporting Date Using
Quoted Prices in
Active Markets for
Identical Assets
Significant Other
Observable Inputs
Significant
Unobservable
Inputs
Description
December 31,
2012
(Level 1)
(Level 2)
(Level 3)
Liabilities
Senior notes
Total liabilities
$
$
187,066
187,066
$
$
— $
— $
187,066
187,066
$
$
—
—
Fair Value Measurements at Reporting Date Using
Quoted Prices in
Active Markets for
Identical Assets
Significant Other
Observable Inputs
Significant
Unobservable
Inputs
Description
Assets
Natural gas derivatives
Total assets
Liabilities
Crude oil derivatives
Natural gas liquids derivatives
Senior notes
Total liabilities
December 31,
2011
$
$
$
$
622
622
245
117
210,500
210,862
$
$
$
$
(Level 1)
(Level 2)
(Level 3)
— $
— $
— $
—
—
— $
622
622
245
117
210,500
210,862
$
$
$
$
—
—
—
—
—
—
FASB ASC 825-10-65, Disclosures about Fair Value of Financial Instruments, requires that the Partnership disclose
estimated fair values for its financial instruments. Fair value estimates are set forth below for the Partnership’s financial
instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument:
• Accounts and other receivables, trade and other accounts payable, other accrued liabilities, income taxes payable
and due from/to affiliates — the carrying amounts approximate fair value 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 loan 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 Notes
is based on market prices of similar debt. The carrying amount of the Partnership's note payable to bank as of
December 31, 2012 is not deemed to be significantly different than the fair value.
(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. The Partnership is required to recognize all derivative instruments
97
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
as either assets or liabilities at fair value on the Partnership’s consolidated balance sheets and to recognize certain changes in
the fair value of derivative instruments on the Partnership’s Consolidated Statements of Operations.
The Partnership performs, at least quarterly, a retrospective assessment of the effectiveness of its hedge contracts,
including assessing the possibility of counterparty default. If the Partnership determines that a derivative is no longer expected
to be highly effective, the Partnership discontinues hedge accounting prospectively and recognizes subsequent changes in the
fair value of the hedge in earnings.
All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair
value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a
derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the
hedged item through earnings or recognized in accumulated other comprehensive income (“AOCI”) until such time as the
hedged item is recognized in earnings. The Partnership is exposed to the risk that periodic changes in the fair value of
derivatives qualifying for hedge accounting will not be effective, as defined, or that derivatives will no longer qualify for hedge
accounting. To the extent that the periodic changes in the fair value of the derivatives are not effective, that ineffectiveness is
recorded to earnings. Likewise, if a hedge ceases to qualify for hedge accounting, any change in the fair value of derivative
instruments since the last period is recorded to earnings; however, any amounts previously recorded to AOCI would remain
there until such time as the original forecasted transaction occurs, then would be reclassified to earnings or if it is determined
that continued reporting of losses in AOCI would lead to recognizing a net loss on the combination of the hedging instrument
and the hedge transaction in future periods, then the losses would be immediately reclassified to earnings. If a forecasted hedge
transaction is no longer probable of occurring, any gain or loss in AOCI is reclassified to earnings.
For derivative instruments that are designated and qualify as cash flow hedges, the effective portion of the gain or loss
on the derivative is reported as a component of AOCI and reclassified into earnings in the same period during which the hedged
transaction affects earnings. The effective portion of the derivative represents the change in fair value of the hedge that offsets
the change in fair value of the hedged item. To the extent the change in the fair value of the hedge does not perfectly offset the
change in the fair value of the hedged item; the ineffective portion of the hedge is immediately recognized in earnings.
(a)
Commodity Derivative Instruments
The Partnership is not currently exposed to market risks associated with commodity prices and from time to time has
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 are in the form of swaps for crude oil, natural gas and natural gasoline. In addition, the Partnership is 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 completed on July 31, 2012, as of December 31, 2012 , the Partnership has
terminated and settled all of its commodity derivative instruments. For the year ended December 31, 2012 , changes in the fair
value of the Partnership’s derivative contracts were recorded in both earnings and in AOCI as a component of partners’ capital.
(b)
Impact of Commodity Cash Flow Hedges
Crude Oil. For the years ended December 31, 2012, 2011 and 2010, net gains and losses on swap hedge contracts
increased crude revenue (included in income from discontinued operations) by $496, $775 and $27, respectively.
Natural Gas. For the years ended December 31, 2012, 2011 and 2010, net gains and losses on swap hedge contracts
increased gas revenue (included in income from discontinued operations) by $813, $332 and $601, respectively.
Natural Gas Liquids. For the years ended December 31, 2012, 2011 and 2010, net gains and losses on swap hedge
contracts increased liquids revenue (included in income from discontinued operations) by $1,066, $254 and $207, 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.
98
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
(c)
Impact of Interest Rate Derivative Instruments
The Partnership is exposed to market risks associated with interest rates. 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. All
derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and
changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative
qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item
through earnings or recognized in AOCI until such time as the hedged item is recognized in earnings.
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 Senior 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.
In March 2010, in connection with a pay down of the Partnership’s revolving credit facility, the Partnership terminated
all of its existing cash flow hedge agreements with an aggregate notional amount of $140,000, which it had entered to hedge its
exposure to increases in the benchmark interest rate underlying its variable rate revolving and term loan credit facilities.
Termination fees of $3,850 were paid on the early extinguishment of all interest rate swap agreements in March 2010. The
amounts remaining in AOCI were reclassified into interest expense over the original term of the terminated interest rate
derivatives.
The Partnership recognized increases in interest expense of $0, $5,779 and $6,327 for the years ended December 31,
2012, 2011 and 2010, 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 Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related
Hedged Items” below.
Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items
Fair Values of Derivative Instruments in the Consolidated Balance Sheet
Derivative Assets
Fair Values
Derivative Liabilities
Fair Values
Balance Sheet
Location
December 31,
2012
2011
Balance Sheet
Location
December 31,
2012
2011
Derivatives designated as
hedging instruments:
Commodity contracts
Total derivatives designated
as hedging instruments
Derivatives not designated
as hedging instruments:
Commodity contracts
Total derivatives not
designated as hedging
instruments
Current:
Current:
Fair value of derivatives $
— $
622
Fair value of derivatives $
— $
$
— $
622
$
— $
245
245
Current:
Current:
Fair value of derivatives $
— $
— Fair value of derivatives $
— $
117
$
— $
—
$
— $
117
99
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Effect of Derivative Instruments on the Consolidated Statement of Operations
For the Years Ended December 31, 2012, 2011 and 2010
Effective Portion
Ineffective Portion and Amount Excluded
from Effectiveness Testing
Amount of Gain or (Loss)
Recognized in OCI on
Derivatives
2012
2011
2010
Location of Gain
or (Loss)
Reclassified from
Accumulated
OCI into Income
Amount of Gain or (Loss)
Reclassified from
Accumulated OCI into
Income
2012
2011
2010
Location of Gain
or (Loss)
Recognized in
Income on
Derivatives
Amount of Gain or (Loss)
Recognized in Income on
Derivatives
2012
2011
2010
Derivatives
designated as
hedging
instruments:
Interest Rate
contracts
Commodity
contracts
Total derivatives
designated as
hedging
instruments
$ — $ — $ (241)
Interest Expense
$ — $
(18) $(4,210)
Interest Expense
$ — $ — $ —
126
1,011
143
Income from
Discontinued
Operations
748
1,785
547
Income from
Discontinued
Operations
4
37
70
$
126
$ 1,011
$
(98)
$
748
$ 1,767
$(3,663)
$
4
$
37
$
70
Location of Gain or (Loss) Recognized in
Income on Derivatives
Amount of Gain or (Loss) Recognized in Income on
Derivatives
2012
2011
2010
Derivatives not designated as hedging instruments:
Interest rate contracts
Commodity contracts
Interest expense
Income from discontinued operations
Total derivatives not designated as hedging instruments
$
$
— $
1,623
1,623
$
5,797
(461)
5,336
$
$
(2,117)
219
(1,898)
No amounts are expected to be reclassified into earnings for the subsequent 12 - month period for commodity cash
flow hedges.
(13)
Related Party Transactions
As of December 31, 2012, Martin Resource Management owned 5,093,267 of the Partnership’s common units
representing approximately 19.2% of the Partnership’s outstanding common limited partnership units. The Partnership’s
general partner is a wholly-owned subsidiary of Martin Resource Management. The Partnership’s general partner owns a 2.0%
general partner interest in the Partnership and the Partnership’s incentive distribution rights. 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, 2012, of approximately 19.2% 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.
100
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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;
•
•
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 small crude oil gathering business in Stephens, Arkansas;
operating an underground NGL storage facility in Arcadia, Louisiana;
operating an environmental consulting company;
operating an engineering services company; and
building and marketing sulfur processing equipment.
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
expenses, under the Omnibus Agreement, the Partnership is required to reimburse Martin Resource Management for indirect
general and administrative and corporate overhead expenses.
Effective October 1, 2012, through December 31, 2013, the Conflicts Committee of the board of directors of the
general partner of the Partnership (the “Conflicts Committee”) approved an annual reimbursement amount for indirect expenses
101
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
of $10,622, which will be effective for the 15 - month period. The Partnership reimbursed Martin Resource Management for
$7,593, $4,772, and $3,791 of indirect expenses for the years ended December 31, 2012, 2011, and 2010, 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 of the Partnership's general
partner. 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 of the Partnership’s general
partner 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 of the Partnership’s general
partner. 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
Resource Management operates its land transportation operations. Under the agreement, Martin Transport, Inc. agreed to
transport the Partnership's NGL's 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.
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.
102
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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, three new agreements were executed, all with effective
dates of December 31, 2012. Under the terms of these contracts, Talen's provides terminal services and marine transportation
services to Martin Resource Management.
Other Agreements
Cross Tolling Agreement. The Partnership is a party to an agreement with Cross, dated November 25, 2009, under
which it processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate
cuts for Cross. The Tolling Agreement has a 22 year term which expires November 25, 2031. Under this Tolling Agreement,
Martin Resource Management 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, 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. The Partnership is party to an agreement dated August 1, 2008 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.
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
financial statement 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 financial
statement as follows:
103
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Revenues:
Terminalling and storage
Marine transportation
Product sales:
Natural gas services
Sulfur services
Terminalling and storage
2012
2011
2010
$
$
$
64,669
17,494
$
54,211
23,478
113
6,022
1,066
7,201
89,364
$
716
8,151
214
9,081
86,770
$
46,823
28,194
591
7,146
166
7,903
82,920
The impact of related party cost of products sold is reflected in the consolidated financial statement as follows:
Cost of products sold:
Natural gas services
Sulfur services
Terminalling and storage
$
$
27,512
16,968
48,375
92,855
$
$
16,749
18,314
45,089
80,152
$
$
The impact of related party operating expenses is reflected in the consolidated financial statement as follows:
Operating expenses
Marine transportation
Natural gas services
Sulfur services
Terminalling and storage
$
$
28,495
1,855
6,646
21,838
58,834
$
$
29,870
1,590
6,573
20,018
58,051
$
$
7,517
16,061
32,489
56,067
26,730
1,349
5,271
15,040
48,390
The impact of related party selling, general and administrative expenses is reflected in the consolidated financial
statement as follows:
Selling, general and administrative:
Marine transportation
Natural gas services
Sulfur services
Terminalling and storage
Indirect overhead allocation, net of reimbursement
$
$
60
2,498
2,964
563
7,593
13,678
$
$
65
1,069
2,704
—
4,772
8,610
$
$
—
1,048
2,398
—
3,791
7,237
(14)
Long-Term Debt and Capital Leases
At December 31, 2012 and 2011, long-term debt consisted of the following:
104
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
$200,000 **** Senior notes, 8.875% interest, net of unamortized discount of $1,612 and
$2,192, respectively, issued March 2010 and due April 2018, unsecured** ............................ $
$400,000 Revolving loan facility at variable interest rate (3.58%* weighted average at
December 31, 2012), due April 2016 secured by substantially all of the Partnership’s assets,
including, without limitation, inventory, accounts receivable, vessels, equipment, fixed
assets and the interests in the Partnership’s operating subsidiaries and equity method
investees*** ..............................................................................................................................
$3,315 Note payable to bank, interest rate at 4.75%, maturity date of October 2029,
unsecured ..................................................................................................................................
$7,354 Note payable to bank, interest rate at 7.50%, maturity date of January 2017, secured
by equipment .............................................................................................................................
Capital lease obligations ...........................................................................................................
Total long-term debt and capital lease obligations....................................................................
Less current portion ..................................................................................................................
Long-term debt and capital lease obligations, net of current portion ....................................... $
2012
2011
173,388
$
197,808
296,000
250,000
2,971
—
5,839
478,198
3,206
—
6,363
6,031
460,202
1,261
474,992
$
458,941
* 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 3.25% and the applicable margin for revolving loans that are base prime rate loans ranges from
1.00% to 2.25%. The applicable margin for existing LIBOR borrowings is 3.00%. Effective January 1, 2013, the applicable
margin for existing LIBOR borrowings decreased to 2.25%. Effective April 1, 2013, the applicable margin for existing LIBOR
borrowings will increase to 2.75%.
** Effective September 2010, the Partnership entered into an interest rate swap that swapped $40,000 of fixed rate to
floating rate. The floating rate cost was the applicable three-month LIBOR rate. This interest rate swap was scheduled to
mature in April 2018, but was terminated in August 2011.
** Effective September 2010, the Partnership entered into an interest rate swap that swapped $60,000 of fixed rate to
floating rate. The floating rate cost was the applicable three-month LIBOR rate. This interest rate swap was scheduled to
mature in April 2018, but was terminated in August 2011.
*** Effective October 2008, the Partnership entered into a cash flow hedge that swapped $40,000 of floating rate to
fixed rate. The fixed rate cost was 2.82% plus the Partnership’s applicable LIBOR borrowing spread. Effective April 2009, the
Partnership entered into two subsequent swaps to lower its effective fixed rate to 2.58% plus the Partnership’s applicable
LIBOR borrowing spread. These cash flow hedges were scheduled to mature in October 2010, but were terminated in March
2010.
*** Effective January 2008, the Partnership entered into a cash flow hedge that swapped $25,000 of floating rate to
fixed rate. The fixed rate cost was 3.40% plus the Partnership’s applicable LIBOR borrowing spread. Effective April 2009, the
Partnership entered into two subsequent swaps to lower its effective fixed rate to 3.050% plus the Partnership’s applicable
LIBOR borrowing spread. These cash flow hedges matured in January 2010.
*** Effective September 2007, the Partnership entered into a cash flow hedge that swapped $25,000 of floating rate to
fixed rate. The fixed rate cost was 4.61% plus the Partnership’s applicable LIBOR borrowing spread. Effective March 2009, the
Partnership entered into two subsequent swaps to lower its effective fixed rate to 4.31% plus the Partnership’s applicable
LIBOR borrowing spread. These cash flow hedges were scheduled to mature in September 2010, but were terminated in March
2010.
*** Effective November 2006, the Partnership entered into an interest rate swap that swapped $30,000 of floating rate
to fixed rate. The fixed rate cost was 4.77% plus the Partnership’s applicable LIBOR borrowing spread. This cash flow hedge
matured in March 2010.
105
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
*** Effective March 2006, the Partnership entered into a cash flow hedge that swapped $75,000 of floating rate to
fixed rate. The fixed rate cost was 5.25% plus the Partnership’s applicable LIBOR borrowing spread. Effective February 2009,
the Partnership entered into two subsequent swaps to lower its effective fixed rate to 5.10% plus the Partnership’s applicable
LIBOR borrowing spread. These cash flow hedges were scheduled to mature in November 2010, but were terminated in March
2010.
**** 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.
(a)
Senior Notes
In March 2010, the Partnership and Martin Midstream Finance Corp. (“FinCo”), a subsidiary of the Partnership
(collectively, the “Issuers”), entered into (i) a Purchase Agreement, dated as of March 23, 2010 (the “Purchase Agreement”), by
and among the Issuers, certain subsidiary guarantors (the “Guarantors”) and Wells Fargo Securities, LLC, RBC Capital Markets
Corporation and UBS Securities, LLC, as representatives of a group of initial purchasers (collectively, the “Initial Purchasers”),
(ii) an Indenture, dated as of March 26, 2010 (the “Indenture”), among the Issuers, the Guarantors and Wells Fargo Bank,
National Association, as trustee (the “Trustee”) and (iii) a Registration Rights Agreement, dated as of March 26, 2010 (the
“Registration Rights Agreement”), among the Issuers, the Guarantors and the Initial Purchasers, in connection with a private
placement to eligible purchasers of $200,000 in aggregate principal amount of the Issuers’ 8.875% unsecured senior notes due
2018 (the “Senior Notes”). The Partnership completed the aforementioned Senior Notes offering on March 26, 2010, and
received proceeds of approximately $197,200, after deducting initial purchasers’ discounts and the expenses of the private
placement. The proceeds were primarily used to repay borrowings under the Partnership’s revolving credit facility.
Indenture. On March 26, 2010, the Issuers issued the Senior Notes pursuant to the Indenture in a transaction exempt
from registration requirements under the Securities Act. The Senior 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.
Interest and Maturity. The Senior 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 Senior Notes issued under the 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 Senior 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 Senior
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 Senior Notes at redemption prices (expressed as percentages of principal
amount) equal to 104.438% for the 12-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 Senior Notes.
Certain Covenants. The Indenture restricts the Partnership’s ability and the ability of certain of its 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 the Partnership; (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 Senior
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 Indenture) has occurred and is continuing, many of these covenants will terminate.
106
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Events of Default. The 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 Senior Notes; (ii) default in payment when due of the principal of, or premium, if any,
on the Senior Notes; (iii) failure by the Partnership to comply with certain covenants relating to asset sales, repurchases of the
Senior Notes upon a change of control and mergers or consolidations; (iv) failure by the Partnership for 180 days after notice to
comply with its reporting obligations under the Securities Exchange Act of 1934; (v) failure by the Partnership for 60 days after
notice to comply with any of the other agreements in the Indenture; (vi) default under any mortgage, indenture or instrument
governing any indebtedness for money borrowed or guaranteed by the Partnership or any of its restricted subsidiaries, whether
such indebtedness or guarantee now exists or is created after the date of the 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 $20,000 or more, subject to a cure provision; (vii) failure by the
Partnership or any of its restricted subsidiaries to pay final judgments aggregating in excess of $20,000, which judgments are
not paid, discharged or stayed for a period of 60 days; (viii) except as permitted by the 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 Indenture with respect to the Issuers or any
of the Partnership’s restricted subsidiaries that is a significant subsidiary or any group of restricted subsidiaries that, taken
together, would constitute a significant subsidiary of the Partnership. Upon a continuing Event of Default, the Trustee, by
notice to the Issuers, or the holders of at least 25% in principal amount of the then outstanding Senior Notes, by notice to the
Issuers and the Trustee, may declare the Senior 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 the
Partnership that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a
significant subsidiary of the Partnership, will automatically cause the Senior Notes to become due and payable.
Registration Rights Agreement. Under the Registration Rights Agreement, the Issuers and the Guarantors filed with
the SEC a registration statement an offer to exchange the Senior Notes for substantially identical notes that are registered under
the Securities Act. The Partnership exchanged the Senior Notes for registered 8.875% senior unsecured notes due April 2018.
(b)
Credit Facility
On November 10, 2005, the Partnership entered into a multi-bank $225,000 credit facility, which has subsequently
been amended including most recently on May 10, 2012 (the “Credit Facility”), when the Partnership amended the Credit
Facility to increase the maximum amount of borrowings and letters of credit available under the Credit Facility from $375,000
to $400,000.
Under the Credit Facility, as of December, 2012, the Partnership had $296,000 outstanding under the revolving Credit
Facility. As of December 31, 2012, irrevocable letters of credit issued under the Credit Facility totaled $120. As of December
31, 2012, the Partnership had $103,880 available under its revolving Credit Facility. The Credit Facility is used for ongoing
working capital needs and general partnership purposes and to finance permitted investments, acquisitions and capital
expenditures. During the current fiscal year, draws on the Credit Facility ranged from a low of $35,000 to a high of $361,000.
The Partnership’s obligations under the Credit Facility are secured by substantially all of the Partnership’s assets,
including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in its operating
subsidiaries and equity method investees. The Partnership may prepay all amounts outstanding under this facility at any time
without penalty.
In addition, the Credit Facility contains various covenants, which, among other things, limit the Partnership’s ability
to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless it is the survivor; (iv) sell all or substantially
all of its assets; (v) make certain acquisitions; (vi) make certain investments; (vii) make certain capital expenditures; (viii)
make distributions other than from available cash; (ix) create obligations for some lease payments; (x) engage in transactions
with affiliates; (xi) engage in other types of business; and (xii) incur indebtedness or grant certain liens through its joint
ventures.
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 5.00 to 1.00. The maximum
107
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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 3.25 to
1.00. The minimum consolidated 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 2.75 to 1.00. The Partnership was in compliance with the covenants contained in the Credit Facility as of
December 31, 2012.
The Credit Facility also contains certain default provisions relating to Martin Resource Management. If Martin
Resource Management no longer controls the Partnership’s general partner, or if Ruben Martin is not the Chief Executive
Officer of the Partnership’s general partner or a successor acceptable to the administrative agent and lenders providing more
than 50% of the commitments under the Credit Facility is not appointed, 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 the Credit Facility if it is deemed to
have a material adverse effect on the Partnership. Any event of default and corresponding acceleration of outstanding balances
under the Credit Facility could require the Partnership to refinance such indebtedness on unfavorable terms and would have a
material adverse effect on the Partnership’s financial condition and results of operations as well as its ability to make
distributions to unitholders.
The Partnership is required to make certain prepayments under the Credit Facility. If the Partnership receives greater
than $15,000 from the incurrence of indebtedness other than under the Credit Facility, it must prepay indebtedness under the
Credit Facility with all such proceeds in excess of $15,000. The Partnership must prepay revolving loans under the Credit
Facility with the net cash proceeds from any issuance of its equity. The Partnership must also prepay indebtedness under the
Credit Facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the Credit Facility
requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by
April 15, 2016. The Credit Facility contains customary events of default, including, without limitation, payment defaults, cross-
defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults.
In March 2010, the Partnership terminated all of its existing interest rate swaps resulting in termination fees of $3,850.
In August, 2011, the Partnership terminated all of its existing interest rate 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 Senior 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. The Partnership received a termination benefit of $2,800 upon cancellation of these swap agreements.
The Partnership paid cash interest in the amount of $29,239, $22,818, and $23,663 for the years ended December 31,
2012, 2011 and 2010, respectively. Capitalized interest was $1,136, $624, and $130 for the years ended December 31, 2012,
2011 and 2010, respectively.
(15)
Equity Offerings
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
108
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. The net proceeds were used to reduce
the outstanding balance under its revolving credit facility.
(16)
Partners' Capital
As of December 31, 2012, partners’ capital consists of 26,566,776 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 approximatley 19.2% of the Partnership's outstanding common
limited partnership units and a 2% general partnership interest.
The Partnership Agreement contains specific provisions for the allocation of net income and losses to each of the
partners for purposes of maintaining their respective partner capital accounts.
Distributions of Available Cash
The Partnership distributes all of its Available Cash (as defined in the Partnership Agreement) within 45 days after the
end of each quarter to unitholders of record and to the general partner. Available Cash is generally defined as all cash and cash
equivalents of the Partnership on hand at the end of each quarter less the amount of cash reserves its general partner
determines in its reasonable discretion is necessary or appropriate to: (i) provide for the proper conduct of the 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.
(17)
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 is 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 will be used to replace the tank and, in the event the proceeds
exceed the net book value of the tank that was destroyed, the Partnership will recognize a gain equal to the amount of the
excess.
(18)
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, on the consolidated balance sheet.
Woodlawn, a subsidiary of the Partnership, is 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 $8,681, $11 and $0, related to the
operation of the subsidiary, were recorded for the years ended December 31, 2012, 2011 and 2010, 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
109
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
and equipment. A deferred tax benefit of $7,657, $139 and $415 related to the Woodlawn basis differences was recorded for
the years ended December 31, 2012, 2011 and 2010, respectively. A deferred tax expense of $402, $622, and $452 related to
the Cross basis differences was recorded for the year ended December 31, 2012, 2011 and 2010, respectively. A deferred tax
liability of $0 and $9,697 related to these basis differences existed at December 31, 2012 and 2011, 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 $1,575,
$713 and $932 were recorded in income tax expense for the years ended December 31, 2012, 2011 and 2010, respectively.
An income tax liability of $10,239, and $926 existed at December 31, 2012 and 2011, respectively.
The components of income tax expense from operations recorded for the years ended December 31, 2012, 2011 and
2010 are as follows:
Current:
Federal
State
Deferred:
Federal
Total income tax expense
2012
2011
2010
$
$
$
10,516
1,894
12,410
(7,255)
5,155
$
1,303
975
2,278
483
2,761
Total income tax expense was allocated to continuing and discontinued operations as follows:
Income tax expense from continuing operations:
Current:
Federal
State
Deferred:
Federal
Total income tax expense from continuing operations
Income tax expense (benefit) from discontinued operations:
Current:
Federal
State
Deferred:
Federal
Total income tax expense (benefit) from discontinued operations
110
$
$
$
$
2012
2011
1,835
1,320
3,155
402
3,557
2012
8,681
574
9,255
$
$
$
1,292
958
2,250
622
2,872
2011
11
17
28
(7,657)
1,598
$
(139)
(111) $
$
$
$
$
$
1,043
1,145
2,188
37
2,225
2010
1,043
1,127
2,170
452
2,622
2010
0
18
18
(415)
(397)
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
(19)
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 of the Notes to
Consolidated Financial Statements. The Partnership evaluates the performance of its reportable segments based on operating
income. There is no allocation of administrative expenses or interest expense.
The natural gas services segment information below excludes the discontinued operations of the Prism Assets for all
periods. See Note 5.
Operating
Revenues
Intersegment
Eliminations
Operating
Revenues
After
Eliminations
Depreciation
and
Amortization
Operating
Income
(Loss) after
Eliminations
Capital
Expenditures
Year Ended December 31,
Terminalling and storage
Natural gas services
Sulfur services
Marine transportation
Indirect selling, general,
and administrative
Total
Year Ended December 31,
Terminalling and storage
Natural gas services
Sulfur services
Marine transportation
Indirect selling, general,
and administrative
Total
$
322,175
825,506
261,584
88,815
—
$ 1,498,080
$
283,175
611,749
275,044
83,971
—
$ 1,253,939
Year Ended December 31,
Terminalling and storage
Natural gas services
Sulfur services
Marine transportation
Indirect selling, general,
and administrative
Total
$
$
199,744
442,005
165,078
82,635
—
889,462
$
$
$
$
$
$
(4,652) $
—
—
(3,067)
317,523
825,506
261,584
85,748
—
—
(7,719) $ 1,490,361
(4,414) $
—
—
(7,035)
278,761
611,749
275,044
76,936
—
—
(11,449) $ 1,242,490
(4,354) $
—
—
(4,993)
—
(9,347) $
195,390
442,005
165,078
77,642
—
880,115
$
$
$
$
$
$
22,976
601
7,371
11,115
—
42,063
19,814
578
6,725
13,159
—
40,276
17,330
571
6,262
12,721
—
36,884
$
$
$
$
$
$
$
$
$
$
$
25,403
15,395
41,909
3,174
(12,046)
73,835
20,619
7,487
34,595
(6,485)
(8,864)
47,352
20,034
7,744
20,166
6,524
(6,386)
48,082
$
72,877
434
11,477
8,852
—
93,640
48,287
620
16,158
12,137
—
77,202
8,656
257
7,107
2,159
—
18,179
Revenues from one customer in the natural gas services segment were $150,246, $137,177 and $92,265 for the years
ended December 31, 2012, 2011 and 2010, respectively. Revenues from one customer in the sulfur services segment were
$87,820, $111,172 and $50,357 for the years ended December 31, 2012, 2011 and 2010, respectively.
111
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The Partnership's assets by reportable segment, which exclude assets held for sale of $212,787 as of December 31,
2011, are as follows:
Total assets:
Terminalling and storage
Natural gas services
Sulfur services
Marine transportation
Total assets
2012
2011
$
$
376,330
331,064
155,639
149,963
1,012,996
$
$
282,106
268,502
162,289
143,424
856,321
(20)
Quarterly Financial Information
Consolidated Quarterly Income Statement Information
2012
Revenues
Operating Income
Equity in earnings of unconsolidated entities
Income from continuing operations
Income from discontinued operations
Net income
Limited partners' interest in net income per limited partner unit
2011
Revenues
Operating Income
Equity in earnings of unconsolidated entities
Income from continuing operations
Income from discontinued operations
Net income
Limited partners' interest in net income per limited partner unit
(21)
Commitments and Contingencies
(Unaudited)
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(Dollar in thousands, except per unit amounts)
$
$
$
$
$
$
348,326
19,781
233
10,742
1,725
12,467
0.40
$
$
$
333,844
19,215
1,215
8,461
1,984
10,445
0.25
$
$
$
354,091
16,245
(678)
8,743
63,603
72,346
3.07
$
$
$
454,100
18,594
(1,883)
9,176
(2,447)
6,729
0.27
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(Dollar in thousands, except per unit amounts)
281,802
14,871
(705)
4,757
2,433
7,190
0.31
$
$
$
292,413
11,916
(1,368)
4,952
3,030
7,982
0.37
$
$
$
321,117
9,177
(1,425)
2,285
2,265
4,550
0.20
$
$
$
347,158
11,388
(1,254)
1,373
1,664
3,037
0.06
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.
On October 2, 2012, the Partnership announced that the ongoing litigation and disputes since May 2008 involving the
shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among
other things, provided for a resolution of all the lawsuits and disputes. In connection with the settlement, Martin Resource
Management transferred 1,500,000 common units of the Partnership to KCM, LLC.
(22)
Condensed Consolidating Financial Information
The Partnership has no significant operations independent of its subsidiaries. As of December 31, 2012, the
Partnership's obligations under the outstanding Senior Notes (see Note 14) were fully, jointly and severally guaranteed, by all
112
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
of its wholly-owned subsidiaries other than Redbird and MOP Midstream Holdings, LLC ("MMH"). Redbird is a holding
company for the Partnership's investment in Cardinal. MMH is a holding company for the Partnership's investment in Caliber.
The guarantees are unconditional except for certain customary circumstances in which a subsidiary would be released from the
guarantee under the indentures. Separate financial statements for each of the Partnership's guarantor subsidiaries are not
provided because such information would not be material to its investors or lenders. Neither the Parent nor Martin Midstream
Finance Corp. (collectively, the "Co-Issuers") have independent assets or operations, therefore the Co-Issuers' financial
information has been combined with the financial information of the guarantor subsidiaries. The tables below present
condensed consolidating financial information for the Partnership and its combined guarantor subsidiaries, and combined non-
guarantor subsidiaries as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011 and 2010. The
financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the
subsidiaries operated as independent entities.
Condensed Consolidating Balance Sheet
December 31, 2012
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
$
$
$
552,282
$
— $
(237,367) $
510,381
—
(83,058)
33,391
—
154,309
—
—
—
—
83,058
—
314,915
510,381
154,309
—
33,391
1,012,996
$
154,309
$
(154,309) $
1,012,996
178,482
$
237,367
$
(237,367) $
178,482
Assets
Total current assets
Property, plant and equipment, net
Investment in unconsolidated entities
Investment in subsidiary
Total other assets
Liabilities and partners’ capital
Total current liabilities
Long-term debt and capital leases, less current maturities
Other long-term obligations
Partners’ capital
Total liabilities & partner's capital
474,992
1,560
357,962
—
—
—
—
(83,058)
83,058
474,992
1,560
357,962
$
1,012,996
$
154,309
$
(154,309) $
1,012,996
Condensed Consolidating Balance Sheet
December 31, 2011
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
$
$
$
579,196
$
433,258
—
124
25,300
— $
(101,251) $
—
132,605
—
—
—
—
(124)
—
477,945
433,258
132,605
—
25,300
1,037,878
$
132,605
$
(101,375) $
1,069,108
262,195
$
101,251
$
(101,251) $
262,195
Assets
Total current assets
Property, plant and equipment, net
Investment in unconsolidated entities
Investment in subsidiary
Total other assets
Liabilities and partners’ capital
Total current liabilities
Long-term debt and capital leases, less current maturities
Other long-term obligations
Partners’ capital
Total liabilities & partner's capital
458,941
10,785
305,957
—
—
31,354
—
—
(124)
458,941
10,785
337,187
$
1,037,878
$
132,605
$
(101,375) $
1,069,108
113
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Condensed Consolidating Statements of Operations
Year ended December 31, 2012
Total revenues
Total costs and expenses
Other operating (loss)
Operating income
Equity in (loss) of unconsolidated entities
Equity in (loss) of subsidiary
Debt prepayment premium
Interest expense
Other, net
Net income before taxes
Income tax (expense)
Income from continuing operations
Income from discontinued operations, net of income taxes
Net income
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
$
$
1,490,361
1,416,108
(418)
73,835
— $
—
—
—
— $
—
—
—
1,490,361
1,416,108
(418)
73,835
—
(627)
(2,470)
(30,665)
606
40,679
(3,557)
37,122
(1,113)
—
—
—
486
(627)
—
(627)
64,865
101,987
$
$
—
(627) $
—
627
—
—
—
627
—
627
—
627
$
(1,113)
—
(2,470)
(30,665)
1,092
40,679
(3,557)
37,122
64,865
101,987
Condensed Consolidating Statements of Operations
Year ended December 31, 2011
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
$
1,242,490
1,196,464
1,326
47,352
—
(4,752)
(26,781)
420
16,239
(2,872)
13,367
9,392
22,759
— $
—
—
—
(4,752)
—
—
—
(4,752)
—
(4,752)
—
(4,752) $
$
— $
—
—
—
1,242,490
1,196,464
1,326
47,352
—
4,752
—
—
4,752
—
4,752
—
4,752
$
(4,752)
—
(26,781)
420
16,239
(2,872)
13,367
9,392
22,759
Total revenues
Total costs and expenses
Other operating income
Operating income
Equity in earnings (loss) of unconsolidated entities
Equity in net income of subsidiary
Interest expense
Other, net
Net income before taxes
Income tax (expense)
Income from continuing operations
Income from discontinued operations, net of income taxes
Net income
$
$
114
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Condensed Consolidating Statements of Operations
Year ended December 31, 2010
Total revenues
Total costs and expenses
Other operating income
Operating income
Equity in earnings of unconsolidated entities
Gain from ownership change in unconsolidated entity
Equity in net income of subsidiary
Interest expense
Other, net
Net income before taxes
Income tax (expense)
Income from continuing operations
Income from discontinued operations, net of income taxes
Net income
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
$
$
880,115
832,261
228
48,082
—
—
8,949
(35,322)
385
22,094
(2,622)
19,472
8,061
27,533
$
$
— $
—
—
—
— $
—
—
—
2,536
6,413
—
—
—
8,949
—
8,949
—
8,949
—
—
(8,949)
—
—
(8,949)
—
(8,949)
—
(8,949) $
$
880,115
832,261
228
48,082
2,536
6,413
—
(35,322)
385
22,094
(2,622)
19,472
8,061
27,533
Condensed Consolidating Statements of Cash Flows
Year ended December 31, 2012
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Net cash provided by operating activities
Net cash provided by (used in) investing activities
Net cash provided by (used in) financing activities
$
$
$
32,678
$
— $
— $
(96,803) $
(90,568) $
172,335
$
69,021
$
90,568
$
(172,335) $
32,678
(15,036)
(12,746)
Condensed Consolidating Statements of Cash Flows
Year ended December 31, 2011
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
$
$
$
91,362
$
— $
— $
91,362
(202,655) $
(93,652) $
93,652
$
(202,655)
100,179
$
93,652
$
(93,652) $
100,179
Condensed Consolidating Statements of Cash Flows
Year ended December 31, 2010
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
39,178
$
— $
— $
(91,016) $
(12,628) $
12,628
$
57,262
$
12,628
$
(12,628) $
39,178
(91,016)
57,262
$
$
$
115
(23)
Subsequent Events
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$50,800. The
purchase was funded with borrowings under the Partnership's revolving credit facility.
Issuance of Senior Notes. On February 11, 2013, the Partnership completed a private placement of $250.0 million in
aggregate principal amount of 7.25% senior unsecured notes due 2021 to qualified institutional buyers under Rule 144A. The
Partnership 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 the Partnership's revolving credit facility.
Quarterly Distribution. On January 24, 2013, The Partnership declared a quarterly cash distribution of $0.77 per
common unit for the fourth quarter of 2012, or $3.08 per common unit on an annualized basis, which was paid on February 14,
2013 to unitholders of record as of February 7, 2013.
Common Unit Grants. On January 2, 2013, the Partnership issued 57,500 restricted common units under the
Partnership's long-term incentive plan to the executive officers of the general partner and certain Martin Resource Management
employees who provide services to the Partnership. These restricted units vest 100% on January 1, 2016.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
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,
2012. 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, 2012.
(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, our management concluded that our internal control over financial reporting was
effective as of December 31, 2012. The effectiveness of our internal control over financial reporting as of December 31, 2012
has been audited by KPMG LLP, our independent registered public accounting firm, as stated in their report appearing on page
74.
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. Other Information
None
116
PART III
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 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 our 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.
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Name
Ruben S. Martin
Robert D. Bondurant
Randall L. Tauscher
Wesley M. Skelton
Chris Booth
C. Scott Massey
Joe N. Averett, Jr.
Charles H. Still
Byron R. Kelley
Age
61
54
47
65
43
60
70
70
65
Position with the General Partner
President, Chief Executive Officer and Director
Executive Vice President and Chief Financial Officer
Executive Vice President and Chief Operating Officer
Executive Vice President, Chief Administrative Officer and Controller
Executive Vice President, General Counsel and Secretary
Director
Director
Director
Director
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 as served on the board of directors of Penn Virginia Corporation and Capital
118
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 2010. Currently, Mr. Still is of counsel with the law firm of Fulbright & Jaworski L.L.P. Mr. Still was an associate
and partner in Fulbright & Jaworski L.L.P. from 1968 until his retirement in 2008. Mr. Still is currently on the board of
directors of OYO Geospace Corporation. Mr. Still holds a Doctor of Jurisprudence degree from the University of Texas and a
Bachelor of Business Administration in accounting from Texas Tech University. He is an Adjunct Professor of Law at the
University of Texas. Mr. Still was selected to serve as a director on our general partner's board of directors due to his extensive
corporate legal experience.
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. Mr. Kelley is currently 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. 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.
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, 2012 to December 31, 2012, the board of directors of our general partner held 15 meetings. All
directors then in office attended each of these meetings, either in person, by teleconference or by videoconference with the
exception of Ruben S. Martin, who was not in attendance at the meeting of the board of directors on the date of June 13, 2012,
and Joe N. Averett, Jr., who was not in attendance at the meeting of the board of directors on the date of July 27, 2012.
Additionally, the board of directors undertook action one time during 2012 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, 2012 to December 31,
2012, and a brief description of the functions performed by each committee are set forth below:
Conflicts Committee (12 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
119
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 2012 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 (2 meetings). 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
120
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, 2012.
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. We reimbursed Martin Resource Management for $157.8
million of direct costs and expenses for the twelve months ended December 31, 2012 compared to $142.0 million for the
twelve months ended December 31, 2011. 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, 2012, 2011 and 2010, the Conflicts Committee of our general partner
approved reimbursement amounts of $7.6, $4.8 and $3.8 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.”
Item 11. Executive Compensation
Compensation Discussion and Analysis
Background
We are required to provide information regarding the compensation program in place as of December 31, 2012, 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, 2012, 2011 and 2010, the Conflicts Committee of our general partner approved
reimbursement amounts of $7.6, $4.8 and $3.8 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
121
practices of Martin Resource Management. During 2012, 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 to 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 near 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 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 of our general
partner 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,
122
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 2012 Compensation Amounts
During 2012, 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 and in one case, a cash award, based upon
their service to us.
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 42.0% of the aggregate annual base
salaries paid to the Named Executive Officers by Martin Resource Management during 2012. 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 increased during
2012 by Martin Resource Management by 3%.
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.
Employee Benefit Plan Awards and Other Compensation. No employee benefit plan awards or other compensation
were granted to the Named Executive Officers in 2012 based upon their service to us.
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
123
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 30, 2012, we issued 1,250 restricted common units to each of our four non-employee 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 non-employee 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 non-employee 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, non-employee directors
under our LTIP. These restricted common units vest in equal installments of 375 units on January 24, 2011, 2012, 2013 and
2014, respectively.
On May 3, 2010, we issued 1,000 restricted common units to each of our three independent, non-employee directors
under our LTIP. These restricted common units vest in equal installments of 250 units on January 24, 2011, 2012, 2013 and
2014, respectively.
On August 3, 2009, we issued 1,000 restricted common units to each of its three independent, non-employee directors
under its long-term incentive plan from treasury shares purchased by us in the open market for $78. These units vest in 25%
increments beginning in January 2010 and will be fully vested in January 2013.
On May 5, 2008, we issued 1,000 restricted common units to each of its three independent, non-employee directors
under its long-term incentive plan from treasury shares purchased by us in the open market for $93. These units vest in 25%
increments beginning in January 2009 and will be fully vested in January 2012.
124
Unit Options. The LTIP currently permits the grant of options covering common units. As of March 4, 2013, 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 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 Resource Management Employees' Stock Profit Sharing Plan. Martin Resource Management maintains an
employee stock profit sharing plan that covers employees who satisfy certain minimum age and service requirements. This
employee stock ownership 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. Participants in the Martin Employees’ Stock Profit Sharing Plan become
100% vested upon completing three years of vesting service or upon their attainment of age 65, permanent disability or death
during employment. Any forfeitures of non-vested accounts are allocated to the accounts of employed participants. Except for
rollover contributions, participants are not permitted to make contributions to the Martin Employees’ Stock Profit Sharing Plan.
125
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.
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, 2012, 2011 and 2010.
Name and
Principal Position
Ruben S. Martin, President and Chief Executive
Officer
Robert D. Bondurant, Executive Vice President and
Chief Financial Officer
Randall L. Tauscher, Executive Vice President and
Chief Operating Officer
Wesley M. Skelton, Executive Vice President,
Controller and Chief Administrative Officer
Year
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
Donald R. Neumeyer, Former Executive Vice
President(1)
2012 (1)
Chris H. Booth, Executive Vice President, General
Counsel and Secretary
2011
2010
2012
2011
2010
(1) Represents salary earned through date of resignation on October 31, 2012.
126
Salary ($)
Bonus ($)
Total
Compensation
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
283,593
124,371
100,099
151,307
125,761
53,857
224,502
210,548
163,644
133,380
124,371
117,404
72,363
75,211
52,653
94,755
88,814
86,830
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
— $
— $
— $
— $
— $
— $
— $
— $
$
107,500
— $
— $
— $
— $
— $
— $
— $
— $
— $
283,593
124,371
100,099
151,307
125,761
53,857
224,502
210,548
271,144
133,380
124,371
117,404
72,363
75,211
52,653
94,755
88,814
86,830
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 $12,500 each which are paid by the general partner. Martin Resource Management employees who
are a member of the board of directors of our general partner do not receive any additional compensation for serving in such
capacity. Officers of our general partner who also serve as directors will not receive additional compensation. All directors of
our general partner are entitled to reimbursement for their reasonable out-of-pocket expenses in connection with their travel to
and from, and attendance at, meetings of the board of directors or committees thereof. Each director will be fully indemnified
by us for actions associated with being a director to the extent permitted under Delaware law.
The following table sets forth the compensation of our board members for the period from January 1, 2012 through
December 31, 2012.
Name
Ruben S. Martin
C. Scott Massey (2)
Howard Hackney (1) (2)
Joe N. Averett, Jr. (2)
Charles H. “Hank” Still (2)
Byron R. Kelley (2)
Fees
Earned
Paid in
Cash ($)
N/A
50,000
37,500
50,000
50,000
50,000
$
$
$
$
$
Stock
Awards ($)
N/A
44,000
44,000
44,000
44,000
44,000
$
$
$
$
$
$
$
$
$
$
Total ($)
N/A
94,000
81,500
94,000
94,000
94,000
(1) Represents fees paid to Howard Hackney through his date of resignation on July 30, 2012.
(2) On April 30, 2012, the Partnership issued 1,250 restricted common units to each of five non-employee directors,
C. Scott Massey, Howard Hackney, Joe N. Averett, Jr., Byron R. Kelley, and Charles H. “Hank” Still, under our
LTIP. These restricted common units vest in equal installments of 312.5 units on January 24, 2013, 2014, 2015 and
2016, 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 30, 2012, 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:
Byron R. Kelley, Committee Chair
Joe N. Averett Jr.
C. Scott Massey
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.
127
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 4, 2013 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.
Name of Beneficial Owner(1)
Martin Resource Management Corporation(3)
Martin Resource, LLC(3)
Cross Oil Refining & Marketing Inc.(3)
Ruben S. Martin(4)
Wesley M. Skelton
Robert D. Bondurant
Chris Booth
Randall Tauscher
C. Scott Massey(5)(6)
Joe N. Averett, Jr.(5)(6)
Charles H. Still((5)6)
Byron R. Kelley(5)(6)
All directors and executive officers as a group (9 persons)(6)
Common
Units
Beneficially
Owned
5,093,267
4,203,823
889,444
5,163,288
6,624
16,010
4,207
12,132
15,500
9,000
6,000
2,500
5,235,261
Percentage of
Common Units
Beneficially
Owned(2)
19.1%
15.8%
3.3%
19.4%
—
—
—
—
—
—
—
—
19.7%
(1) The address for Martin Resource Management Corporation and all of the individuals listed in this table, unless
otherwise indicated, is c/o Martin Midstream Partners L.P., 4200 Stone Road, Kilgore, Texas 75662.
(2) The percent of class shown is less than one percent unless otherwise noted.
(3) Martin Resource Management is the owner of Martin Resource, LLC and Cross Oil Refining & Marketing Inc., and
as such may be deemed to beneficially own the common units held by Martin Resource LLC and Cross Oil
Refining & Marketing Inc. The 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.
(4) 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.
(5) On April 30, 2012, we issued 1,250 restricted common units to each of five non-employee 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 non-employee 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 non-employee directors. These
units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015.
On August 2, 2010, we issued 1,500 restricted common units to each of two new non -employee directors.
These units vest in 25% increments beginning in January 2011 and will be fully vested in January 2014.
128
On May 3, 2010, we issued 1,000 restricted common units to each of its non-employee directors. These units
vest in 25% increments beginning in January 2011 and will be fully vested in January 2014.
On August 3, 2009, we issued 1,000 restricted common units to each of our three independent directors.
These units vest in 25% increments beginning in January 2010 and will be fully vested in January 2013.
On May 5, 2008, we issued 1,000 restricted common units to each of our three independent directors. These
units vest in 25% increments beginning in January 2009 and will be fully vested in January 2012.
On May 3, 2007, we issued 1,000 restricted common units to each of our three independent directors. These
units vest in 25% increments beginning in January 2008 and were fully vested in January 2011.
On January 24, 2006, we issued 1,000 restricted common units to each of our three independent
directors. These units vest in 25% increments beginning in January 2007 and were fully vested in January 2010.
Mr. Massey may be deemed to be the beneficial owner of 1,000 common units held by his wife.
(6) 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 our general partner and, together with our general partner, owns approximately
19.1% of our outstanding common limited partner units as of March 4, 2013. The table below sets forth information as of
March 4, 2013 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.
Name of Beneficial Owner(1)
Martin Employees' Stock Profit Sharing Trust (2)
Martin Resource Management ESOP Trust (3)
Wilmington Trust Retirement and Institutional Services Company (3)
CNRT, LLC (4)
RSM III Investments, Ltd. (5).
Ruben S. Martin III Dynasty Trust (6)
Martin Transport, Inc. (7)
Ruben S. Martin (4) (7) (8)
Wesley M. Skelton (2) (9) (10) (11)
Robert D. Bondurant(9) (10) (11)
Randall L. Tauscher (9)(11)
Executive officers and directors as a group (4 individuals)
* Represents less than 1.0%
Beneficial Ownership of
Common Stock
Number of
Shares
Percent of
Outstanding
48,050.00
95,112.50
95,112.50
56,666.67
56,666.67
16,000.00
1,000.00
62,300.00
50,750.00
5,000.00
2,125.00
120,175.00
26.6%
37.0%
37.0%
31.4%
31.4%
8.9%
*
34.5%
28.1%
2.8%
1.2%
66.5%
(1) The business address of each shareholder, director and executive officer of Martin Resource Management
Corporation is c/o Martin Resource Management Corporation, 4200 Stone Road, Kilgore, Texas 75662.
(2) Wesley M. Skelton is a co-trustee of the Martin Employees' Stock Profit Sharing Trust and exercises shared control
over the voting and disposition of the securities owned by this trust. As a result, he may be deemed to be the
beneficial owner of the securities held by such trust; thus, the number of shares of common stock reported herein as
129
beneficially owned by him includes the 48,050 shares owned by such trust. Mr. Skelton disclaims beneficial
ownership of these 48,050 shares.
(3) Wilmington Trust Retirement and Institutional Services Company ("Wilmington") is the trustee of the Martin
Resource Management ESOP Trust and exercises control over the voting and disposition of the securities owned by
this trust. As a result, Wilmington 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 Wilmington includes the
18,450 shares owned by such trust. The trust also owns 76,662.50 convertible preferred shares which may be
converted into common shares on a one-to-one basis at any time and thus, the number of shares of preferred stock
reported herein as beneficially owned by Wilmington includes the preferred shares owned by such trust.
Wilmington disclaims beneficial ownership of these 95,112.50 shares.
(4) Ruben S. Martin is the president of RSM III Management Corp., which is the general partner of RSM III
Investments Ltd., which is the sole member of CNRT, LLC. Courtney Stovall and Robin Martin, as managers of
CNRT, LLC exercise control over the voting of the securities owned by this entity. However, as a result of his
position with the general partner of the sole member of this entity, Ruben S. Martin may be deemed to be the
beneficial owner of the securities held by such entity; thus, the number of shares of common stock reported herein
as beneficially owned by such individual includes the 56,666.67 shares owned by such entity.
(5) RSM III Investments Ltd. is the sole member of CNRT, LLC and, as such, may be deemed to be the beneficial
owner of the securities owned by CNRT, LLC.
(6) Bill Bankston is the trustee of the Ruben S. Martin III Dynasty Trust and exercises control over the voting and
disposition of the securities owned by the trust. As a result, he may be deemed to be the beneficial owner of the
securities held by the trust. These 16,000 shares have been pledged as security to a third party to secure payment
for a loan made by such third party.
(7) Ruben S. Martin beneficially owns securities in Martin Resource Management representing approximately 34.5% of
the voting stock thereof and serves as its Chairman of the Board and President. Martin Transport, Inc. is a wholly
owned subsidiary of Martin Resource Management. As a result, Ruben S. Martin may be deemed to be the
beneficial owner of the securities held by Martin Transport, Inc.; thus, the number of shares of common stock
reported herein as beneficially owned by Ruben S. Martin includes the 1,000 shares owned by Martin Transport,
Inc.
(8) Ruben S. Martin directly owns 4,633.33 shares of common stock.
(9) Messrs., Skelton, Bondurant and Tauscher each have the right to acquire 750, 1,250, and 1,250 shares, respectively,
by virtue of options issued under Martin Resource Management’s non-qualified stock option plan.
(10) Messrs. Skelton and Bondurant own securities in Martin Resource Management of 700 and 2,500 shares of
common stock, respectively, obtained by the exercise of options issued under Martin Resource Management ’s
nonqualified stock option plan.
(11) Messrs. Skelton, Bondurant and Tauscher own securities in Martin Resource Management of 1,250, 1,250 and 875,
restricted common shares, respectively, representing shares by virtue of restricted stock issued under Martin
Resource Management’s 2007 Long-Term Incentive Plan. Fifty percent of these shares have vested and have been
reissued without restriction.
The following table sets forth information regarding securities authorized for issuance under our equity compensation
plans as of December 31, 2012:
130
Equity Compensation Plan Information
Number of
securities to
be
issued upon
exercise
of
outstanding
options,
Warrants
and rights
(a)
Weighted-
average
exercise
price of
outstanding
options,
warrants
and rights
(b)
N/A
— $
— $
N/A
—
—
Number of
securities
remaining
available for
future issuance
under equity
compensation
plans (excluding
securities reflected
in
column (a))
(c)
N/A
688,400
688,400
Plan Category
Equity compensation plans approved by security holders
Equity compensation plans not approved by security holders(1)
Total
(1) Our general partner has adopted and maintains the Martin Midstream Partners L.P. Long-Term Incentive Plan. For
a description of the material features of this plan, please see “Item 11. Executive Compensation – Employee Benefit
Plans – Martin Midstream Partners L.P. Long-Term Incentive Plan”.
In April 2012, we issued 6,250 restricted common units to non-employee directors under our long-term incentive plan
from purchased by us in the open market for $222. These restricted common units vest in equal installments of 312.5 units on
January 24, 2013, 2012, 2015 and 2016, respectively.
In May 2011, we issued 6,250 restricted common units to non-employee directors under our long-term incentive plan
from 5,750 treasury units purchased by us in the open market for $235 and 500 treasury units from forfeitures. These restricted
common units vest in equal installments of 312.5 units on January 24, 2012, 2013, 2014 and 2015, respectively.
In February 2011, we issued 9,100 restricted common units to certain Martin Resource Management employees under
its long-term incentive plan from 9,100 treasury units purchased by us in the open market for $347. These units vest in 25%
increments beginning in February 2013 and will be fully vested in February 2015.
On August 2, 2010, we issued 1,500 restricted common units to each of two new independent, non-employee directors
under our long-term incentive plan. These restricted common units vest in equal installments of 375 units on January 24, 2011,
2012, 2013 and 2014, respectively.
On May 3, 2010, we issued 1,000 restricted common units to each of our three independent, non-employee directors
under our long-term incentive plan. These restricted common units vest in equal installments of 250 units on January 24, 2011,
2012, 2013 and 2014, respectively.
On August 3, 2009, we issued 1,000 restricted common units to each of its three independent, non-employee directors
under its long-term incentive plan from treasury shares purchased by us in the open market for $78. These units vest in 25%
increments beginning in January 2010 and will be fully vested in January 2013.
On May 5, 2008, we issued 1,000 restricted common units to each of its three independent, non-employee directors
under its long-term incentive plan from treasury shares purchased by us in the open market for $93. These units vest in 25%
increments beginning in January 2009 and will be fully vested in January 2012.
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 4, 2013. Our general partner is a wholly-owned
subsidiary of Martin Resource Management. Our general partner owns a 2.0% general partner interest in us and 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.
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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.
Formation Stage
The consideration received by our
general partner and Martin
Resource Management for the
transfer of assets to us
Operational Stage
Distributions of available cash to
our general partner
Payments to our general partner
and its affiliates
Withdrawal or removal of our
general partner
4,253,362 subordinated units (All of the original 4,253,362 subordinated units issued
to Martin Resource Management have been converted into common units on a one-for-
one basis since the formation of the Partnership. 850,672 subordinated units were
converted on each of November 14, 2005, 2006, 2007 and 2008, respectively, and
850,674 subordinated units were converted on November 14, 2009)
2% general partner interest; and
the incentive distribution rights.
We will generally make cash distributions 98% to our unitholders, including Martin
Resource Management as holder of all of the subordinated units, and 2% to our general
partner. In addition, if distributions exceed the minimum quarterly distribution and other
higher target levels, our general partner will be entitled to increasing percentages of the
distributions, up to 50% of the distributions above the highest target level as a result of
its incentive distribution rights.
Assuming we have sufficient available cash to pay the full minimum quarterly
distribution on all of our outstanding units for four quarters, our general partner would
receive an annual aggregate distribution of approximately $1.8 million on its 2.0%
general partner interest.
Martin Resource Management is entitled to reimbursement for all direct expenses it or
our general partner incurs on our behalf. The direct expenses include the salaries and
benefit costs employees of Martin Resource Management who provide services to
us. Our general partner has sole discretion in determining the amount of these
expenses. In addition to the direct expenses, Martin Resource Management is entitled to
reimbursement for a portion of indirect general and administrative and corporate
overhead expenses. Under the omnibus agreement, we are required to reimburse Martin
Resource Management for indirect general and administrative and corporate overhead
expenses. The Conflicts Committee will review and approve future adjustments in the
reimbursement amount for indirect expenses, if any, annually. Please read “Agreements
— Omnibus Agreement” below.
If our general partner withdraws or is removed, its general partner interest and its
incentive distribution rights will either be sold to the new general partner for cash or
converted into common units, in each case for an amount equal to the fair market value
of those interests.
Liquidation Stage
Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to
receive liquidating distributions according to their particular capital account balances.
Agreements
Omnibus Agreement
We and our general partner are parties to an omnibus agreement with Martin Resource Management (the "Onimbus
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.
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;
132
•
•
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,
operating an underground NGL storage facility in Arcadia, Louisiana,
operating an environmental consulting company,
operating an engineering services company, and
building and marketing of sulfur processing equipment.
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 October 1, 2012 through December 31, 2013, the Conflicts
Committee of our general partner approved an annual reimbursement for indirect expenses of $10,622. For the years ended
December 31, 2012, 2011 and 2010, the Conflicts Committee of our general partner approved and we reimbursed Martin
Resource Management of $7.6, $4.8 and $3.8 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
133
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 of our general partner’s board of
directors. 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 of our general partner if such
amendment would adversely affect the unitholders. The Omnibus Agreement was amended on November 25, 2009, to permit
us to provide refining services to Martin Resource Management. Such amendment was approved by the conflicts committee of
our general partner. 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.
Other Agreements
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.
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Talen's Agreements. In connection with the Talen's acquisition, three new agreements were executed, all with effective
dates of December 31, 2012. Under the terms of these contracts, Talen's provides terminal services and marine transportation
services to Martin Resource Management.
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 has a 12 year term which expires November 24, 2021. 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 an agreement dated August 1, 2008 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.
135
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.
2010 Public Offerings.
In February 2010, we completed a public offering of 1,650,000 common units, resulting in net proceeds of $50.6 million,
after payment of underwriters’ discounts, commissions and offering expenses. Our general partner contributed $1.1 million in
cash to us in conjunction with the offering in order to maintain its 2% general partner interest in us. The net proceeds were used
to pay down revolving debt under our credit facility.
On August 17, 2010, we completed a public offering of 1,000,000 million common units resulting in net proceeds of
approximately $28.1 million after payment of underwriters’ discounts. We used the net proceeds of $28.1 million to redeem
from subsidiaries of Martin Resource Management an aggregate number of common units equal to the number of common
units issued in the offering. Martin Resource Management reimbursed us for our payments of commissions and offering
expenses. As a result of these transactions, our general partner was not required to contribute cash to us in conjunction with
the issuance of these units in order to maintain its 2% general partner interest in us since there was no net increase in the
outstanding limited partner units.
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 were
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.
Acquisition of Offshore Tank Barge. On December 22, 2010, we acquired a 60,000 bbl offshore tank barge from
Martin Resource Management for a total purchase price of $17.0 million. We paid cash in the amount of $9.6 million and
assumed a note payable to a third party for $7.4 million. The net book value of the acquired assets was $16.8 million and was
recorded in property, plant, and equipment. The remaining $0.2 million was recorded as a reduction of partners' capital.
Acquisition of Terminalling Assets. On August 26, 2010, we acquired certain shore-based marine terminalling assets
from Martin Resource Management for $11.7 million. The net book value of the acquired assets was $7.3 million and was
recorded in property, plant and equipment. The remaining $4.4 million was recorded as a reduction of partners' capital. These
assets are located in Theodore, Alabama and Pascagoula, Mississippi.
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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.
Approval and Review of Related Party Transactions
If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a
related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the
board of directors of our general partner or to our management, as appropriate. If the board of directors is involved in the
approval process, it determines whether to refer the matter to the Conflicts Committee of our general partner's board of
directors, as constituted under our limited partnership agreement. If a matter is referred to the Conflicts Committee, it obtains
information regarding the proposed transaction from management and determines whether to engage independent legal counsel
or an independent financial advisor to advise the members of the committee regarding the transaction. If the Conflicts
Committee retains such counsel or financial advisor, it considers such advice and, in the case of a financial advisor, such
advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.
Item 14. Principal Accounting Fees and Services
KPMG, LLP served as our independent auditors for the fiscal years ended December 31, 2012 and 2011. The following
fees were paid to KPMG, LLP for services rendered during our last two fiscal years:
Audit fees
Audit related fees
Audit and audit related fees
Tax fees
All other fees
Total fees
2012
1,302,000 (1)
20,000
1,322,000
171,976 (2)
—
1,493,976
2011
1,095,000 (1)
16,809
1,111,809
142,930 (2)
—
1,254,739
(1)
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. 2011 Audit fees include fees for the
annual integrated audit, the audit of Waskom Gas Processing Company and fees related to services in connection with
transactions.
(2)
Tax fees are for services related to the review of our partnership K-1's returns, and research and consultations on other
tax related matters.
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, 2012 and December 31, 2011 were approved in advance by the Audit Committee.
PART IV
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, 2012 and 2011
Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010
137
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012 and 2011
Consolidated Statements of Changes in Capital for the years ended December 31, 2012, 2011 and 2010
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010
Notes to the Consolidated Financial Statements
(2)
Financial Statements of Waskom Gas Processing Company for the seven months ended July 31, 2012, 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 142 for a list of all exhibits filed as part of this report.
138
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.
SIGNATURES
Date: March 4, 2013
Martin Midstream Partners L.P.
(Registrant)
By:
By:
Martin Midstream GP LLC
It's General Partner
/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 4th day of March, 2013.
139
Signature
Title
/s/ Ruben S. Martin
Ruben S. Martin
/s/ Robert D. Bondurant
Robert D. Bondurant
/s/ Wesley M. Skelton
Wesley M. Skelton
/s/ C. Scott Massey
C. Scott Massey
/s/ Byron Kelley
Byron Kelley
/s/ Joe N. Averett, Jr.
Joe N. Averett, Jr.
/s/ Charles H. Still
Charles H. Still
President, Chief Executive Officer and Director of Martin
Midstream GP LLC (Principal Executive Officer)
Executive Vice President and Chief Financial Officer of
Martin Midstream GP LLC (Principal Financial Officer)
Executive Vice President, Chief Administrative Officer,
Secretary and Controller of Martin Midstream GP LLC
(Principal Accounting Officer)
Director of Martin Midstream GP LLC
Director of Martin Midstream GP LLC
Director of Martin Midstream GP LLC
Director of Martin Midstream GP LLC
140
Exhibit
Number
INDEX TO EXHIBITS
Exhibit Name
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
4.1
4.2
4.3
4.4*
4.5
4.6
10.1
Certificate of Limited Partnership of Martin Midstream Partners L.P. (the “Partnership”), dated June 21, 2002
(filed as Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July
1, 2002, and incorporated herein by reference).
Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of November 25,
2009 (filed as Exhibit 10.1 to the Partnership’s Amendment to Current Report on Form 8-K/A (SEC File No.
000-50056), filed January 19, 2010, and incorporated herein by reference).
Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership,
dated January 31, 2011 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K (SEC File No.
000-50056), filed February 1, 2011, and incorporated herein by reference).
Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership,
dated October 2, 2012 (filed as Exhibit 10.5 to the Partnership’s Current Report on Form 8-K (SEC File No.
000-50056), filed October 9, 2012, and incorporated herein by reference).
Certificate of Limited Partnership of Martin Operating Partnership L.P. (the “Operating Partnership”), dated June
21, 2002 (filed as Exhibit 3.3 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706),
filed July 1, 2002, and incorporated herein by reference).
Amended and Restated Agreement of Limited Partnership of the Operating Partnership, dated November 6, 2002
(filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November
19, 2002, and incorporated herein by reference).
Certificate of Formation of Martin Midstream GP LLC (the “General Partner”), dated June 21, 2002 (filed as
Exhibit 3.5 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July 1, 2002,
and incorporated herein by reference).
Limited Liability Company Agreement of the General Partner, dated June 21, 2002 (filed as Exhibit 3.6 to the
Partnership’s Registration Statement on Form S-1 (SEC File No. 33-91706), filed July 1, 2002, and incorporated
herein by reference).
Certificate of Formation of Martin Operating GP LLC (the “Operating General Partner”), dated June 21, 2002
(filed as Exhibit 3.7 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July
1, 2002, and incorporated herein by reference).
Limited Liability Company Agreement of the Operating General Partner, dated June 21, 2002 (filed as Exhibit 3.8
to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July 1, 2002, and
incorporated herein by reference).
Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).
Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership’s
Registration Statement on Form S-1 (SEC File No. 333-91706), filed October 25, 2002, and incorporated herein
by reference).
Indenture (including form of 8.875% Senior Note due 2018), dated as of March 26, 2010, by and among the
Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National
Association, as trustee (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (SEC File No.
000-50056), filed March 26, 2010, and incorporated herein by reference).
First Supplemental Indenture, to the Indenture dated as of March 26, 2010, dated as of February 11, 2013, by and
among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank,
National Association, as trustee.
Indenture (including form of 7.250% Senior Notes due 2021), dated as of February 11, 2013, by and among the
Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National
Association, as trustee (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (SEC File No.
000-50056), filed February 12, 2013, and incorporated herein by reference).
Registration Rights Agreement, dated as of February 11, 2013, by and among the Partnership, Martin Midstream
Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (filed as Exhibit 4.2 to the
Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed February 12, 2013, and incorporated
herein by reference).
Second Amended and Restated Credit Agreement, dated November 10, 2005, among the Partnership, the
Operating Partnership, Royal Bank of Canada and the other Lenders set forth therein (filed as Exhibit 10.1 to the
Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 14, 2005, and incorporated
herein by reference).
141
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
Second Amendment to Second Amended and Restated Credit Agreement, dated as of December 28, 2007, among
the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas
Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C.,
Woodlawn Pipeline Co., Inc., the financial institution parties to the Credit Agreement and Royal Bank of Canada,
as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K
(SEC File No. 000-50056), filed January 2, 2008, and incorporated herein by reference).
Third Amendment to Second Amended and Restated Credit Agreement, effective as of September 24, 2008,
among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism
Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company,
L.L.C., Woodlawn Pipeline Co., Inc., the financial institution parties to the Credit Agreement and Royal Bank of
Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on
Form 8-K (SEC File No. 000-50056), filed September 30, 2008, and incorporated herein by reference).
Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of December 21, 2009, among
the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas
Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C.,
Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline LLC, the financial institution parties to the Credit Agreement
and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s
Current Report on Form 8-K (SEC File No. 000-50056), filed December 23, 2009, and incorporated herein by
reference).
Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of January 14, 2010, among the
Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas
Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C.,
Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline LLC, the financial institutions parties thereto, as lenders, and
Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s
Current Report on Form 8-K (SEC File No. 000-50056), filed January 19, 2010, and incorporated herein by
reference).
Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of March 26, 2010, among the
Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas
Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C.,
Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline LLC, the financial institution parties to the Credit Agreement
and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s
Current Report on Form 8-K (SEC File No. 000-50056), filed March 26, 2010, and incorporated herein by
reference).
Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of April 15, 2011, among the
Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas
Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C.,
Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline, LLC, the financial institutions party to the Credit Agreement
and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s
Current Report on Form 8-K (SEC File No. 000-50056), filed April 21, 2011, and incorporated herein by
reference).
Eighth Amendment to Second Amended and Restated Credit Agreement, dated as of May 31, 2011, among the
Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas
Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C.,
Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline, LLC, the financial institutions party to the Credit Agreement
and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.3 to the Partnership’s
Current Report on Form 8-K/A (SEC File No. 000-50056), filed January 13, 2012, and incorporated herein by
reference).
Ninth Amendment to Second Amended and Restated Credit Agreement, dated as of September 7, 2011, among the
Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas
Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C.,
Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline, LLC, the financial institutions party to the Credit Agreement
and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s
Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 7, 2011, and incorporated herein by
reference).
Commitment Increase and Joinder Agreement, dated December 5, 2011 (filed as Exhibit 10.1 to the Partnership’s
Current Report on Form 8-K (SEC File No. 000-50056), filed December 7, 2011, and incorporated herein by
reference).
Commitment Increase and Joinder Agreement, dated May 10, 2012 (filed as Exhibit 10.1 to the Partnership’s
Current Report on Form 8-K (SEC File No. 000-50056), filed May 10, 2012 and incorporated herein by
reference).
142
10.12*
10.13*
10.14
10.15
10.16
Tenth Amendment to the Second Amended and Restated Credit Agreement, dated as of May 22, 2012, among the
Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas
Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C.,
Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline, LLC, Martin Midstream Finance Corp., the financial
institutions party to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent.
Eleventh Amendment to the Second Amended and Restated Credit Agreement and Limited Waiver, dated as of
February 4, 2013, among the Operating Partnership, the Partnership, the Operating General Partner, Martin
Midstream Finance Corp., Redbird Gas Storage LLC, MOP Midstream Holdings LLC, the financial institutions
party to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent.
Omnibus Agreement, dated November 1, 2002, by and among Martin Resource Management Corporation, the
General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current
Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
Amendment No. 1 to Omnibus Agreement, dated as of November 25, 2009, by and among Martin Resource
Management Corporation, the General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3
to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed December 1, 2009, and
incorporated herein by reference).
Amendment No. 2 to Omnibus Agreement, dated October 1, 2012, by Martin Resource Management Corporation,
Martin Midstream GP, LLC, Martin Midstream Partners L.P., and Martin Operating Partnership L.P. (filed as
Exhibit 10.4 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012,
and incorporated herein by reference).
10.17 Motor Carrier Agreement, dated January 1, 2006, by and between the Operating Partnership and Martin Transport,
Inc. (filed as Exhibit 10.9 to the Partnership’s Annual Report on Form 10-K (SEC File No. 000-50056), filed
March 2, 2011, and incorporated herein by reference).
.
10.18 Marine Transportation Agreement, dated January 1, 2006, by and between the Operating Partnership and
Midstream Fuel Service, L.L.C. (filed as Exhibit 10.10 to the Partnership’s Annual Report on Form 10-K (SEC
File No. 000-50056), filed March 2, 2011, and incorporated herein by reference).
10.19
Product Storage Agreement, dated November 1, 2002, by and between Martin Underground Storage, Inc. and the
Operating Partnership (filed as Exhibit 10.8 to the Partnership’s Current Report on Form 8-K (SEC File No.
000-50056), filed November 19, 2002, and incorporated herein by reference).
10.20 Marine Fuel Agreement, dated November 1, 2002, by and between Martin Fuel Service LLC and the Operating
Partnership (filed as Exhibit 10.9 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed
November 19, 2002, and incorporated herein by reference).
10.21† Martin Midstream Partners L.P. Amended and Restated Long-Term Incentive Plan (filed as Exhibit 10.1 to the
Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed January 26, 2006, and incorporated herein
by reference).
10.22†
10.23
10.24
10.25
10.26
10.27
10.28
Form of Restricted Common Unit Award Notice (filed as Exhibit 10.2 to the Partnership’s Current Report on Form
8-K (SEC No. 000-50056), filed January 26, 2006, and incorporated herein by reference).
Assignment and Assumption of Lease and Sublease, dated November 1, 2002, by and between the Operating
Partnership and Martin Gas Sales LLC (“MGSLLC”) (filed as Exhibit 10.12 to the Partnership’s Current Report
on Form 8-K (SEC No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
Purchaser Use Easement, Ingress-Egress Easement, and Utility Facilities Easement dated November 1, 2002, by
and between MGSLLC and the Operating Partnership (filed as Exhibit 10.13 to the Partnership’s Current Report
on Form 8-K (SEC No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
Asset Purchase Agreement by and among the Partnership, the Operating Partnership and Tesoro Marine Services,
L.L.C., dated October 27, 2003 (filed as Exhibit 10.1 to the Partnership’s Amendment No. 1 to Current Report on
Form 8-K (SEC No. 000-50056), filed January 23, 2004, and incorporated herein by reference).
Purchase Agreement by and among the Operating Partnership, Prism Gas Systems I, L.P., Natural Gas Partners V,
L.P., Robert E. Dunn, William J. Diehnelt, Gene A. Adams, Philip D. Gettig, Sharon C. Taylor and Scott A.
Southard, dated September 6, 2005 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC
No. 000-50056), filed September 6, 2005, and incorporated herein by reference).
Amended and Restated Terminal Services Agreement by and between the Operating Partnership and Martin Fuel
Service LLC (“MFSLLC”), dated October 27, 2004 (filed as Exhibit 10.1 to the Partnership's Current Report on
Form 8-K (SEC No. 000-50056), filed October 28, 2004, and incorporated herein by reference).
Lubricants and Drilling Fluids Terminal Services Agreement by and between the Operating Partnership and
MFSLLC, dated December 23, 2003 (filed as Exhibit 10.4 to the Partnership’s Amendment No. 1 to Current
Report on Form 8-K (SEC No. 000-50056), filed January 23, 2004, and incorporated herein by reference).
10.29*(1) Amended and Restated Sales Agency Agreement, dated August 1, 2008, by and between Martin Operating
Partnership L.P. and Martin Product Sales LLC.
143
10.30† Martin Resource Management Corporation Purchase Plan for Units of Martin Midstream Partners L.P. (filed as
Exhibit 10.1 to the Partnership's registration statement on Form S-8 (SEC File No. 333-140152), filed January 23,
2007, and incorporated herein by reference).
Form of Indemnification Agreement (filed as Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q
(SEC File No. 000-50056), filed November 6, 2008, and incorporated herein by reference).
Amended and Restated Contribution Agreement, dated as of November 25, 2009, by and among the Operating
Partnership, the Partnership, Cross Oil Refining & Marketing, Inc. and Martin Resource Management (filed as
Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed December 1, 2009,
and incorporated herein by reference).
Tolling Agreement, dated as of November 25, 2009, by and between the Operating Partnership and Cross Oil
Refining & Marketing, Inc. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC File No.
000-50056), filed December 1, 2009, and incorporated herein by reference).
Amended and Restated Common Unit Purchase Agreement, dated as of November 24, 2009, by and between the
Partnership and Martin Resource Management (filed as Exhibit 10.4 to the Partnership’s Current Report on Form
8-K (SEC File No. 000-50056), filed December 1, 2009, and incorporated herein by reference).
Second Amended and Restated LLC Agreement of Redbird Gas Storage LLC, dated as of October 2, 2012. (filed
as Exhibit 10.6 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5,
2012, and incorporated herein by reference).
Asset Purchase Agreement, dated October 2, 2012, by and among Martin Operating Partnership L.P., Martin
Midstream Partners L.P., Cross Oil Refining & Marketing, Inc. and Martin Resource Management Corporation
(filed as Exhibit 10.3 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9,
2012, and incorporated herein by reference).
Supply Agreement dated, as of October 2, 2012, by and between the Partnership and Cross Oil & Refining
Marketing Inc. (filed as Exhibit 10.7 to the Partnership's Quarterly Report on Form 10-Q (SEC File No.
000-50056), filed November 5, 2012, and incorporated herein by reference).
Noncompetition Agreement dated, as of October 2, 2012, by and among the Partnership, Cross Oil Refining &
Marketing Inc., and Martin Resource Management Corporation. (filed as Exhibit 10.8 to the Partnership's
Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5, 2012, and incorporated herein by
reference).
10.31
10.32
10.33
10.34
10.35
10.36
10.37
10.38
10.39 Membership Interests Purchase Agreement, dated October 2, 2012, by and among Martin Operating Partnership
L.P., Martin Midstream Partners L.P., Martin Underground Storage, Inc. and Martin Resource Management
Corporation (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056),
filed October 9, 2012, and incorporated herein by reference).
10.40
21.1*
23.1*
23.2*
31.1*
31.2*
32.1*
32.2*
101
Purchase Price Reimbursement Agreement, dated October 2, 2012, by Martin Resource Management Corporation
to and for the benefit of Martin Operating Partnership L.P. (filed as Exhibit 10.2 to the Partnership's Current
Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
List of Subsidiaries.
Consent of KPMG LLP.
Consent of KPMG LLP.
Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 9.06
of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and
shall not be deemed to be “filed.”
Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 9.06
of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and
shall not be deemed to be “filed.”
Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Annual Report on
Form 10-K for the fiscal year ended December 31, 2012, formatted in Extensible Business Reporting Language:
(1) the Consolidated Balance Sheets; (2) the Consolidated Statements of Income; (3) the Consolidated Statements
of Cash Flows; (4) the Consolidated Statements of Capital; (5) the Consolidated Statements of Other
Comprehensive Income; and (6) the Notes to Consolidated Financial Statements, tagged as blocks of text.
*
†
Filed or furnished herewith.
As required by Item 15(a)(3) of Form 10-K, this exhibit is identified as a compensatory plan or arrangement.
(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.
144
Financial Statement Schedule
Pursuant to Item 15(a)(2)
Waskom Gas
Processing Company
Consolidated Financial Statements July 31, 2012
(unaudited) and December 31, 2011 and for the seven
months ended July 31, 2012 (unaudited) and each of
the years in the two-year period ended December 31,
2011 (with Independent Auditors' Report thereon).
145
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 years ended December 31, 2011 and 2010. 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
audits.
We conducted our audits 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 audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of Waskom Gas Processing Company and subsidiaries as of December 31, 2011 and the results of their operations and
their cash flows for the years ended December 31, 2011 and 2010, in conformity with U.S. generally accepted accounting
principles.
/s/ KPMG LLP
Shreveport, Louisiana
March 5, 2012
146
WASKOM GAS PROCESSING COMPANY
CONSOLIDATED BALANCE SHEETS
AS OF JULY 31, 2012 AND DECEMBER 31, 2011
ASSETS
CURRENT ASSETS:
Cash
Accounts receivable
Accounts receivable - partners
Inventories
Prepaid expenses
Total current assets
PROPERTY AND EQUIPMENT:
Gas plant asset and gas gathering equipment
Other fixed assets
Accumulated depreciation and amortization
Net property and equipment
NON-CURRENT ASSETS:
Other non-current assets:
TOTAL
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accounts payable and accrued liabilities
Accounts payable - partners
2012
(Unaudited)
2011
$
2,191,147
$
1,172,173
5,869,715
574,652
—
757,494
1,473,935
18,241,163
423,474
26,224
9,807,687
20,922,290
164,365,426
746,743
(36,997,090)
128,115,079
157,072,005
746,743
(32,336,265)
125,482,483
133,500
250,000
$
138,056,266
$
146,654,773
$
5,882,893
$
2,131,007
14,934,725
4,057,864
Total current liabilities
8,013,900
18,992,589
LONG-TERM LIABILITIES - Asset retirement obligation
833,590
799,527
COMMITMENTS AND CONTINGENCIES
PARTNERS' CAPITAL
TOTAL
See accompanying notes to consolidated financial statements.
147
129,208,776
126,862,657
$
138,056,266
$
146,654,773
WASKOM GAS PROCESSING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
FOR THE SEVEN MONTHS ENDED JULY 31, 2012 AND
YEARS ENDED DECEMBER 31, 2011 AND 2010
2012
(Unaudited)
2011
2010
OPERATING REVENUES:
Natural gas processing and other revenues
$
22,401,200
$
39,618,717
$
36,297,801
Natural gas liquid sales
Gain/loss on disposal of assets
44,261,039
(83,205)
88,654,517
86,911,925
845,567
912,004
Total operating revenues
66,579,034
129,118,801
124,121,730
OPERATING COSTS AND EXPENSES:
Cost of sales - natural gas liquids
Operating costs
Depreciation and amortization
46,502,430
6,296,194
4,694,888
92,705,171
10,126,797
6,849,262
87,159,671
9,375,703
6,597,686
Total operating costs and expenses
57,493,512
109,681,230
103,133,060
OPERATING INCOME INCOME BEFORE TAXES
9,085,522
19,437,571
20,988,670
Income tax expense
NET INCOME
100,000
53,008
226,589
$
8,985,522
$
19,384,563
$
20,762,081
See accompanying notes to consolidated financial statements.
148
WASKOM GAS PROCESSING COMPANY
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
FOR THE SEVEN MONTHS ENDED JULY 31, 2012 AND YEARS ENDED DECEMBER 31,
2011 AND 2010
BALANCE - December 31, 2009
Cash contributions for capital expenditures
Cash contributions for investment in Waskom Midstream LLC
Cash distributions in excess of working capital
Cash distributions
Distributions in-kind
Net Income
BALANCE - December 31, 2010
Cash contributions for capital expenditures
Cash distributions in excess of working capital
Cash distributions
Distributions in-kind
Net Income
BALANCE - December 31, 2011
Cash contributions for capital expenditures (unaudited)
Cash distributions in excess of working capital (unaudited)
Distributions in-kind (unaudited)
Net Income (unaudited)
Total Partners'
Capital
$
70,560,798
7,471,259
40,000,000
(4,702,415)
(4,200,000)
(22,383,279)
20,762,081
107,508,444
32,209,322
(4,432,461)
(2,400,000)
(25,407,211)
19,384,563
126,862,657
7,293,499
(1,209,056)
(12,723,846)
8,985,522
BALANCE - July 31, 2012 (Unaudited)
$
129,208,776
See accompanying notes to consolidated financial statements.
149
WASKOM GAS PROCESSING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE SEVEN MONTHS ENDED JULY 31, 2012 AND
YEARS ENDED DECEMBER 31, 2011 AND 2010
OPERATING ACTIVITIES:
Net Income
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization
Distributions in-kind to partners
Loss / (Gain) on sale of asset
Changes in operating assets and liabilities:
Accounts receivable
Accounts receivable - partners
Inventory
Prepaid expenses
Other non-current assets, net
Accounts payable and accrued liabilities
Accounts payable - partners
2012
(Unaudited)
2011
2010
$
8,985,522
$
19,384,563
$
20,762,081
4,694,888
(12,723,846)
83,205
6,849,262
(25,407,211)
(845,567)
6,597,686
(22,383,279)
(912,004)
301,762
12,371,448
(151,178)
26,224
116,500
(9,086,227)
(1,926,857)
(527,729)
(7,533,187)
79,975
(2,160)
—
6,330,191
(920,761)
(768,174)
(1,334,484)
(35,077)
(24,064)
—
2,132,514
3,134,610
7,169,809
Net cash provided by (used in) operating activities
2,691,441
(2,592,624)
INVESTING ACTIVITIES:
Additions to property and equipment
Acquisitions, net of cash required
Proceeds from sale / disposal of assets
Net cash used in investing activities
FINANCING ACTIVITIES:
Contributions from partners
Distributions to partners
Net cash provided by financial activities
(7,375,526)
—
33,295
(7,342,231)
(25,489,809)
—
2,502,000
(22,987,809)
(7,277,746)
(40,000,000)
2,477,000
(44,800,746)
7,293,499
(1,209,056)
6,084,443
32,209,322
(6,832,462)
25,376,860
47,471,259
(8,902,415)
38,568,844
NET INCREASE (DECREASE) IN CASH
1,433,653
(203,573)
937,907
CASH - Beginning of year
757,494
961,067
23,160
CASH - End of year
SUPPLEMENTAL CASH FLOWS DISCLOSURES:
Taxes paid
See accompanying notes to consolidated financial statements.
$
$
150
2,191,147
$
757,494
$
961,067
97,342
$
196,544
$
112,371
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), $6,794,726, and $6,546,872 for the seven months ended 2012 and the
years ended December 31, 2011 and 2010, 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.
151
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 years ended December 31, 2011 and 2010 was $34,063 (unaudited), $54,536 and $50,814, 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 years
ended December 31, 2012 and 2010 was $100,000 (unaudited), $53,008 and $226,589, 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, 2011, and 2010, 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), $32,209,322 and $7,471,259 for the seven months
ended 2012, and the years ended 2011 and 2010, 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),
$4,432,461 and $4,702,415 for the seven months ended 2012, and the years ended 2011 and 2010, respectively. Other cash
distributions totaled $0 (unaudited), $2,400,000 and $4,200,000 for the seven months ended 2012, and the years ended
2011 and 2010, 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
152
of products-in-kind based on the partners' equity interest. Distributions of products in-kind of $12,723,846 (unaudited),
$25,407,211 and $22,383,279 for the seven months ended 2012, and the years ended 2011 and 2010, 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), $85,613,194 and
$71,734,452 for the seven months ended 2012, and the years ended 2011 and 2010, 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.
153
MARTIN MIDSTREAM PARTNERS L.P.
company information
PrinciPAL Officers
MArtin MidstreAM GP LLc
Ruben S. Martin III
President
Chief Executive Officer
Robert D. Bondurant
Executive Vice President
Chief Financial Officer
Randall L. Tauscher
Executive Vice President
Chief Operating Officer
Wesley M. Skelton
Executive Vice President
Chief Administrative Officer
Chris Booth
Executive Vice President
Chief Legal Officer
Edward H. Grimm III
Senior Vice President
Marine
T. Damon King
Senior Vice President
Shore Bases
Michael Lawrence
Senior Vice President
Sulfur Services
Tom E. Redd
Vice President
Natural Gas/LPG Services
Scot A. Shoup
Senior Vice President
Operations
Matt A. Yost
Senior Vice President
Terminalling and Engineering
Scott Boydston
Vice President
Director of Audit Services
Ronald G. Garner
Vice President
Fertilizer
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S. Wesley Martin
Vice President
Business Development
Melanie Mathews
Vice President
Human Resources
Joe McCreery
Vice President
Finance/Head of Investor Relations
Michael Murley
Vice President
Risk Management
Alana Sumpter
Vice President
Information Technology
Doug Towns
Vice President
Smackover Facilities
Walter Tyson
Vice President
Martin Lubricants
Karen Yost
Vice President
Taxation
John Ben Blackburn
Assistant General Counsel
BOArd Of directOrs
MArtin MidstreAM GP LLc
Ruben S. Martin III
President
Chief Executive Officer
Martin Midstream GP LLC
Joe N. Averett, Jr.
Former President and
Chief Executive Officer
Crystal Gas Storage, Inc.
C. Scott Massey
Certified Public Accountant
C. Scott Massey, CPA LLC
Manager Sandstone Ventures LLC
C. Henry (Hank) Still
Of Counsel
Fulbright & Jaworski L.L.P.
Byron Kelley
President/Chief Executive Officer
CVR Partners, LP
cOrPOrAte Offices
MArtin MidstreAM GP LLc
4200 B Stone Road
Kilgore, Texas 75662
(903) 983-6200
trAnsfer AGent
Computershare
P.O. Box 43006
Providence, RI 02940-3006
Overnight Delivery Address:
250 Royal Street
Canton, Massachusetts 02021
(800) 301-0911
www-us.computershare.com/Investor
AuditOrs
KPMG LLP
333 Texas Street
Suite 1900
Shreveport, Louisiana 71101
units trAded
NASDAQ Global Select Market
Symbol: MMLP
investOr infOrMAtiOn
Updated investor information on
the Company is available on our
website www.martinmidstream.com.
Inquiries can also be sent to
ir@martinmlp.com.
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4200 B Stone Road
Kilgore, Texas 75662
903-983-6200
www.martinmidstream.com