M I D S T R E A M P A R T N E R S
2 0 1 0 a n n u a L r e p o r t
str ateGy creates opportunity
fellow unitholders,
Last year in my letter to you, we highlighted the resounding
diversification of Martin Midstream. (It is equally as good, if
not better than any other MLP, in my opinion.) Our diversity
pulled us through the economic downturn as the portfolio effect
of our operations remained positive along with our distribution
programs through the recovery. In 2010, we again benefited
from our broad cross-section of business lines and finished
the year with a solid distribution coverage ratio. Further, with
improved liquidity and access to capital fully restored, we were
able to grow through a series of strategic acquisitions and drop
down transactions.
Effective January 1, 2010, our Waskom joint venture
completed an acquisition of a gas gathering system in Harrison
County, Texas. In addition to approximately 60 miles of natural
gas gathering pipeline, this system includes compression, dehy-
dration and two refrigeration plants with natural gas processing
capacity of 35 MMcf/d each. In November 2010, we purchased
the Darco Gas Gathering System. This system consists of
approximately 21 miles of pipe and is located in Harrison
County, Texas and is connected to the Harrison Gas Gathering
System that Waskom acquired earlier in the year. The Darco
system gathers primarily lean Haynesville gas for delivery to a
third party but also provides access to Cotton Valley production
that could be connected to the Waskom Plant in the future.
The processing capacity of the Waskom Plant will be expanded
to 320 MMcf/d by the fourth quarter of 2011, and the supply
derived from this system has been instrumental to this expansion.
We remain the only natural gas processor in Northeast Texas
and Northwest Louisiana with full fractionation capability and
are currently constructing a new rail car loading/unloading
facility adjacent to the Waskom Plant. This rail car facility will
be completed in the fourth quarter of 2011 and will allow us
access to new natural gas liquids markets for our high purity
products well beyond the existing regional markets we have
historically served. We believe our fractionation capability,
particularly when combined with our new rail car facility and
the tightening of available fractionation capacity, provides us
with a strong competitive advantage over other processors in
the area. In May 2011, through a joint venture formed with
our affiliate and owner of our general partner, Martin Resource
Management Corporation (MRMC), we purchased an approx-
imate 40% interest in the Monroe Gas Storage facility located
in the Black Warrior Basin of Mississippi. This facility, which
has been in operation since 2009, will bring steady fee-based
distributable cash flow to our unitholders for years to come.
Last summer, we grew our Terminalling and Storage
Segment through the drop down acquisition of two additional
shore based terminals at Theodore, Alabama and Pascagoula,
Mississippi. These assets were purchased from MRMC and
represent the easternmost storage facilities within our network.
Given this increased geographical presence, we believe our
system of assets to be one of the largest along the U.S. Gulf
Coast. In early 2011, we made our system even larger as we
acquired additional marine terminalling assets from one of our
principal competitors. Through this acquisition, we purchased
one inland terminalling facility and 13 marine terminalling
facilities located on the Louisiana Gulf Coast. Our system is
well-positioned for increased offshore oil and gas activity in
the U.S. Gulf of Mexico. The level of activity has been stifled
in response to the 2010 offshore catastrophe. However, we
remain optimistic long-term for the industry to recover as
activity has increased during the first half of 2011.
In 2010, the Sulfur Services segment enjoyed solid perfor-
mance driven by increased margins in the fertilizer segment.
We expect ongoing growth and sustainability in the Sulfur
ruben s. Martin iii
President and Chief Executive Officer
Services segment into 2011 due to the restructuring of a contract
with our largest customer which allows for a significant reduction
in cash flow volatility caused by commodity and demand
fluctuations, an expansion of sulfur prilling capacity at our
Beaumont, Texas facility that is fee based and supported by
long-term contracts with two major integrated oil companies,
and the commencement of operations at our new ammonium
sulfate plant at Plainview, Texas.
Late in 2010, our Marine Transportation segment success-
fully completed a drop down acquisition of an offshore refined
product barge capable of transporting up to 65,000 barrels. The
barge we call the M6000, is under a long-term fee generating
contract with its former owner, MRMC. Under this agreement,
the M6000 will be integral to supplying our expanded marine
shore based terminals with product. Additionally, we added
four barges to our inland fleet and we contracted to build three
new boats. The boats, to be delivered in 2011, will replace
horsepower we currently charter from third parties. As you can
see, in 2010 we continued to modernize and update our fleet,
allowing us to be more competitive.
We have returned to a growth trajectory. We know as
investors you patiently waited through nine consecutive quarters
without a distribution increase. We were very pleased to finally
restore distribution growth for the first and second quarter
distributions of 2011. We are moving forward. Our access
to capital remains strong and we have made several strategic
personnel changes to assist in our growth.
Lastly, this coming November we will enter our tenth year
as a publicly traded master limited partnership. I would like
to especially recognize and thank our broad group of original
investors. To those of you who have been with us every step of
the way, I am truly humbled and appreciative. We have enjoyed
having you as “true partners” and trust that you’ll be right there
with us for the next ten years. While our growth has been
remarkable, the best is yet to come!
Wishing you continued prosperity throughout the remainder
of 2011,
ruben s. Martin iii
President and Chief Executive Officer
ter MinaLLinG anD stor aGe
TERMINALING
& STORAGE
160
140
120
100
80
60
40
20
0
800
Natural gas
Martin Midstream owns or operates a system of marine terminalling
facilities and inland facilities located in the United States Gulf Coast
region that provide storage and handling services for producers and
suppliers of petroleum products and by-products, lubricants and other
liquids and fuel oil. 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. Terminalling and storage services are provided on a fee
basis primarily under long-term contacts.
500
600
400
700
• 27 Marine Terminals (representing approximately 744 thousand
300
barrels of storage)
200
• 12 Specialty Petroleum Terminals (representing approximately
2.53 million barrels of storage)
Sulfur Services
Marine
Transportation
100
0
500
400
300
200
100
0
150
135
120
105
90
75
60
45
30
15
0
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
$119
$115
$105
$ 97
$ 36
’06
’07
’08
’09
’10
OPER ATING R EV ENUE
2010 PERCENTAGE OF
AFTER ELIMINATIONS
OPERATING INCOME
(In Millions)
$679
$516
$554
39.90%
$390
$409
2010 Operating Income
$16 MILLION
’06
’07
’08
’09
’10
2010 PERCENTAGE OF
OPERATING INCOME
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
11.58%
$372
2010 Operating Income
$4.7 MILLION
$165
$131
$103
2010 PERCENTAGE OF
OPERATING INCOME
$80
’06
’07
’08
’09
’10
39.54%
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
2010 Operating Income
$15.9 MILLION
2010 PERCENTAGE OF
OPERATING INCOME
$76
$78
$68
$ 60
$ 48
24.87%
’06
’07
’08
’09
’10
2010 Operating Income
$10 MILLION
TERMINALING
& STORAGE
160
140
120
100
80
60
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
$119
$115
$105
$ 97
natur aL Gas serv ices
40
$ 36
Natural gas
20
0
800
700
600
500
400
300
200
100
0
We have ownership interests in over 706 miles of gathering and
transmission pipelines located in the natural gas producing regions of
Central and East Texas, Northwest Louisiana, the Texas Gulf Coast as
well as a 285-million cubic feet per day natural gas processing plant in
East Texas. We distribute, store and sell natural gas liquids to propane
retailers, refineries and industrial users in Texas and the Southeastern
United States. Our assets include:
Sulfur Services
400
500
• Prism Gas Systems I, L.P. (50% interests in Waskom Gas Processing
Company)
300
• Woodlawn Plant and Gathering System
• Prism Liquids Pipeline ETX Condensate Gathering System
200
• McLeod Gathering System
• Hallsville Gathering System
100
• Darco Gathering System
• Harrison Gas Gathering System (50% operating interest)
0
• Matagorda Gathering System (50% non-operated interest)
• Fishhook Gathering System (50% non-operated interest)
Marine
Transportation
150
135
120
105
90
75
60
45
30
15
0
’06
’07
’08
’09
’10
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
2010 PERCENTAGE OF
OPERATING INCOME
$679
$516
$554
$390
$409
39.90%
2010 Operating Income
$16 MILLION
’09
’08
’07
’06
’10
2010 PERCENTAGE OF
OPERATING INCOME
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
$372
11.58%
$165
2010 Operating Income
$4.7 MILLION
$131
$103
$80
2010 PERCENTAGE OF
OPERATING INCOME
’10
’08
’06
’09
’07
39.54%
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
2010 Operating Income
$15.9 MILLION
$76
$78
2010 PERCENTAGE OF
OPERATING INCOME
$ 60
$68
$ 48
’06
’07
’08
24.87%
’09
’10
2010 Operating Income
$10 MILLION
1300
1200
1100
1000
900
800
M A RTIN MIDSTR e A M PA RTNeRS
FinancialHigHligHts
700
(in thousands, except per unit amounts)
600
Total Assets
500
Revenue
400
Operating Income
300
70
60
50
40
30
20
200
100
Net Income
Distributable Cash Flow(1)
Distributions per Unit(2)
0
(1) See Reconciliation on page following Form 10-K.
(2) Actual distributions per unit.
’06
’08
’10
’09
’07
10
3.0
2.5
2.0
2006
2007
2008
1.5
2009
2010
$ 457,461
$ 656,604
$ 706,322
$ 685,939
576,384
804,327
1.0
1,246,444
662,385
26,609
22,243
32,140
41,935
32,561
55,517
52,364
43,558
0.5
63,064
34,420
22,203
55,723
$785,478
912,118
40,176
16,022
65,502
0
’06
$
’07
2.44
’08
$
’09
2.60
’10
$
2.91
0.0
$
’06
3.00
’07
’08
$
’09
3.00
’10
RE V ENUE
(in Millions)
$1,246
DISTR IBUTABLE
CAS H FLOW
(in Millions)
$66
$63
$56
$56
DISTRIBUTIONS
PER L.P. UNIT
$3.00
$3.00
$2.91
$2.60
$2.44
$912
$662
$804
$576
$32
’06
’07
’08
’09
’10
’06
’07
’08
’09
’10
’06
’07
’08
’09
’10
aboutMartinMidstrea MPartnersl.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 and storage
services for petroleum products and by-products; natural gas gathering and processing and NGL distribution 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 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 pur-
chasers 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.
M A RTIN MIDSTR e A M PA RTNeRS
distributablecasHFlowreconciliation
(in thousands)
Net income
2006
2007
2008
2009
2010
$ 22,243
$ 32,561
$ 43,558
$22,203
$16,022
Adjustments to reconcile net income to distributable cash flow:
Depreciation and amortization
Amortization of deferred debt issue costs
Amortization of issuance discount on notes payable
Deferred income taxes
early extinguishment of interest rate swaps
Distribution equivalents from unconsolidated entities
Invested cash in unconsolidated entities
17,597
1,040
—
—
26,322
1,233
—
680
34,895
39,506
1,120
1,689
—
2,442
—
294
9,285
767
12,812
1,338
11,450
2,793
7,353
2,712
equity in earning of unconsolidated entities
(8,547)
(10,941)
(13,224)
(7,044)
Non-cash mark to market on derivatives
Non-cash hurricane costs (net of cash payments)
Maintenance capital expenditures
Payments for plant turnaround costs
(389)
—
3,904
(2,327)
2,526
—
512
—
(7,732)
(11,955)
(17,998)
(7,601)
Gain on disposition or sale of property, plant and equipment
—
(484)
Gain on involuntary conversion of property, plant and equipment
(3,125)
(131)
(65)
(4,996)
(1,017)
—
—
39
—
—
98
—
—
—
47
—
1,160
(159)
$ 32,140
$ 55,517
$ 63,064
$55,723
$65,502
40,656
4,814
269
(415)
3,850
13,015
2,469
(9,792)
380
(4,653)
(1,090)
(136)
—
—
—
113
Repayment of debt
Debt prepayment premium
Other
DCF
ForM10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
Mark One
[ X ]
[ ]
Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the fiscal year ended December 31, 2010
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)
Delaware
State or other jurisdiction of incorporation or
organization
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:
NONE
Securities Registered Pursuant to Section 12(g) of the Act:
Title of each class
Common Units representing limited
partnership interests
Name of each exchange on which registered
NASDAQ
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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
(cid:134)
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
(cid:134)
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
(cid:134)
Yes
(cid:134)
No
(cid:134)
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.
(cid:134)
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
(Do not check if a smaller
reporting company)
Non-accelerated filer
Accelerated filer
(cid:134)
⌧
(cid:134)
Smaller reporting company
(cid:134)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
(cid:134)
Yes
No
⌧
As of June 30, 2010, 17,707,832 common units were outstanding. The aggregate market value of the common units held by non-
affiliates of the registrant as of such date approximated $206,544,787 based on the closing sale price on that date. There were 19,582,332 of the
registrant’s common units and 889,444 of the registrant’s subordinated units outstanding as of March 2, 2011.
DOCUMENTS INCORPORATED BY REFERENCE: None.
TABLE OF CONTENTS
Page
PART I 1
Business ........................................................................................................................................................1
Item 1.
Item 1A. Risk Factors ................................................................................................................................................26
45
Item 1B. Unresolved Staff Comments .......................................................................................................................
Item 2.
45
Properties ....................................................................................................................................................
Legal Proceedings.......................................................................................................................................45
Item 3.
Reserved .................................................................................................................................................... 46
Item 4.
.
PART II 46
Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.46
Item 5.
Selected Financial Data...............................................................................................................................47
Item 6.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations......................48
Item 7A. Quantitative and Qualitative Disclosures about Market Risk .....................................................................74
Financial Statements and Supplementary Data...........................................................................................77
Item 8.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ...................120
Item 9.
Item 9A. Controls and Procedures ...........................................................................................................................120
Item 9B. Other Information .....................................................................................................................................120
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
123
Directors, Executive Officers and Corporate Governance........................................................................123
Executive Compensation...........................................................................................................................128
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters .137
Certain Relationships and Related Transactions, and Director Independence..........................................142
Principal Accounting Fees and Services ...................................................................................................149
PART IV
Item 15.
150
Exhibits and Financial Statement Schedules.............................................................................................150
i
Item 1. Business
Overview
PART I
We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United
States Gulf Coast region. Our four primary business lines include:
• Terminalling and storage services for petroleum products and by-products;
• Natural gas services;
•
Sulfur and sulfur-based products gathering, processing, marketing , manufacturing and distribution; and
• Marine transportation services for petroleum products and by-products.
The petroleum products and by-products we gather, process, transport, store and market are produced
primarily by major and independent oil and gas companies who often turn to third parties, such as us, for the
transportation and disposition of these products. In addition to these major and independent oil and gas companies, our
primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale
purchasers of these products. We generate the majority of our cash flow from fee-based contracts with these customers.
Our location in the Gulf Coast region of the United States provides us strategic access to a major hub for petroleum
refining, natural gas gathering and processing and support services for the exploration and production industry.
We were formed in 2002 by Martin Resource Management Corporation (“Martin Resource Management”), a
privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to
drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and
internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of
hydrocarbon products and by-products and other bulk liquids. As of March 2, 2011, Martin Resource Management
owns an approximate 31.6% limited partnership interest in us. Furthermore, it owns and controls our general partner,
which owns a 2.0% general partner interest and incentive distribution rights in us.
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 27 marine shore based terminal facilities and 12
specialty terminal facilities located in the United States Gulf Coast region that provide storage,
processing and handling services for producers and suppliers of petroleum products and by-products,
lubricants and other liquids, including the refining of various grades and quantities of naphthenic
lubricants and related products. As further described in the “Subsequent Events” section within this
Item, 13 of our marine shore based terminals and one of our specialty terminals were acquired January
31, 2011 through our acquisition of certain terminalling assets from Martin Resource Management.
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. Through our acquisitions of Prism Gas Systems I, L.P. (“Prism Gas”) and
Woodlawn Pipeline Co., Inc. (“Woodlawn”), we have ownership interests in over 706 miles of
gathering and transmission pipelines located in the natural gas producing regions of East Texas,
- 1 -
Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal waters in the Gulf of
Mexico, as well as a 285 MMcfd capacity natural gas processing plant located in East Texas. In
addition to our natural gas gathering and processing business, we distribute natural gas liquids or,
“NGLs”. We purchase NGLs primarily from natural gas processors. We store NGLs in our supply and
storage facilities for wholesale deliveries to propane retailers, refineries and industrial NGL users in
Texas and the Southeastern United States. We own an NGL pipeline which spans approximately
200 miles running from Kilgore to Beaumont, Texas. We own three NGL supply and storage
facilities with an aggregate above-ground storage capacity of approximately 3,000 barrels and we
lease approximately 2.6 million barrels of underground storage capacity for NGLs. We believe we
have a natural gas processing competitive advantage in East Texas with the only full fractionation
facilities serving this area. The recent acquisition of natural gas gathering and processing assets from
Crosstex Energy, L.P. and Crosstex Energy, Inc. by Waskom Gas Processing Company (a joint
venture in which we participate with Center Point Energy Gas Processing Company, an indirect,
wholly-owned subsidiary of CenterPoint Energy, Inc.) and the Darco Gathering System further
strengthens our East Texas infrastructure.
•
Sulfur Services. We have developed an integrated system of transportation assets and facilities
relating to sulfur services over the last 30 years. We process and distribute sulfur predominantly
produced by oil refineries primarily located in the United States Gulf Coast region. We handle molten
sulfur on contracts that are tied to sulfur indices and tend to provide stable margins. We process
molten sulfur into prilled or pelletized sulfur on take or pay fee contracts at our facilities in Port of
Stockton, California and Beaumont, Texas. The sulfur we process and handle is primarily used in the
production of fertilizers and industrial chemicals. We own and operate six sulfur-based fertilizer
production plants and one emulsified sulfur blending plant that manufacture primarily sulfur-based
fertilizer products for wholesale distributors and industrial users. These plants are located in Illinois,
Texas and Utah. We own and operate a sulfuric acid production plant in Plainview, Texas which
processes molten sulfur into sulfuric acid. Demand for our sulfur products exists in both the domestic
and foreign markets, and we believe our asset base provides us with additional opportunities to handle
increases in U.S. supply and access to foreign demand.
• Marine Transportation. We utilize a fleet of 44 inland marine tank barges, 18 inland push boats and four
offshore tug barge units that transport petroleum products and by-products largely in the United States
Gulf Coast region. We provide these transportation services on a fee basis primarily under annual
contracts and many of our customers have long standing contractual relationships with us. Over the past
several years, we have focused on modernizing our fleet. As a result, the average age of our vessels has
decreased from 33 years in 2006 to 20 years as of March 2, 2011. 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.
2010 Developments and Subsequent Events
Recent Acquisitions
Acquisition of the Darco Gathering System. On November 12, 2010, we, through our wholly owned
subsidiary, Prism Gas, acquired approximately 20 miles of natural gas gathering pipeline and various equipment located
in Harrison County, Texas for approximately $25.0 million. We financed this acquisition with borrowings under our
revolving loan facility.
Acquisition by Waskom of the Harrison Pipeline System. On January 15, 2010, we, through Prism Gas, as 50%
owner and the operator of Waskom Gas Processing Company (“WGPC”), through WGPC’s 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. Our share of the acquisition cost was approximately $20.0 million.
Other Developments
Public Offerings. On August 17, 2010, we completed a public offering of 1,000,000 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
- 2 -
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.
On February 8, 2010, we completed a public offering of 1,650,000 common units, resulting in net proceeds of
$50.6 million, after payment of underwriters’ discounts, commissions and offering expenses. Our general partner
contributed $1.1 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner
interest in us. The net proceeds were used to pay down revolving debt under our credit facility.
Debt Financing Activities. Effective March 26, 2010, our credit facility was amended to (i) decrease the size
of our aggregate facility from $350.0 million to $275.0 million, (ii) convert all term loans to revolving loans, (iii) extend
the maturity date from November 9, 2012 to March 15, 2013, (iv) permit us to invest up to $40.0 million in our joint
ventures, (v) eliminate the covenant that limits our ability to make capital expenditures, (vi) decrease the applicable
interest rate margin on committed revolver loans, (vii) limit our ability to make future acquisitions and (viii) adjust the
financial covenants.
On March 26, 2010, we completed a private placement of $200.0 million in aggregate principal amount of
8.875% senior unsecured notes due 2018 (“2018 Notes”) to qualified institutional buyers under Rule 144A. We received
proceeds of approximately $197.2 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.
Pursuant to the terms of a registration rights agreement entered into in connection with the offering of the 2018
Notes, we filed an exchange offer registration statement with the SEC on September 16, 2010 with respect to an offer to
exchange the 2018 Notes for registered notes with substantially identical terms. The registration statement was declared
effective by the SEC and the exchange offer was completed in the fourth quarter of 2010.
For a more detailed discussion regarding our credit facility, see “Description of Our Long-Term Debt—Senior
Notes” in Item 7.
Subsequent Events
Public Offering. On February 9, 2011, we completed a public offering of 1,874,500 common units, resulting
in net proceeds of $70.7 million after payment of underwriters’ discounts, commissions and offering expenses. Our
general partner contributed $1.5 million in cash to us in conjunction with the issuance of these units 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.
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 was recorded in property, plant and
equipment. These assets are located across the Louisiana Gulf Coast.
Quarterly Distribution. On January 24, 2011, we declared a quarterly cash distribution of $0.76 per common unit
for the fourth quarter of 2010, or $3.04 per common unit on an annualized basis, to be paid on February 14, 2011 to
unitholders of record as of February 3, 2011, reflecting a $0.01 increase over the quarterly distribution paid in respect to the
third quarter of 2010.
Business Strategy
The key components of our business strategy are to:
• Pursue Organic Growth Projects. We continually evaluate economically attractive organic expansion
opportunities in new or existing areas of operation that will allow us to leverage our existing market
position, increase the distributable cash flow from our existing assets through improved utilization and
efficiency, and leverage our existing customer base.
• Pursue Internal Organic Growth by Attracting New Customers and Expanding Services Provided to
Existing Customers. We seek to identify and pursue opportunities to expand our customer base across all
of our business segments. We generally begin a relationship with a customer by transporting or marketing
a limited range of products and services. We believe expanding our customer base and our service and
product offerings to existing customers is the most efficient and cost effective method of achieving
organic growth in revenues and cash flow. We believe significant opportunities exist to expand our
customer base and provide additional services and products to existing customers.
- 3 -
• Pursue Strategic Acquisitions. We monitor the marketplace to identify and pursue accretive acquisitions
that expand the services and products we offer or that expand our geographic presence. After acquiring
other businesses, we will attempt to utilize our industry knowledge, network of customers and suppliers
and strategic asset base to operate the acquired businesses more efficiently and competitively, thereby
increasing revenues and cash flow. We believe that our diversified base of operations provides multiple
platforms for strategic growth through acquisitions.
• Pursue Strategic Alliances. Many of our larger customers are establishing strategic alliances with
midstream service providers such as us to address logistical and transportation problems or achieve
operational synergies. These strategic alliances are typically structured differently than our regular
commercial relationships, with the goal that such alliances would expand our business relationships with
our customers and suppliers. We intend to pursue strategic alliances with customers in the future.
• Expand Geographically. We work to identify and assess other attractive geographic markets for our
services and products based on the market dynamics and the cost associated with penetration of such
markets. We typically enter a new market through an acquisition or by securing at least one major
customer or supplier and then dedicating or purchasing assets for operation in the new market. Once in a
new territory, we seek to expand our operations within this new territory both by targeting new customers
and by selling additional services and products to our original customers in the territory.
Competitive Strengths
We believe we are well positioned to execute our business strategy because of the following competitive
strengths:
•
•
•
•
•
Asset Base and Integrated Distribution Network. We operate a diversified asset base that, together
with the services provided by Martin Resource Management, enables us to offer our customers an
integrated distribution network consisting of transportation, terminalling and midstream logistical
services while minimizing our dependence on the availability and pricing of services provided by third
parties. Our integrated distribution network enables us to provide customers a complementary portfolio
of transportation, terminalling, distribution and other midstream services for petroleum products and
by-products.
Strategically Located Assets. We believe we are one of the largest providers of shore bases and one of
the largest lubricant distributors and marketers in the United States Gulf Coast region. In addition, we
are one of the largest operators of marine service terminals in the United States Gulf Coast region
providing broad geographic coverage and distribution capability of our products and services to our
customers. Our natural gas gathering and processing assets are focused in areas that have continued to
experience high levels of drilling activity and natural gas production.
Specialized Transportation Equipment and Storage Facilities. We have the assets and expertise to
handle and transport certain petroleum products and by-products with unique requirements for
transportation and storage, such as molten sulfur and asphalt. For example, we own facilities and
resources to transport molten sulfur and asphalt, which must be maintained at temperatures between
approximately 275 and 350 degrees Fahrenheit to remain in liquid form. We believe these capabilities
help us enhance relationships with our customers by offering them services to handle their unique
product requirements.
Ability to Grow Our Natural Gas Gathering and Processing Services. We believe that, with our Prism
Gas assets, we have opportunities for organic growth in our natural gas gathering and processing
operations through increasing fractionation capacity, pipeline expansions, new pipeline construction
and bolt-on acquisitions. We believe Prism’s assets are well situated in the Haynesville Shale which is
one of the four largest U.S. shale deposits.
Experienced Management Team and Operational Expertise. Members of our executive management
team and the heads of our principal business lines have, on average, more than 30 years of experience
in the industries in which we operate. Further, these individuals have been employed by Martin
Resource Management, on average, for more than 18 years. Our management team has a successful
track record of creating internal growth and completing acquisitions. We believe our management
team’s experience and familiarity with our industry and businesses are important assets that assist us in
implementing our business strategies.
- 4 -
•
•
•
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 six times
for $334.6 million in total net proceeds, including capital contributions from our general partner. We
have also occasionally issued units to Martin Resource Management in exchange for cash or assets.
Fee-Based Contracts and Active Commodity Risk Management. We generate a majority of our cash
flow from fee-based contracts with our customers. In addition, a significant portion of these fee-based
contracts consist of reservation charges or minimum fee arrangements, which reduce the volatility of a
portion of cash flows to volume fluctuations. We seek to further minimize our exposure to commodity
price fluctuations through swaps for crude oil, natural gas and natural gas liquids. As of December 31,
2010, Prism Gas has hedged approximately 37% and 10% of its commodity risk by volume for 2011
and 2012, respectively. As of March 2, 2011, Prism Gas has hedged approximately 45% and 14% of
its commodity risk by volume for 2011 and 2012, respectively.
Terminalling and Storage Segment
Industry Overview. The United States petroleum distribution system moves petroleum products and by-
products from oil refinery and natural gas processing facilities to end users. This distribution system is comprised of a
network of terminals, storage facilities, pipelines, tankers, barges, rail cars and trucks. Terminals play a key role in moving
these products throughout the distribution system by providing storage, blending and other ancillary services.
In the 1990s, the petroleum industry entered a period of consolidation. Refiners and marketers developed large-
scale, cost-efficient operations resulting in several refinery acquisitions, combinations, alliances and joint ventures. This
consolidation resulted in major oil companies integrating the various components of their businesses, including
terminalling and storage. However, major integrated oil companies later concentrated their focus and resources on their
core competencies of exploration, production, refining and retail marketing and examined ways to lower their distribution
costs. Additionally, the Federal Trade Commission required some divestitures of terminal assets in markets in which
merged companies, alliances and joint ventures were regarded as having excessive market power. As a result of these
factors, oil and gas companies began to increasingly rely on third parties such as us to perform many terminalling and
storage services.
Although many large energy and chemical companies own terminalling and storage facilities, these companies
also use third-party terminalling and storage services. Major energy and chemical companies typically have a strong
demand for terminals owned by independent operators when such terminals are strategically located at or near key
transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal
storage when their owned storage facilities are inadequate, either because of lack of capacity, the nature of the stored
material or specialized handling requirements.
The Gulf Coast region is a major hub for petroleum refining. Approximately two-thirds of United States refining
capacity expansion in the 1990s occurred in this region. Growth in the refining and natural gas processing industries has
increased the volume of petroleum products and by-products that are transported within the Gulf Coast region, which
consequently has increased the need for terminalling and storage services.
The marine and offshore oil and gas exploration and production industries use terminal facilities in the Gulf Coast
region as shore bases that provide them logistical support services as well as provide a broad range of products, including
fuel oil, lubricants, chemicals and supplies. The demand for these types of terminals, services and products is driven
primarily by offshore exploration, development and production in the Gulf of Mexico. Offshore activity is greatly
influenced by current and projected prices of oil and natural gas.
Marine Shore Based Terminals. We own or operate 27 marine shore based terminals along the Gulf Coast
from Theodore, Alabama to Corpus Christi, Texas. Of our 27 marine shore based terminals, 13 were acquired on January
31, 2011 through our acquisition of certain terminalling assets from Martin Resource Management. Our terminal assets
are located at strategic distribution points for the products we handle and are in close proximity to our customers.
- 5 -
We are one of the largest operators of marine shore based terminals in the Gulf Coast region. These terminals are
used to distribute and market lubricants and the full service terminals also provide shore bases for companies that are
operating in the offshore exploration and production industry. Customers are primarily oil and gas exploration and
production companies and oilfield service companies, such as drilling fluid companies, marine transportation companies
and offshore construction companies. Shore bases typically provide logistical support, including the storing and handling
of tubular goods, loading and unloading bulk materials, providing facilities from which major and independent oil
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 27 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 fifteen full service terminals. These terminal facilities provide
logistical support services and provide storage and handling services for fuel oil and lubricants. The significant difference
between our full service terminals and our fuel and lubricant terminals is that our full service terminals generate additional
revenues by providing shore bases to support our 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, and oilfield service companies such as drilling fluids companies, marine transportation companies
and offshore construction companies.
The following is a summary description of our fifteen full service terminals:
Terminal
Location
Acres
Tanks
Pelican Island ...................
Harbor Island(1)...............
Freeport ............................
Port O’Connor(2) .............
Sabine Pass(3) ..................
Cameron “East”(4) ...........
Cameron “West”(5)..........
Venice (6) ………….
Theodore …………..
Pascagoula….……...
Amelia-2 (7)(8)…...…
Cameron-7 (7)(9)….
Cameron-8 (7)(10)….
Intracoastal City-2 (7)(11)
Fourchon-15 (7)(12)...
Galveston, Texas
Harbor Island, Texas
Freeport, Texas
Port O’Connor, Texas
Sabine Pass, Texas
Cameron, Louisiana
Cameron, Louisiana
Venice, Louisiana
Theodore, Alabama
Pascagoula, Mississippi
Amelia, Louisiana
Cameron, Louisiana
Cameron, Louisiana
Intracoastal City, Louisiana
Fourchon, Louisiana
51.3
25.5
17.8
22.8
23.1
34.3
16.9
2.8
14.0
29.0
4.0
8.0
3.0
10.0
8.0
16
12
1
8
11
12
5
2
18
5
10
1
8
15
28
Aggregate
Capacity
87,200 Bbls.
32,500 Bbls.
8,300 Bbls.
7,000 Bbls.
17,000 Bbls.
34,000 Bbls.
16,500 Bbls.
15,000 Bbls.
19,800 Bbls.
11,400 Bbls.
15,114 Bbls.
15,000 Bbls.
32,522 Bbls.
24,334 Bbls.
14,815 Bbls.
_________
(1) A portion of this terminal is located on land owned by a third party and leased under a lease that expires in January 2015.
(2) This terminal is located on land owned by a third party and leased under a lease that expires in March 2014.
(3) A portion of this terminal is located on land owned by a third party and leased under a lease that expires in September 2036.
(4) This terminal is located on land owned by third parties and leased under a lease that expires in March 2012 and can be extended
by us through March 2022.
(5) This terminal is located on land owned by a third party and leased under a lease that expires in February 2013.
(6) This terminal is located on land owned by a third party and leased under a sublease agreement that expires in August 2012.
(7) These terminals were acquired from Martin Resource Management on January 31, 2011.
(8) This terminal is located on land owned by a third party and leased under a lease that expires in March 2012.
(9) This terminal is located on land owned by a third party and leased under a lease that expires in July 2012 and can be extended by
us through July 2017.
(10)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.
(11)This terminal is located on land owned by a third party and leased under a lease that expires in December 2015 and can be
extended by us through December 2025.
(12)This terminal is located on land owned by a third party and leased under a lease that expires in December 2013 and can be
extended by us through December 2033.
- 6 -
Fuel and Lubricant Terminals. We own or operate twelve lubricant and fuel oil terminals located in the Gulf
Coast region that provide storage and handling services for lubricants and fuel oil.
The following is a summary description of our fuel and lubricant terminals:
Terminal
Location
Tanks
Aggregate Capacity
Amelia ........................ Amelia, Louisiana
Berwick(1).................. Berwick, Louisiana
Intracoastal City(2)(3)
Fourchon(4) ................
Cameron 6(5)(6)
Dulac(5)(7)
Fourchon 17(5)(8)
River Ridge (5)(9)
Morgan City DWC
31(5)(10)
Morgan City 33(5)(11) Morgan City, Louisiana
Fourchon 16(5)(12)
Venice 2(5)(13)
Intracoastal City, Louisiana
Fourchon, Louisiana
Cameron, Louisiana
Dulac, Louisiana
Fourchon, Louisiana
River Ridge, Louisiana
Morgan City, Louisiana
Fourchon, Louisiana
Venice, Louisiana
17 14,900 Bbls.
2 25,000 Bbls.
16 39,000 Bbls.
11 80,000 Bbls.
16 44,133 Bbls.
7 15,807 Bbls.
6 41,200 Bbls.
33 10,210 Bbls.
37 27,176 Bbls.
10 53,579 Bbls.
16 13,318 Bbls.
16 29,520 Bbls.
__________
(1) This terminal is located on land owned by third parties and leased under a lease that expires in September 2012 and can be
extended by us through September 2017.
(2) A portion of this terminal is located on land owned by a third party at which we throughput fuel oil pursuant to an agreement
that expired in January 2010 and is automatically renewed on a monthly basis.
(3) A portion of this terminal is located on land owned by third parties and leased under a lease that expires in April 2014.
(4) This terminal is located on land owned by a third party at which we throughput lubricants and fuel oil pursuant to an agreement
that expires in January 2017.
(5) These terminals were acquired from Martin Resource Management on January 31, 2011.
(6) This terminal is located on land owned by third parties and leased under a lease that expires in March 2013 and can be extended
by us through March 2013.
(7) This terminal is located on land owned by third parties and leased under a lease that expires in December 2012.
(8) This terminal is located on land owned by third parties and leased under a lease that expires in December 2013 and can be
extended by us through December 2033.
(9) This terminal is located on land owned by third parties and leased under a lease that expires in April 2019.
(10) This terminal is located on land owned by third parties and leased under a lease that expires in December 2014 and can be
extended by us through December 2034.
(11) This terminal is located on land owned by third parties and leased under a lease that expires in May 2014 and can be extended by
us through May 2019.
(12) This terminal is located on land owned by third parties and leased under multiple leases that expires in July 2011, March 2012,
and July 2012. These leases can be extended by us through July 2026, March 2022, and July 2022, respectively.
(13) This terminal is located on land owned by third parties and leased under a lease that expires in December 2012 and can be
extended by us through December 2027.
Specialty Petroleum Terminals. We own or operate 12 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 12 terminals, one was acquired on January 31, 2011 through our acquisition of
certain terminalling assets from Martin Resource Management. Our specialty terminals have an aggregate storage
capacity of approximately 2.53 million barrels. Each of these terminals has storage capacity for petroleum products and by-
products and has assets to handle products transported by vessel, barge and truck. The location and composition of our
terminals are structured to complement our other businesses and reflect our strategy to provide a broad range of integrated
services in the handling and transportation of petroleum products and by-products. We developed our terminalling and
storage assets by acquiring existing terminalling and storage facilities and then customizing and upgrading these facilities
as needed to integrate the facilities into our petroleum product and by-product transportation network and to more
effectively service customers. We expect to continue to acquire facilities, streamline their operations and customize and
upgrade them as part of our growth strategy. We also continually evaluate opportunities to add services and increase access
to our terminals to attract more customers and create additional revenues.
Our Tampa terminal is located on approximately 10 acres of land owned by the Tampa Port Authority that was
leased to us under a 10-year lease that commenced on December 16, 2006 with two five-year options. Our Stanolind
terminal is located on approximately 11 acres of land owned by us located on the Neches River in Beaumont. Our Neches
terminal is a deep water marine terminal located near Beaumont, Texas on approximately 50 acres of land owned by us.
Our Ouachita County terminal is located on approximately six acres of land owned by us on the Ouachita River in southern
Arkansas. Our Corpus Christi terminal is located on approximately 25 acres of land owned by us and has access to the
waterfront via marine docks owned by the Port of Corpus Christi.
- 7 -
At our Tampa, Neches, Stanolind and Corpus Christi terminals, our customers are primarily large oil refining and
natural gas processing companies. We charge either a fixed monthly fee or a throughput fee for the use of our facilities,
based on the capacity of the applicable tank. We conduct a substantial portion of our terminalling and storage operations
under long-term contracts, which enhances the stability and predictability of our operations and cash flow. We attempt to
balance our short-term and long-term terminalling contracts in order to allow us to maintain a consistent level of cash flow
while maintaining flexibility to earn higher storage revenues when demand for storage space increases. In addition, a
significant portion of the contracts for our specialty terminals provide for minimum fee arrangements that are not based on
the volume handled. At our Ouachita County terminal, Cross Oil Refining & Marketing, Inc., a related party owned by
Martin Resource Management, operates the terminal under a long-term terminalling agreement whereby we receive a
throughput fee.
In Channelview, Texas, we operate a terminal used for lubricant blending, storage, packaging and distribution.
This terminal is used as our central hub for lubricant distribution where we receive, package and ship our lubricants to our
terminals or directly to customers.
In Smackover, Arkansas, we own a refining terminal where we process crude oil into finished products, including
naphthenic lubricants, distillates, asphalt and other intermediate cuts. This process is dedicated to an affiliate of Martin
Resource Management through a long-term tolling agreement based upon throughput rates and a monthly reservation fee.
In Houston, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource
Management through a terminalling service agreement based on throughput rates.
In Port Neches, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource
Management through a terminalling service agreement based upon throughput rates.
In Omaha, Nebraska, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource
Management through a terminalling service agreement based on throughput rates.
In Beaumont, Texas we own Spindletop Terminal where we receive natural gasoline via pipeline and then ship
the product to our customers via other pipelines to which the facility is connected. Our fees for the use of this facility are
based on the number of barrels shipped from the terminal.
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.
We also continually evaluate opportunities to add services and increase access to our terminals to attract more
customers and create additional revenues. The following is a summary description of our specialty marine terminals:
Terminal
Location
Tanks
Aggregate
Capacity
Products
Description
Tampa(1)................. Tampa, Florida
8
716,000 Bbls.
Asphalt, sulfur and fuel oil Marine terminal,
Stanolind ................. Beaumont, Texas
9
555,000 Bbls.
Asphalt, crude oil, sulfur,
sulfuric acid and fuel oil
Neches..................... Beaumont, Texas
8
500,000 Bbls.
Ammonia, asphalt, fuel
oil, crude oil and
sulfur-based fertilizer
Ouachita County...... Ouachita County,
2
77,500 Bbls.
Crude oil
Arkansas
Corpus Christi ......... Corpus Christi,
4
330,000 Bbls.
Fuel oil and diesel
Texas
loading/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
for barges and
trucks
Marine Terminal,
loading/unloading
barges and vessels
and unloading
trucks
- 8 -
Terminal
Location
Channelview ......... Houston, Texas
Aggregate
Capacity
44,000 sq. ft.
Warehouse
34,000 Bbls
Products
Description
Lubricants
Lubricants blending
and storage
Cross Refining.......
Smackover, Arkansas
7,500 Bbls per
day
Naphthenic lubricants,
Distillates, Asphalt
Crude refining
facility
South Houston
Asphalt ..................
Houston, Texas
Port Neches
Asphalt ..................
Port Neches, Texas
Asphalt
71,000 Bbls
Asphalt
31,250 Bbls
Omaha Asphalt...... Omaha, Nebraska
114,225 Bbls
Asphalt
Spindletop ............. Beaumont, Texas
90,000 Bbls
Natural Gasoline
Lake Charles (2)
Lake Charles, Louisiana
18,000 sq.
ft.Warehouse
8,709 Bbls
Lubricants
Asphalt Processing
and storage
Asphalt Processing
and storage
Asphalt Processing
and storage
Pipeline receipts and
shipments
Lubricants storage
(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) 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.
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 such as asphalt, sulfur, anhydrous ammonia and sulfuric acid. As a result, our facilities typically
command higher terminal fees when compared to fees charged for terminalling and storage of other petroleum products.
The principal competitive factors affecting our terminals which provide lubricant distribution and marketing,
as well as shore bases at certain terminals, are the locations of the facilities, availability of competing logistical support
services and the experience of personnel and dependability of service. The distribution and marketing of our lubricant
products is brand sensitive and we encounter brand loyalty competition. Shore base rental contracts are generally long-
term contracts and provide more protection from competition. Our primary competitors for both lubricants and shore
bases include several independent operations as well as major companies that maintain their own similarly equipped
marine terminals, shore bases and lubricant supply sources.
Natural Gas Services Segment
NGL Industry Overview. NGLs are produced through natural gas processing. They are also a by-product of
crude oil refining. NGL consists of hydrocarbons that are vapors at atmospheric temperatures and pressures but change
to liquid phase under pressure. NGLs include ethane, propane, normal butane, iso butane and natural gasoline.
- 9 -
Ethane is almost entirely used as a petrochemical feedstock in the production of ethylene and propylene.
Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a fuel for heating, for
industrial applications, as motor fuel and as a refrigerant. Normal butane is used as a petrochemical feedstock, as a
blend stock for motor gasoline and as a component in aerosol propellants. Normal butane can also be made into iso
butane through isomerization. Iso butane is used in the production of motor gasoline, alkylation or MTBE and as a
component in aerosol propellants. Natural gasoline is used as a component of motor gasoline and as a petrochemical
feedstock.
NGL Facilities. We purchase NGLs primarily from natural gas processors and, to a lesser extent, major domestic
oil refiners. We transport NGLs using Martin Resource 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
Location
Capacity
Description
Wholesale terminals Arcadia, Louisiana(1)
Retail terminals
__________
Hattiesburg, Mississippi(2)
Mt. Belvieu, Texas(3)(2)
Kilgore, Texas
Longview, Texas
Henderson, Texas
2,400,000 barrels
100,000 barrels
70,000 barrels
90,000 gallons
30,000 gallons
12,000 gallons
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 Hattiesburg, Mississippi and Mont Belvieu, Texas from third parties under one-year
lease agreements, which have been renewed annually for more than 20 years.
(3) In addition, under a throughput agreement, we are entitled to the access and use of a truck loading and unloading and pipeline
distribution terminal owned by Enterprise Products and located at Mont Belvieu, Texas. Effective each January 1, this
agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving
written notice to the other party at least 30 days prior to the expiration of the then-applicable term. This terminal facility has
a storage capacity of 8,000 barrels.
Our NGL customers that utilize these assets consist of retail propane distributors, industrial processors and
refiners. For the year ended December 31, 2010, we sold approximately 35% of our NGL volume to independent retail
propane distributors located in Texas and the southeastern United States and approximately 65% of our NGL volume to
refiners and industrial processors.
NGL Competition. We compete with large integrated NGL producers and marketers, as well as small local
independent marketers. NGLs compete primarily with natural gas, electricity and fuel oil as an energy source, principally
on the basis of price, availability and portability.
NGL Seasonality. The level of NGL supply and demand is subject to changes in domestic production, weather,
inventory levels and other factors. While production is not seasonal, residential and wholesale demand is highly seasonal.
This imbalance causes increases in inventories during summer months when consumption is low and decreases in
inventories during winter months when consumption is high. If inventories are low at the start of the winter, higher prices
are more likely to occur during the winter. Additionally, abnormally cold weather can put extra upward pressure on prices
during the winter because there are less readily available sources of additional supply except for imports which are less
accessible and may take several weeks to arrive. General economic conditions and inventory levels have a greater impact
on industrial and refinery use of NGLs than the weather.
- 10 -
We generally maintain consistent margins in our natural gas services business because we attempt to pass
increases and decreases in the cost of NGLs directly to our customers. We generally try to coordinate our sales and
purchases of NGLs based on the same daily price index of NGLs in order to decrease the impact of NGL price volatility on
our profitability.
Prism Gas. Prism Gas is operated and reported as part of our natural gas services business segment, which has
been expanded to include natural gas gathering and processing as well as the NGL services business described herein.
Prism Gas has ownership interests in over 706 miles of gathering pipelines located in the natural gas producing
regions of North Central Texas and East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore Texas and
federal waters in the Gulf of Mexico as well as a 285 MMcfd natural gas processing plant located in East Texas. The
underlying assets are in two operating areas:
East Texas and North Central Texas
The East Texas and North Central Texas area assets consist of the Waskom Processing Plant, Harrison Pipeline
System, East Harrison Gathering System, the Marshall Line, Woodlawn, the Prism Liquids Pipeline, the
McLeod Gathering System, the Hallsville Gathering System, the Darco Gathering System and the East Texas
Gathering systems. The East Texas Gathering systems were sold effective November 1, 2010.
•
•
•
•
•
Waskom Processing Plant — The Waskom Processing Plant, located in Harrison County in East
Texas, currently has 285 MMcfd of processing capacity with full fractionation facilities. Expansions
to the processing plant were completed in March and June of 2007, July of 2008 and June of 2009
increasing the capacity from 150 MMcfd to 285 MMcfd. An additional expansion is anticipated and
currently scheduled to be complete in the fourth quarter of 2011 which will increase the capacity to
320 MMcfd. In June 2009, the Waskom fractionator was expanded to a capacity of 14,500 barrels per
day (“bpd”). For the years ended December 31, 2010 and 2009, inlet throughput and NGL
fractionation averaged approximately 281 and 243 MMcfd and 9,691 and 10,034 bpd, respectively.
Prism Gas owns an unconsolidated 50% operating interest in the Waskom Processing Plant with
CenterPoint Energy Gas Processing, Inc. owning the remaining 50% non-operating interest. We
reflect the results of operations from this facility using the equity method of accounting.
Harrison Pipeline System – In January of 2010, as 50% owner and operator of Waskom Gas
Processing Company, through Waskom Gas Processing Company’s wholly owned subsidiary
Waskom Midstream LLC, we acquired the Harrison Pipeline System, located in Harrison County in
East Texas. The system consisted of gathering pipeline, two 35 MMcfd dew point control plants and
various equipment. In March of 2010 the gas was rerouted to the Waskom Processing Plant which
resulted in the shutdown of the two dew point control plants. This allowed for the sale of one of the
plants in 2010 with the expectation of the second plant being sold in the second quarter of 2011. For
the year ended December 31, 2010, the system gathered 37 MMcfd. We reflect the results of
operations from this system using the equity method of accounting.
East Harrison Gathering System – The East Harrison Gathering System located in Harrison County in
East Texas was acquired in December of 2009. Prism Gas owns a consolidated 100% interest in this
system but leased the system to Waskom Midstream LLC effective March 1, 2010 and as such we
reflect the results of operations using the equity method of accounting. For 2010, volumes transported
through the system are included in the Harrison Pipeline System volumes.
The Marshall Line — The Marshall Line is a 10” gathering line that Prism Gas began leasing from
Kinder Morgan Texas in 2006. It is located in Harrison County in East Texas. The Marshall Line
gathers gas at intermediate pressure and feeds the Waskom Processing Plant. Prism Gas owns a
consolidated 100% interest in the lease which was assigned to Waskom Midstream LLC effective
March 1, 2010 and as such we reflect the results of operations using the equity method of accounting.
For 2010, volumes gathered on the Marshall Line are included in the Harrison Pipeline System
volumes.
Woodlawn Plant and Gathering System —Woodlawn is a natural gas gathering and processing
company which owns integrated gathering and processing assets in East Texas. Woodlawn’s system
- 11 -
consists of natural gas gathering pipe, a condensate transport pipeline and a 30 MMcfd processing
plant. For the years ended December 31, 2010 and 2009, the Woodlawn Gathering System gathered
approximately 25 and 24 MMcfd of natural gas, respectively. Prism owns a consolidated 100%
interest in this system.
The Prism Liquids Pipeline — The Prism Liquids Pipeline condensate system was formed from the
condensate transport pipe obtained in the Woodlawn acquisition. The system was subsequently
extended approximately 10 miles using lateral lines to gather condensate from additional locations.
The pipeline is a common carrier under the Rules and Regulations of the Railroad Commission of
Texas, Oil and Gas Division and, as such, operates under a tariff filed with the Railroad Commission
of Texas. The system gathers and transports condensate for producers along the main line which
extends south from the Woodlawn Plant to the Carthage Plant operated by DCP Midstream. For the
years ended December 31, 2010 and 2009, the Prism Liquids Pipeline transported 1,278 and 2,190
bpd of condensate, respectively. Prism owns a consolidated 100% interest in this system.
McLeod Gathering System — The McLeod Gathering System, located in East Texas and Northwest
Louisiana, is a low-pressure gathering system connected to the Waskom Processing Plant providing
processing and blending services for natural gas, with high nitrogen and high liquids content gathered
by the system. For the years ended December 31, 2010 and 2009, the McLeod Gathering System
gathered approximately 5 and 4 MMcfd of natural gas, respectively. Prism Gas owns a consolidated
100% interest in this system.
Hallsville Gathering System — The Hallsville Gathering System, located in Harrison County, Texas,
provides gathering and centralized compression for producers in the Oak Hill Field of East Texas.
The system operates at low pressure and redelivers gas to two interstate and three intrastate markets
via the Oakhill Gathering System. For the years ended December 31, 2010 and 2009, the Hallsville
Gathering System gathered approximately 13 and 18 MMcfd of natural gas, respectively. Prism Gas
owns a consolidated 100% interest in this system.
Darco Gathering System — The Darco Gathering System located in Harrison County, Texas was
acquired on November 1, 2010. The system consists of natural gas gathering pipe, various equipment
and intangibles. The gathering system is tied to the Harrison Pipeline System and to a third party
system. Prism Gas owns a consolidated 100% interest in this system. For November and December
2010, the Darco Gathering System gathered approximately 28 MMcfd of natural gas.
East Texas Gathering System — The East Texas Gathering System, located in Panola County, Texas,
is comprised of gathering systems built to gather gas produced in this area to market outlets. Prism
Gas sold its 100% interest in these systems effective November 1, 2010.
•
•
•
•
•
The natural gas supply for the Waskom Processing Plant, the Harrison Pipeline System, the East Harrison
Gathering system, the Marshall Line, the Woodlawn Plant and Gathering System, the McLeod Gathering System, the
Hallsville Gathering System and the Darco Gathering System is derived primarily from natural gas wells located in the
Cotton Valley and Haynesville formations of East Texas and Northwest Louisiana.
The Cotton Valley formation is one of the largest tight gas plays in the U.S. and extends over fourteen counties
in East Texas and into Northwest Louisiana. Prism Gas’ East Texas Operating Area includes assets that provide
gathering and processing services to producers in Cass, Gregg, Harrison, Panola and Rusk Counties, Texas and Caddo
Parish, Louisiana. The total number of wells permitted in Prism Gas’ East Texas Operating Area was 934 and 419 in
calendar years 2010 and 2009, respectively. These annual permit numbers include 363 and 200 permits for horizontal
wells in 2010 and 2009, respectively. Improved technology and drilling applications have enhanced the economics of
drilling in the Cotton Valley formation; however, in 2009 the economic benefit was more than offset by lower prices
and as a result drilling activity declined. Due to the continuing weakness in natural gas prices, we anticipate that
drilling activity in 2011 will stay above the low levels of 2009 but may not reach the 2010 levels.
In 2008, 2009 and 2010, development of the Haynesville Shale began. The Haynesville Shale is one of the
four largest U.S. shale deposits. One of the largest producers in the Haynesville Shale estimates the formation will
ultimately produce over 500 TCF of natural gas and will be among the top 10 natural gas fields in the world.
Haynesville gas contains less natural gas liquids than Cotton Valley gas and as a result, in both 2010 and 2009, the inlet
stream to Waskom Processing Plant contained less natural gas liquids than the historical average.
- 12 -
Our primary suppliers of natural gas to the Waskom Processing Plant include BP America Production
Company, Centerpoint Energy Gas Transmission Company, Endeavour Pipeline, Inc., Samson Lone Star, LLC and
Devon Energy Corporation, which collectively represented approximately 80% of the 281 MMcfd of natural gas
supplied in 2010 and approximately 65% of the 243 MMcfd of natural gas supplied for the year ended December 31,
2009. A substantial portion (approximately 22%) of the Waskom Processing Plant’s inlet volumes are derived from
production at BP’s Blocker, East Mountain, Carthage and Woodlawn fields in East Texas. Production from these fields
is dedicated to the Waskom Processing Plant under a contract with BP for the life of the Waskom partnership. We
receive natural gas at the Waskom Processing Plant from our McLeod Gathering System. We also receive a significant
amount of trucked-in NGLs that are fractionated, treated and stabilized at the Waskom Processing Plant. In June 2009,
we completed construction to expand the fractionator to 14,500 bpd to provide additional capacity for the increase in
NGL volumes from the plant expansion that was underway and trucked-in NGL volumes. In 2010 and 2009, trucked-in
NGL volumes decreased along with the decline in drilling activity. The processing plant was expanded to 285 MMcfd
in four phases with the first expansion of 30 MMcfd being completed in March 2007, the second expansion of 70
MMcfd being completed in June 2007, the third phase of 15 MMcfd being completed in July 2008 and the fourth phase
of 20 MMcfd being completed in June 2009. The fifth phase of 35 MMcfd is scheduled to be completed in the fourth
quarter of 2011.
There are currently five cryogenic processing plants that compete with Waskom for natural gas supplies.
Drilling activity in the Cotton Valley formation is moving north from the Panola-Harrison County line further into
Harrison County. Our plant is the preferred gas plant for much of this new production due to its proximity to the
increased drilling activity. In addition, the Waskom Processing Plant is the only plant in this area that has full
fractionation capability with access to strong local markets for NGLs. Purchasers of NGLs fractionated at Waskom
include various chemical companies and other industrial distributors.
The processing contracts for the Waskom Processing Plant are primarily percent-of-liquids (“POL”) contracts,
in which we retain a portion of the NGLs recovered as a processing fee, percent-of-proceeds (“POP”) contracts in which
we retain a portion of both the residue gas and the NGLs as payment for services and straight fee contracts in which we
receive a fee for every Mcf of gas delivered to the plant. Currently, approximately 42% of the contracts are POL, 39%
of the contracts are fee and 16% of the contracts are POP. In addition, there is one minor contract for processing on a
keep-whole basis.
Woodlawn provides gathering and processing services. The Woodlawn gathering system provides both low
and intermediate pressure gathering services. The gas is gathered to a 30 MMcfd refrigerated gas processing plant. The
NGL’s that are recovered at Woodlawn are trucked to the Waskom Processing Plant for fractionation. The contracts on
the Woodlawn system are primarily wellhead purchase with some POP contracts.
The McLeod Gathering System is a low-pressure gathering system that provides an outlet for high nitrogen and
high liquids content gas. In June 2003, Prism Gas constructed a pipeline to tie the McLeod Gathering System to the
Waskom Processing Plant to provide an outlet for high nitrogen gas. As a result, the majority of gas gathered on the
McLeod Gathering System is transported to the Waskom Processing Plant for processing and blending. Revenue from
the McLeod Gathering System is earned through gathering and compression fees and processing revenue. The
processing revenue results from the difference in the processing agreements with the producers and the agreement that
we have with the Waskom partnership. The processing contracts in the McLeod Gathering System are predominately
POP contracts. Natural gas gathered in the region surrounding the McLeod Gathering System has two primary outlets,
including the Waskom Processing Plant.
Cotton Valley and Haynesville wells are now being drilled in the southern area served by the McLeod
Gathering System. The new Cotton Valley wells that have recently been tied into the system are POL contracts with a
small gathering fee. These contracts are typically lower margin, higher volume contracts. The Haynesville wells are
typically fee based gathering. In this area, competition is geographic based with the McLeod Gathering System
capturing wells that are located near the system and the competitor capturing wells that are near its system.
The Hallsville Gathering System was constructed in 2005 and 2006 to gather low pressure gas. The wells tied
into the system are fee-based gathering contracts.
The Marshall Line was leased from Kinder Morgan to provide additional sources of gas for the Waskom
Processing Plant. The gas on the system is from Cotton Valley production and is tied into the system under percent of
index-based contracts.
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Gulf Coast
The Gulf Coast area assets consist of the Fishhook Gathering System and the Matagorda Offshore Gathering
System (“Matagorda”) located offshore and onshore of the Texas Gulf Coast.
•
•
Fishhook Gathering System — The Fishhook Gathering System, located in Jefferson County, Texas
offshore federal waters, gathers and transports gas in both offshore and onshore areas. In 2010,
volumes were shut in on a significant portion of the system as a pipeline was rerouted in response to a
producer platform removal. For the years ended December 31, 2010 and 2009 approximately 6 and
26 MMcfd of natural gas was gathered and transported on the system, respectively. Prism Gas owns
an unconsolidated 50% non-operating interest in Panther Interstate Pipeline Energy, LLC (“PIPE”),
the owner of the Fishhook Gathering System, with Panther Pipeline Ltd. owning the remaining 50%
operating interest. We reflect the results of operations from this system using the equity method of
accounting.
Matagorda Offshore Gathering System — The Matagorda Offshore Gathering System, located in
Matagorda County, Texas and offshore Texas State waters, gathers gas in both the offshore and
onshore areas. For both years ended December 31, 2010 and 2009, the system gathered approximately
8 and 10 MMcfd of natural gas, respectively. Prism Gas owns an unconsolidated 50% non-operating
interest in the Matagorda Offshore Gathering System, with Panther Pipeline Ltd. owning the
remaining 50% operating interest. We reflect the results of operations from this system using the
equity method of accounting.
The Fishhook Gathering System and the Matagorda Offshore Gathering System gather and transport natural
gas from Texas and federal waters of the Gulf of Mexico to onshore pipelines. The Fishhook Pipeline gathers and
transports natural gas principally from the eastern portion of the High Island Area which is further offshore. The
offshore natural gas supply for the Matagorda Offshore Gathering System is produced primarily from the Brazos Area
blocks, which are near shore in the Texas State waters. Additionally, the Matagorda Offshore Gathering System
includes onshore gathering in Matagorda, Wharton and Brazoria Counties.
The Fishhook Gathering System is located in Jefferson County, Texas offshore federal waters and gathers gas
from producers. Contracts on this system are 100% fee-for-service contracts with both the gathering fee and the
maximum transmission fee stated in PIPE’s FERC Gas Tariff, on file with the Federal Energy Regulatory Commission.
The Matagorda Offshore Gathering System gathers gas from producers. Contracts for the offshore portion of
the Matagorda Offshore Gathering System are a combination of fixed transportation fees plus a fixed margin. The
contracts for the onshore portion of the Matagorda Offshore Gathering System are under either a fixed margin or a fixed
transportation fee. There is limited competition for the offshore portion of the pipeline. There are currently two
pipelines situated in the offshore area but they primarily gather natural gas from wells further offshore than the
Matagorda Offshore Gathering System. There are several pipelines that compete with the onshore portion of the system.
These competing pipelines result in lower margins for the onshore portion of this system.
Sulfur Services Segment
Industry Overview. Sulfur is a natural element and is required to produce a variety of industrial products. In the
United States, approximately 10 million tons of sulfur are consumed annually, with the Tampa, Florida area being the
largest single market. Currently, all sulfur produced in the United States is “recovered sulfur,” or sulfur that is a by-product
from oil refineries and natural gas processing plants. Sulfur production in the United States is principally located along the
Gulf Coast, along major inland waterways and in some areas of the western United States.
Sulfur is an important plant nutrient and is primarily used in the manufacture of phosphate fertilizers, with the
balance used for industrial purposes. The primary application of sulfur in fertilizers occurs in the form of sulfuric acid.
Burning sulfur creates sulfur dioxide, which is subsequently oxidized and dissolved in water to create sulfuric acid. The
sulfuric acid is then combined with phosphate rock to make phosphoric acid, the base material for most high-grade
phosphate fertilizers.
Sulfur-based fertilizers are manufactured chemicals containing nutrients known to improve the fertility of soils.
Nitrogen, phosphorus, potassium and sulfur are the four most important nutrients for crop growth. These nutrients are
found naturally in soils. However, soils used for agriculture become depleted of these nutrients and frequently require
fertilizers rich in these essential nutrients to restore fertility.
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Industrial sulfur products (including sulfuric acid) are used in a wide variety of industries. For example, these
products are used in power plants, paper mills, auto and tire manufacturing plants, food processing plants, road
construction, cosmetics and pharmaceuticals.
Our Operations and Products. We have an integrated system of transportation assets and facilities relating to
our sulfur services. We gather molten sulfur from refiners, primarily located on the Gulf Coast, and from natural gas
processing plants, primarily located in the southwestern United States. We transport sulfur by inland and offshore barges,
rail cars and trucks. In the U.S., recovered sulfur is mainly kept in liquid form from production to usage at a temperature
of approximately 275 degrees Fahrenheit. Because of the temperature requirement, the sulfur industry uses specialized
equipment to store and transport molten sulfur. We have the necessary transportation and storage assets and expertise to
handle the unique requirements for transportation and storage of molten sulfur for domestic customers.
The terms of our commercial sulfur contracts typically range from one to five years in length. We handle molten
sulfur on margin-based contracts. The prices in such contracts are usually tied to a published market indicator and
fluctuate according to the price movement of the indicator. We also provide barge transportation and tank storage to large
integrated oil companies that produce sulfur and fertilizer manufacturers that consume sulfur under transportation and
storage contracts with remaining lives from one to two years in duration.
The sulfur prilling assets we acquired from the acquisition of Bay Sulfur in April 2005 are located at the Port of
Stockton in California and are used to process molten sulfur into pellets. These dry, bulk pellets are stored and loaded at
our facility at the Port of Stockton. The sulfur pellets are sold into certain U.S. and international agricultural markets. Our
facility at the Port of Stockton can process approximately 1,000 metric tons of molten sulfur per day. In January 2007, we
completed the construction of a sulfur priller at our Neches facility in Beaumont, Texas. In January 2009, we completed
the construction of a second sulfur priller at our Neches facility in Beaumont, Texas. The two Beaumont prillers have the
capacity to process approximately 4,000 metric tons of molten sulfur per day. We process molten sulfur into prilled sulfur
on take-or-pay fee contracts. Our sulfur prilling facilities provide refiners access to the export market for the sale of their
residual sulfur.
In late September 2007, we completed construction of a sulfuric acid production facility at our Plainview, Texas
location. This facility processes molten sulfur to produce approximately 500 short tons of sulfuric acid per day. Our
sulfuric acid facility provides our Plainview fertilizer plant with an economical supply of sulfuric acid and the remaining
sulfuric production is sold to Martin Resource Management which markets the product to third parties.
We entered the sulfur based fertilizer manufacturing business in 1990 through an acquisition. We acquired two
additional fertilizer manufacturing companies in 1998. Over the next two years we expended significant resources to
replace and update facilities and other assets and to integrate each of the businesses into our business. These acquisitions
have subsequently increased the profitability of our fertilizer business. In December 2005, sulfur fertilizer production
capacity was added with the purchase of the net operating assets of A & A Fertilizer, Ltd. (“A & A Fertilizer”). This
production capacity is located at our Neches deep-water marine terminal near Beaumont, Texas.
Fertilizer and related sulfur products are a natural extension of our molten sulfur business because of our access to
sulfur and our distribution capabilities. These products allow us to leverage the sulfur services segment of our business.
Our annual fertilizer and industrial sulfur products sales have grown from approximately 62,000 tons in 1997 to
approximately 275,000 tons in 2010 as a result of acquisitions and internal growth.
In the United States, fertilizer is generally sold to farmers through local dealers. These dealers are typically
owned and supplied by much larger wholesale distributors. We sell primarily to these wholesale distributors throughout the
United States. Our industrial sulfur products are marketed primarily in the eastern United States, where many paper
manufacturers and power plants are located. Our products are sold in accordance with price lists that vary from state to
state. These price lists are updated periodically to reflect changes in seasonal or competitive prices. We transport our
fertilizer and industrial sulfur products to our customers using third-party common carriers. We utilize rail shipments for
large volume and long distance shipments where available.
We manufacture and market the following sulfur-based fertilizer and related sulfur products:
• Plant nutrient sulfur products. We produce plant nutrient and agricultural ground sulfur products
at our two facilities in Odessa, Texas. We also produce plant nutrient sulfur at our facility in
Seneca, Illinois. Our plant nutrient sulfur product is a 90% degradable sulfur product marketed
under the Disper-Sul® trade name and sold throughout the United States to direct application
agricultural markets. Our agricultural ground sulfur products are used primarily in the western
United States on grapes and vegetable crops.
• Ammonium sulfate products, NPK products and related blended products. We produce various
grades of ammonium sulfate including coarse and standard grades, a 40% ammonium sulfate
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solution and a Kosher-approved food grade material. We also produce nitrogen-phosphorus-
potassium products (commonly referred to as NPK products). Our NPK products are an
ammoniated phosphate fertilizer containing nitrogen, phosphorus and potash that we manufacture
so all particles have a uniform composition. These products primarily serve direct application
agricultural markets within a 400-mile radius of our manufacturing plant in Plainview, Texas. We
blend our ammonium sulfate to make custom grades of lawn and garden fertilizer at our facility in
Salt Lake City, Utah. We package these custom grade products under both proprietary and private
labels and sell them to major retail distributors, and other retail customers, of these products.
•
•
Industrial sulfur products. We produce industrial sulfur products such as emulsified sulfur,
elemental pastille sulfur, and industrial ground sulfur products. We produce emulsified sulfur at
our Texarkana, Texas facility. Emulsified sulfur is primarily used to control the sulfur content in
the pulp and paper manufacturing processes. We produce elemental pastille sulfur at our two
Odessa, Texas facilities and at our Seneca, Illinois facility. Elemental pastille sulfur is used to
increase the efficiency of the coal-fired precipitators in the power industry. These industrial
ground sulfur products are also used in a variety of dusting and wettable sulfur applications such
as rubber manufacturing, fungicides, sugar and animal feeds.
Liquid sulfur products. We produce ammonium thiosulfate at our Neches terminal location in
Beaumont, Texas. This agricultural sulfur product is a clear liquid containing 12% nitrogen and
26% sulfur. This product serves as a liquid plant nutrient used directly through spray rigs or
irrigation systems. It is also blended with other NPK liquids or suspensions as well. Our market is
predominantly the Mid South and Coastal Bend area of Texas.
Our Sulfur Services Facilities.
We own 58 railcars and lease approximately 140 railcars equipped to transport molten sulfur. We own the
following major marine assets and use them to ship molten sulfur from our Beaumont, Texas terminal to our Tampa,
Florida terminal:
Asset
Class of Equipment
Capacity/Horsepower
Products Transported
Margaret Sue ................ Offshore tank barge
M/V Martin Explorer.... Offshore tugboat
Inland push boat
M/V Martin Express.....
Inland tank barge
MGM 101.....................
Inland tank barge
MGM 102.....................
10,450 long tons
7,200 horsepower
1,200 horsepower
2,450 long tons
2,450 long tons
Molten sulfur
N/A
N/A
Molten sulfur
Molten sulfur
We own the following sulfur prilling facilities as part of our sulfur services business:
Terminal
Location
Daily Production Capacity
Products Stored
Stockton ... Stockton, California 1,000 metric tons per day Molten and prilled sulfur
4,000 metric tons per day Molten and prilled sulfur
Neches ..... Beaumont, Texas
We lease approximately 59 railcars to transport ammonium thiosulfate. We own the following manufacturing
plants as part of our sulfur services business:
Facility
Location
Capacity
Description
Fertilizer plants (two) ............... Odessa, Texas
Fertilizer plant .......................... Seneca, Illinois
Fertilizer plant .......................... Plainview, Texas
Fertilizer plant .......................... Salt Lake City, Utah
Fertilizer plant .......................... Beaumont, Texas
Industrial sulfur plant ............... Texarkana, Texas
Sulfuric acid plant .................... Plainview Texas
70,000 tons/year
36,000 tons/year
180,000 tons/year
25,000 tons/year
70,000 tons/year
18,000 tons/year
150,000 tons/year
Dry sulfur fertilizer production
Dry sulfur fertilizer production
Fertilizer production
Blending and packaging
Liquid sulfur fertilizer production
Emulsified sulfur production
Sulfuric acid production
Competition. Seven phosphate fertilizer manufacturers together consume a vast majority of the total United
States production of sulfur. These companies buy from resellers as well as directly from producers. We own one of the four
vessels currently used to transport molten sulfur between United States ports on the Gulf of Mexico and Tampa, Florida.
Our primary competition consists of producers that sell their production directly to a fertilizer manufacturer that has its
own transportation assets or foreign suppliers from Mexico or Venezuela that may sell into the Florida market. Our
sulfuric acid products compete with regional producers and importers in the South and Southwest portion of the U.S. from
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Louisiana to California. Our sulfur-based fertilizer products compete with several large fertilizer and sulfur products
manufacturers. However, the close proximity of our manufacturing plants to our customer base is a competitive
advantage for us in the markets we serve and allows us to minimize freight costs and respond quickly to customer
requests.
Seasonality. Sales of our agricultural fertilizer products are partly seasonal as a result of increased demand
during the growing season.
Marine Transportation Segment
Industry Overview. The United States inland waterway system is a vast and heavily used transportation system.
This inland waterway system is composed of a network of interconnected rivers and canals that serve as water highways
and is used to transport vast quantities of products annually. This waterway system extends approximately 26,000 miles, of
which 12,000 miles are generally considered significant for domestic commerce.
The Gulf Coast region is a major hub for petroleum refining. Approximately two-thirds of United States refining
capacity expansion in the 1990s occurred in this region. The hydrocarbon refining process generates products and by-
products that require transportation in large quantities from the refinery or processor. Convenient access to and use of this
waterway system by the petroleum and petrochemical industry is a major reason for the current location of United States
refineries and petrochemical facilities. Recent growth in refining and natural gas processing capacity has increased the
volume of petroleum products and by-products transported within the Gulf Coast region, which consequently has increased
the need for transportation, storage and distribution facilities.
The marine transportation industry uses push boats and tugboats as power sources and tank barges for freight
capacity. The combination of the power source and tank barge freight capacity is called a tow.
Marine Fleet. We 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 system operates
coastwise along the Gulf of Mexico and on the United States inland waterway system, primarily between domestic ports
along the Gulf of Mexico Intracoastal Waterway, the Mississippi River system and the Tennessee-Tombigbee Waterway
system. Our inland tows generally consist of one push boat and one to three tank barges, depending upon the horsepower
of the push boat, the river or canal capacity and conditions, and customer requirements. Each of our offshore tows consist
of one tugboat, with much greater horsepower than an inland push boat, and one large tank barge.
We transport asphalt, fuel oil, gasoline, sulfur and other bulk liquids. The following is a summary description of
the marine vessels we use in our marine transportation business:
Class of Equipment
Number in Class
Capacity/Horsepower
Description of Products Carried
Inland tank barges .......
Inland tank barges .......
Inland push boats.........
Offshore tank barges ...
Offshore tugboats ........
13
31
18
5
4
20,000 bbl and under
20,000 - 30,000 bbl
800 - 3,800
horsepower
40,000 bbl and 95,000
bbl
3,200 - 7,200
horsepower
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. The fees we charge Martin
Resource Management are based on applicable market rates.
Competition. We compete primarily with other marine transportation companies. The marine barging industry
has experienced significant consolidation in the past few years. The total number of tank barges and push boats that operate
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in the inland waters of the United States declined from approximately 4,200 in 1982 and has reduced to approximately
3,100 by the end of 2009. We believe the earlier decrease primarily resulted from:
•
•
•
•
•
the increasing age of the domestic tank barge fleet, resulting in retirements;
a reduction in tax incentives, which previously encouraged speculative construction of new equipment;
stringent operating standards to adequately address safety and environmental risks;
the elimination of government programs supporting small refineries;
an increase in environmental regulations mandating expensive equipment modification; and
• more restrictive and expensive insurance.
There are several barriers to entry into the marine transportation industry that discourage the emergence of new
competitors. Examples of these barriers to entry include:
•
•
•
•
significant start-up capital requirements;
the costs and operational difficulties of complying with stringent safety and environmental regulations;
the cost and difficulty in obtaining insurance; and
the number and expertise of personnel required to support marine fleet operations.
We believe the reduction of the number of tank barges, the consolidation among barging companies and the
significant barriers to entry in the industry have resulted in a more stabilized and favorable pricing environment for our
marine transportation services.
We believe we compete favorably with many of our competitors. Historically, competition within the marine
transportation business was based primarily on price. However, we believe customers are placing an increased emphasis on
safety, environmental compliance, quality of service and the availability of a single source of supply of a diversified
package of services. In particular, we believe customers are increasingly seeking transportation vendors that can offer
marine, land, rail and terminal distribution services, as well as provide operational flexibility, safety, environmental and
financial responsibility, adequate insurance and quality of service consistent with the 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 rail cars or 250 tanker trucks. Pipelines
generally provide a less expensive form of transportation than marine transportation. However, pipelines are not able to
transport most of the products we transport and are generally a less flexible form of transportation because they are limited
to the fixed point-to-point distribution of commodities in high volumes over extended periods of time.
Seasonality. The demand for our marine transportation business is subject to some seasonality factors. Our
asphalt shipments are generally higher during April through November when weather allows for efficient road
construction. However, demand for marine transportation of sulfur, fuel oil and gasoline is directly related to production of
these products in the oil refining and natural gas processing business, which is fairly stable.
Our Relationship with Martin Resource Management
Martin Resource Management is engaged in the following principal business activities:
•
providing land transportation of various liquids using a fleet of trucks and road vehicles and road trailers;
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•
•
•
•
•
•
•
•
•
distributing fuel oil, asphalt, sulfuric acid, marine fuel and other liquids;
providing marine bunkering and other shore-based marine services in Alabama, Louisiana, Mississippi and
Texas;
operating a small crude oil gathering business in Stephens, Arkansas;
operating a lube oil packaging facility in Smackover, Arkansas;
operating an underground NGL storage facility in Arcadia, Louisiana;
building and marketing of sulfur processing equipments;
developing an underground natural gas storage facilities in Arcadia, Louisiana and near Delhi, Louisiana;
supplying employees and services for the operation of our business;
operating, for its account and our account, the docks, roads, loading and unloading facilities and other
common use facilities or access routes at our Stanolind terminal; and
•
operating, solely for our account, the asphalt facilities in Omaha, Nebraska.
We are and will continue to be closely affiliated with Martin Resource Management as a result of the following
relationships.
Ownership
As of March 2, 2011, Martin Resource Management owned an approximate 31.6% limited partnership interest
and a 2% general partnership interest in us and all of our incentive distribution rights.
Management
Martin Resource Management directs our business operations through its ownership and control of our general
partner. We benefit from our relationship with Martin Resource Management through access to a significant pool of
management expertise and established relationships throughout the energy industry. We do not have employees.
Martin Resource Management’s employees are responsible for conducting our business and operating our assets on our
behalf.
Related Party Agreements
We are a party to an omnibus agreement with Martin Resource Management. The omnibus agreement requires
us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in
connection with the operation of our business. We reimbursed Martin Resource Management for $81.7 million, $63.1
and $67.5 million of direct costs and expenses for the twelve months ended December 31, 2010, 2009 and 2008,
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,
2010, 2009, and 2008, the Conflicts Committee of our general partner approved reimbursement amounts of $3.8, $3.5, and
$2.9 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and
approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. These indirect expenses
covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury,
clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans
and other general corporate overhead functions we share with Martin Resource 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.
In addition to the omnibus agreement, we and Martin Resource Management have entered into various other
agreements that may not be the result of arm’s-length negotiations and consequently may not be as favorable to us as
they might have been if we had negotiated them with unaffiliated third parties. The agreements include, but are not
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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 2.4 million barrels. Our use of this storage facility gives us greater flexibility in our
operations by allowing us to store a sufficient supply of product during times of decreased demand for use when
demand increases.
In the aggregate, our purchases of land transportation services, NGL storage services, and lube oil product
purchases and sulfur services payroll reimbursements from Martin Resource Management accounted for approximately
14%, 15% and 10% of our total cost of products sold during the years ended December 31, 2010, 2009, and 2008,
respectively. We also purchase marine fuel from Martin Resource Management, which we account for as an operating
expense.
Correspondingly, Martin Resource Management is one of our significant customers. It primarily uses our
terminalling, marine transportation and NGL distribution services for its operations. We provide terminalling and
storage services under a terminal services agreement. We provide marine transportation services to Martin Resource
Management under a charter agreement on a spot-contract basis at applicable market rates. Our sales to Martin
Resource Management accounted for approximately 10%, 7% and 6% of our total revenues for the years ended
December 31, 2010, 2009 and 2008, respectively. We have entered into certain agreements with Martin Resource
Management pursuant to which we provide terminalling and storage and marine transportation services to Midstream
Fuel and Midstream Fuel provides terminal services to us to handle lubricants, greases and drilling fluids. Additionally,
we have entered into a long-term, fee for services-based Tolling Agreement with Martin Resource Management where
Martin Resource Management agrees to pay us for the processing of its crude oil into finished products, including
naphthenic lubricants, distillates, asphalt and other intermediate cuts.
For a more comprehensive discussion concerning the omnibus agreement and the other agreements that we
have entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related
Transactions, and Director Independence – Agreements.”
Approval and Review of Related Party Transactions
If we contemplate entering into a transaction, other than a routine or in the ordinary course of business
transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is
submitted for consideration to the board of directors of our general partner or to our management, as appropriate. If
the board of directors is involved in the approval process, it determines whether to refer the matter to the Conflicts
Committee of our general 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 $2.5 million for all damage caused by the named
windstorm. Our onshore program currently provides $30.0 million per occurrence for named windstorm events . For
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non-windstorm events, our deductible applicable to onshore physical damage remains at $0.5 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.
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 pollution claims, our insurance covers up to $1.0 billion of liability per accident or occurrence and for
non-pollution incidents, our insurance covers up to $2.0 billion of liability per accident or occurrence. We believe our
current insurance coverage is adequate to protect us against most accident related risks involved in the conduct of our
business and that we maintain appropriate levels of environmental damage and pollution insurance coverage. However,
there can be no assurance that all risks are adequately insured against, that any particular claim will be paid by the insurer,
or that we will be able to procure adequate insurance coverage at commercially reasonable rates in the future.
Environmental and Regulatory Matters
Our activities are subject to various federal, state and local laws and regulations, as well as orders of regulatory
bodies, governing a wide variety of matters, including marketing, production, pricing, community right-to-know,
protection of the environment, safety and other matters.
Environmental
We are subject to complex federal, state, and local environmental laws and regulations governing the discharge of
materials into the environment or otherwise relating to protection of human health, natural resources and the environment.
These laws and regulations can impair our operations that affect the environment in many ways, such as requiring the
acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the
environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations;
and imposing substantial liabilities on us for pollution resulting from our operations. Many environmental laws and
regulations can impose joint and several, strict liability, and any failure to comply with environmental laws and regulations
may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial
obligations, and, in some circumstances, the issuance of injunctions that can limit or prohibit our operations.
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may
affect the environment, and, thus, any changes in environmental laws and regulations that result in more stringent and
costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our
operations and financial position. Moreover, there is inherent risk of incurring significant environmental costs and
liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, chemical substances, and
wastes as well as the accidental release or spill of such materials into the environment. Consequently, we cannot assure you
that we will not incur significant costs and liabilities as result of such handling practices, releases or spills, including those
relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass
on those increases to our customers. While we believe that we are in substantial compliance with current environmental
laws and regulations and that continued compliance with existing requirements would not have a material adverse impact
on us, we cannot provide any assurance that our environmental compliance expenditures will not have a material adverse
impact on us in the future.
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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 have not
received any notification that we may be potentially responsible for cleanup costs under CERCLA.
Solid Waste
We generate both hazardous and nonhazardous solid wastes which are subject to requirements of the federal
Resource Conservation and Recovery Act, as amended (“RCRA”) and comparable state statutes. From time to time, the
U.S. Environmental Protection Agency (“EPA”) has considered making changes in nonhazardous waste standards that
would result in stricter disposal requirements for these wastes. Furthermore, it is possible some wastes generated by us that
are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes
being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an
increase in our capital expenditures or operating expenses.
We currently own or lease, and have in the past owned or leased, properties that have been used for the
manufacturing, processing, transportation and storage of petroleum products and by-products. Solid waste disposal
practices within oil and gas related industries have improved over the years with the passage and implementation of
various environmental laws and regulations. Nevertheless, a possibility exists that hydrocarbons and other solid wastes
may have been disposed of on or under various properties owned or leased by us during the operating history of those
facilities. In addition, a number of these properties have been operated by third parties over whom we had no control as to
such entities’ handling of hydrocarbons, hydrocarbon by-products or other wastes and the manner in which such
substances may have been disposed of or released. State and federal laws and regulations applicable to oil and natural gas
wastes and properties have gradually become more strict and, under such laws and regulations, we could be required to
remove or remediate previously disposed wastes or property contamination, including groundwater contamination, even
under circumstances where such contamination resulted from past operations of third parties.
Clean Air Act
Our operations are subject to the federal Clean Air Act, as amended, and comparable state statutes. Amendments
to the Clean Air Act adopted in 1990 contain provisions that may result in the imposition of increasingly stringent pollution
control requirements with respect to air emissions from the operations of our terminal facilities, processing and storage
facilities and fertilizer and related products manufacturing and processing facilities. Such air pollution control requirements
may include specific equipment or technologies to control emissions, permits with emissions and operational limitations,
pre-approval of new or modified projects or facilities producing air emissions, and similar measures. For example, the
Neches Terminal we use is located in an EPA-designated ozone non-attainment area, referred to as the Beaumont/Port
Arthur non-attainment area, which is now subject to a new, EPA-adopted 8-hour standard for complying with the national
standard for ozone. Categorized as being in “moderate” non-attainment for ozone, the Beaumont/Port Arthur non-
attainment area has until 2010 to achieve compliance with this new standard, which almost certainly will require the
adoption of more restrictive regulations in this non- attainment area for the issuance of air permits for new or modified
facilities. In addition, existing sources of air emissions in the Beaumont/Port Arthur area are already subject to stringent
emission reduction requirements. Failure to comply with applicable air statutes or regulations may lead to the assessment
of administrative, civil or criminal penalties, and/or result in the limitation or cessation of construction or operation of
certain air emission sources. We believe our operations, including our manufacturing, processing and storage facilities and
terminals, are in substantial compliance with applicable requirements of the Clean Air Act and analogous state laws.
Global Warming and Climate Change. Recent scientific studies have suggested that emissions of certain
gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to
warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering climate
change-related legislation to restrict greenhouse gas emissions. At least 17 states have already taken legal measures to
reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission
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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 must consider whether it is required to regulate
greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. The Court's holding in Massachusetts that greenhouse gases fall
under the federal Clean Air Act's definition of "air pollutant" may also result in future regulation of greenhouse gas
emissions from stationary sources under various Clean Air Act programs. New legislation or regulatory programs that
restrict emissions of greenhouse gases in areas in which we conduct business could adversely affect our operations and
demand for our services.
Clean Water Act
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state
laws impose restrictions and controls on the discharge of pollutants into federal and state waters. Regulations promulgated
under these laws require entities that discharge into federal and state waters obtain National Pollutant Discharge
Elimination System (“NPDES”) and/or state permits authorizing these discharges. The Clean Water Act and analogous
state laws assess penalties for releases of unauthorized pollutants into the water and impose substantial liability for the
costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that
individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff
and that applicable facilities develop and implement plans for the management of storm water runoff (referred to as storm
water pollution prevention plans (“SWPPPs”)) as well as for the prevention and control of oil spills (referred to as spill
prevention, control and countermeasure (“SPCC”) plans). As part of the regular overall evaluation of our on-going
operations, we are reviewing and, as necessary, updating SWPPPs for certain of our facilities, including facilities recently
acquired. In addition, we have reviewed our SPCC plans and, where necessary, amended such plans to comply with
applicable regulations adopted by EPA in 2002. We believe that compliance with the conditions of such permits and plans
will not have a material effect on our operations.
Oil Pollution Act
The Oil Pollution Act of 1990, as amended (“OPA”) imposes a variety of regulations on “responsible parties”
related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A
“responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an
offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public
and private damages including natural resource damages. Under OPA, vessels and shore facilities handling, storing, or
transporting oil are required to develop and implement oil spill response plans, and vessels greater than 300 tons in weight
must provide to the United States Coast Guard evidence of financial responsibility to cover the costs of cleaning up oil
spills from such vessels. The OPA also requires that all newly constructed tank barges engaged in oil transportation in the
United States be double hulled and all existing single hull tank barges be retrofitted with double hulls or phased out by
2015. We believe we are in substantial compliance with all of the oil spill-related and financial responsibility requirements.
Safety Regulation
The Company’s marine transportation operations are subject to regulation by the United States Coast Guard,
federal laws, state laws and certain international treaties. Tank ships, push boats, tugboats and barges are required to meet
construction and repair standards established by the American Bureau of Shipping, a private organization, and the United
States Coast Guard and to meet operational and safety standards presently established by the United States Coast Guard.
We believe our marine operations and our terminals are in substantial compliance with current applicable safety
requirements.
Occupational Health Regulations
The workplaces associated with our manufacturing, processing, terminal and storage facilities are subject to the
requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. We believe we
have conducted our operations in substantial compliance with OSHA requirements, including general industry standards,
record keeping requirements and monitoring of occupational exposure to regulated substances. In May 2001, Martin
Resource Management paid a small fine in relation to the settlement of alleged OSHA violations at our facility in
Plainview, Texas. Although we believe the amount of this fine and the nature of these violations were not, as an individual
event, material to our business or operations, this violation may result in increased fines and other sanctions if we are cited
for similar violations in the future. Our marine vessel operations are also subject to safety and operational standards
established and monitored by the United States Coast Guard.
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In general, we expect to increase our expenditures relating to compliance with likely higher industry and
regulatory safety standards such as those described above. These expenditures cannot be accurately estimated at this time,
but we do not expect them to have a material adverse effect on our business.
Jones Act
The Jones Act is a federal law that restricts maritime transportation between locations in the United States to
vessels built and registered in the United States and owned and manned by United States citizens. Since we engage in
maritime transportation between locations in the United States, we are subject to the provisions of the law. As a result, we
are responsible for monitoring the ownership of our subsidiaries that engage in maritime transportation and for taking any
remedial action necessary to insure that no violation of the Jones Act ownership restrictions occurs. The Jones Act also
requires that all United States-flagged vessels be manned by United States citizens. Foreign-flagged seamen generally
receive lower wages and benefits than those received by United States citizen seamen. This requirement significantly
increases operating costs of United States-flagged vessel operations compared to foreign-flagged vessel operations. Certain
foreign governments subsidize their nations’ shipyards. This results in lower shipyard costs both for new vessels and
repairs than those paid by United States-flagged vessel owners. The United States Coast Guard and American Bureau of
Shipping maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory
compliance costs for United States-flagged operators than for owners of vessels registered under foreign flags of
convenience. Following Hurricane Katrina, and again after Hurricane Rita, emergency suspensions of the Jones Act were
effectuated by the United States government. The last suspension ended on October 24, 2005. Future suspensions of the
Jones Act or other similar actions could adversely affect our cash flow and ability to make distributions to our unitholders.
Merchant Marine Act of 1936
The Merchant Marine Act of 1936 is a federal law that provides that, upon proclamation by the President of the
United States of a national emergency or a threat to the national security, the United States Secretary of Transportation may
requisition or purchase any vessel or other watercraft owned by United States’ citizens (including us, provided that we are
considered a United States citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased or
requisitioned by the United States government under this law, we would be entitled to be paid the fair market value of the
vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our
push boats or tugboats is requisitioned or purchased and its associated tank barge is left idle, we would not be entitled to
receive any compensation for the lost revenues resulting from the idled barge. We also would not be entitled to be
compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our push boats,
tugboats or tank barges.
Regulations Affecting Natural Gas Transmission, Processing and Gathering
We own a 50% non-operating interest in PIPE. PIPE’s Fishhook Gathering System transports natural gas in
interstate commerce and is thus subject to FERC regulations and FERC-approved tariffs as a natural gas company under
the National Gas Act of 1938 (“NGA”). Under the NGA, FERC has issued orders requiring pipelines to provide open-
access transportation on a basis that is equal for all shippers. In addition, FERC has the authority to regulate natural gas
companies with respect to: rates, terms and conditions of service; the types of services PIPE may provide to its customers;
the construction of new facilities; the acquisition, extension, expansion or abandonment of services or facilities; the
maintenance and retention of accounts and records; and relationships of affiliated companies involved in all aspects of the
natural gas and energy business.
On August 8, 2005, President George W. Bush signed into law the Domenici-Barton Energy Policy Act of 2005
(“EP Act”). The EP Act is a comprehensive compilation of tax incentives, authorized appropriations for grants and
guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. With
respect to regulation of natural gas transportation, the EP Act amends the NGA and the Natural Gas Policy Act of 1978 by
increasing the criminal penalties available for violations of each act. The EP Act also adds a new section to the NGA which
provides FERC with the power to assess civil penalties of up to $1,000,000 per day per violation of the NGA.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress,
FERC and the courts. However, we do not believe that we will be disproportionately affected as compared to other natural
gas producers and marketers by any action taken. We believe that our natural gas gathering operations meet the tests FERC
uses to establish a pipeline’s status as a gatherer exempt from FERC regulation under the NGA, but FERC regulation still
affects these businesses and the markets for products derived from these businesses. FERC’s policies and practices across
the range of its oil and natural gas regulatory activities, including, for example, its policies on open access transportation,
ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has
pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure our
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unitholders that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that
may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-
regulated transmission services and federally unregulated gathering services has been the subject of regular litigation, so, in
such a circumstance, the classification and regulation of some of our gathering facilities and intrastate transportation
pipelines may be subject to change based on future determinations by FERC and the courts.
Other state and local regulations also affect our natural gas processing and gathering business. Our gathering lines
are subject to ratable take and common purchaser statutes in Louisiana and Texas. Ratable take statutes generally require
gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer for
handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to
source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we
contract to purchase or transport oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to
the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering
activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to
resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not
directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale,
including state regulation of production rates and maximum daily production allowable from gas wells. While our
gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may
give producers a stronger basis to challenge proprietary status of a line, or the rates, terms and conditions of a gathering
line providing transportation service.
Pursuant to the Pipeline Safety Improvement Act of 2002, the United States Department of Transportation
(“DOT”) has adopted regulations requiring pipeline operators to develop integrity management programs for transportation
pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require
operators to:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence
area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.
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Employees
We do not have any employees. Under our omnibus agreement with Martin Resource Management, Martin
Resource Management provides us with corporate staff and support services. These services include centralized corporate
functions, such as accounting, treasury, engineering, information technology, insurance, administration of employee
benefit plans and other corporate services. Martin Resource Management employs approximately 647 individuals
including 38 employees represented by labor unions who provide direct support to our operations as of March 2, 2011.
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.
- 25 -
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:
•
•
•
•
•
•
•
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.
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.
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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 shown signs of improvement in recent months, 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;
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 entered into interest rate protection agreements to manage our interest rate risk exposure
by fixing a portion of the interest expense we pay on our long-term debt under our credit facility. There is considerable
turmoil in the world economy and banking markets, which could affect whether the counterparties to such interest rate
protection agreements are able to honor their agreements. If the counterparties fail to honor their commitments, we
- 27 -
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.
Current economic conditions may significantly affect our customers and their ability to make payments to us.
Since 2008, economic conditions in the United States have experienced a downturn due to the sequential
effects of the sub-prime lending crisis, general credit market crisis, the general unavailability of financing, collateral
effects on the finance and banking industries, volatile energy prices, concerns about inflation, slower economic activity,
decreased consumer confidence, reduced corporate profits and capital spending, adverse business conditions, increased
unemployment, liquidity concerns and declines in housing prices and house sales. How long these conditions will
continue is unclear.
Uncertainty about current economic conditions may adversely affect our customers’ abilities to make payments
to us when due. As such, we could see an increase in delayed or uncollected receivables, which may have an adverse
effect on our results of operations, cash flow and ability to make distributions to our unitholders.
The impacts of climate-related initiatives at the international, federal and state levels remain uncertain at this
time.
Currently, there are numerous international, federal and state-level initiatives and proposals addressing
domestic and global climate issues. Within the U.S., most of these proposals would regulate and/or tax, in one fashion
or another, the production of carbon dioxide and other “greenhouse gases” to facilitate the reduction of carbon-
compound emissions to the atmosphere, and provide tax and other incentives to produce and use more “clean energy.”
These include requirements that became effective January 2010 that require petroleum and natural gas facilities that
emit more than 25,000 metric tons of carbon dioxide equivalents per year to report their annual emissions of greenhouse
gases to the EPA beginning in 2011. In late 2010, the EPA finalized a rule requiring new and modified facilities that
will emit greenhouse gases in excess of certain thresholds to obtain construction permits that address their greenhouse
gas emissions. In addition, proposed federal, state and regional initiatives could require us to reduce greenhouse gas
emissions from our existing facilities. Requirements to reduce greenhouse gas emissions could cause us to incur
substantial costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and
(iii) administer and manage any greenhouse gas emissions programs, including the acquisition or maintenance of
emission credits or allowances. More broadly, mandates to reduce greenhouse gas emissions and to increase use of
renewable fuels could decrease demand for hydrocarbon-based products and energy, which could have an indirect, but
material, adverse effect on our business, financial condition and results of operations.
It is expected that climate change legislation will continue to be part of the legislative and regulatory
discussion for the foreseeable future. Increased regulation of emissions, especially in the transportation sector, could
impose significant additional costs on us and our customers. The impact of legislation and regulations on us will depend
on a number of factors, including (i) what industry sectors would be impacted, (ii) the timing of required compliance,
(iii) the overall emissions cap level, (iv) the allocation of emission allowances to specific sources, and (v) the costs and
opportunities associated with compliance. At this time, we cannot predict the effect that climate change regulation may
have on our business, financial condition or results of operations in the future.
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:
•
•
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;
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•
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. Additionally, our marine transportation operations and our assets in the Gulf of Mexico,
including our barges, push boats, tugboats and terminals, can be adversely impacted or damaged by hurricanes, tropical
storms, tidal waves or other related events. Demand for our lubricants and the diesel fuel we throughput in our terminalling
and storage segment can be affected if offshore drilling operations are disrupted by weather in the Gulf of Mexico.
National weather conditions have a substantial impact on the demand for our products. Unusually warm weather
during the winter months can cause a significant decrease in the demand for NGL products, fuel oil and gasoline. Likewise,
extreme weather conditions (either wet or dry) can decrease the demand for fertilizer. For example, an unusually wet
spring can delay planting of seeds, which can leave insufficient time to apply fertilizer at the planting stage. Conversely,
drought conditions can kill or severely stunt the growth of crops, thus eliminating the need to nurture plants with fertilizer.
Any of these or similar conditions could result in a decline in our net income and cash flow, which would reduce our
ability to make distributions to our unitholders.
If we incur material liabilities that are not fully covered by insurance, such as liabilities resulting from accidents
on rivers or at sea, spills, fires or explosions, our results of operations and ability to make distributions to our
unitholders could be adversely affected.
Our operations are subject to the operating hazards and risks incidental to terminalling and storage, marine
transportation and the distribution of petroleum products and by-products and other industrial products. These hazards and
risks, many of which are beyond our control, include:
•
•
•
•
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 September 11, 2001, terrorist attacks and their aftermath may
make some types of insurance more difficult or expensive for us to obtain. In addition, changes in the insurance markets
attributable to the effects of Hurricanes Katrina, Rita and Ike and their aftermath may make some types of insurance more
difficult or expensive for us to obtain. As a result, we may be unable to secure the levels and types of insurance we would
otherwise have secured prior to such events. Moreover, the insurance that may be available to us may be significantly more
expensive than our existing insurance coverage.
- 29 -
The price volatility of petroleum products and by-products can reduce our liquidity and results of operations
and ability to make distributions to our unitholders.
We purchase hydrocarbon products and by-products, such as molten sulfur, sulfur derivatives, fuel oils, LPGs,
lubricants, asphalt and other bulk liquids, and sell these products to wholesale and bulk customers and to other end users.
We also generate revenues through the terminalling and storage of certain products for third parties. The price and market
value of hydrocarbon products and by-products can be, and has recently been, volatile. Our liquidity and revenues have
been adversely affected by this volatility during periods of decreasing prices because of the reduction in the value and
resale price of our inventory. In addition, our liquidity and costs have been adversely affected during periods of increasing
prices because of the increased costs associated with our purchase of hydrocarbon products and by-products. Future price
volatility could have an adverse impact on our liquidity and results of operations, cash flow and ability to make
distributions to our unitholders.
Increasing energy prices could adversely affect our results of operations.
Increasing energy prices, such as those experienced in the past couple of years, could adversely affect our results
of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in
price of these products would increase our operating expenses, which could adversely affect our results of operations
including net income and cash flows. We cannot assure unitholders that we will be able to pass along increased operating
expenses to our customers.
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:
•
•
prevailing oil and natural gas prices and expectations about future prices and price volatility;
the cost of offshore exploration for, and production and transportation of, oil and natural gas;
• worldwide demand for oil and natural gas;
•
•
•
•
consolidation of oil and gas and oil service companies operating offshore;
availability and rate of discovery of new oil and natural gas reserves in offshore areas;
local and international political and economic conditions and policies;
technological advances affecting energy production and consumption;
• weather conditions;
•
•
environmental regulation; and
the ability of oil and gas companies to generate or otherwise obtain funds for exploration and production.
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We expect levels of offshore oil and gas exploration, development and production activity to continue to be
volatile and affect demand for our terminalling and storage services.
Our NGL and sulfur-based fertilizer products are subject to seasonal demand and could cause our revenues to
vary.
The demand for NGL and natural gas is highest in the winter. Therefore, revenue from our natural gas services
business is higher in the winter than in other seasons. Our sulfur-based fertilizer products experience an increase in demand
during the spring, which increases the revenue generated by this business line in this period compared to other periods. The
seasonality of the revenue from these products may cause our results of operations to vary on a quarter-to-quarter basis and
thus could cause our cash available for quarterly distributions to fluctuate from period to period.
The highly competitive nature of our industry could adversely affect our results of operations and ability to
make distributions to our unitholders.
We operate in a highly competitive marketplace in each of our primary business segments. Most of our
competitors in each segment are larger companies with greater financial and other resources than we possess. We may lose
customers and future business opportunities to our competitors and any such losses could adversely affect our results of
operations and ability to make distributions to our unitholders.
Our business is subject to compliance with environmental laws and regulations that may expose us to significant
costs and liabilities and adversely affect our results of operations and ability to make distributions to our
unitholders.
Our business is subject to federal, state and local environmental laws and regulations governing the discharge of
materials into the environment or otherwise relating to protection of human health, natural resources and the environment.
These laws and regulations may impose numerous obligations that are applicable to our operations, such as requiring the
acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the
environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations
and imposing substantial liabilities on us for pollution resulting from our operations. Numerous governmental authorities,
such as the U.S. Environmental Protection Agency and analogous state agencies, have the power to enforce compliance
with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Many
environmental laws and regulations can impose joint and several strict liability, and any failure to comply with
environmental laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties,
the imposition of investigatory and remedial obligations and, in some circumstances, the issuance of injunctions that can
limit or prohibit our operations. The clear trend in environmental regulation is to place more restrictions and limitations on
activities that may affect the environment, and, thus, any changes in environmental laws and regulations that result in more
stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse
effect on our operations and financial position.
The loss or insufficient attention of key personnel could negatively impact our results of operations and ability to
make distributions to our unitholders.
Our success is largely dependent upon the continued services of members of the senior management team of
Martin Resource Management. Those senior executive officers have significant experience in our businesses and have
developed strong relationships with a broad range of industry participants. The loss of any of these executives could have a
material adverse effect on our relationships with these industry participants, our results of operations and our ability to
make distributions to our unitholders.
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
- 31 -
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:
•
•
•
•
catastrophic events, including hurricanes;
environmental remediation;
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 affect on our results of operations, cash flow and ability to make distributions to our
unitholders.
Political, regulatory and economic factors may significantly affect our operations, the manner in which we
conduct our business and slow our rate of growth.
Due to changes in the political climate as a result of the outcome of recent state elections and the
Congressional election in the United States, we cannot predict with any certainty the nature and extent of the changes in
federal, state and local laws, regulations and policy we will face, or the effect of such elections on any pending
legislation. Any increased regulation, new policy initiatives, increased taxes or any other changes in federal law may
have an adverse effect on our business, financial condition and results of operations.
Our marine transportation business would be adversely affected if we do not satisfy the requirements of the
Jones Act or if the Jones Act were modified or eliminated.
The Jones Act is a federal law that restricts domestic marine transportation in the United States to vessels built
and registered in the United States. Furthermore, the Jones Act requires that the vessels be manned and owned by United
States citizens. If we fail to comply with these requirements, our vessels lose their eligibility to engage in coastwise trade
within United States domestic waters.
The requirements that our vessels be United States built and manned by United States citizens, the crewing
requirements and material requirements of the Coast Guard and the application of United States labor and tax laws
significantly increase the costs of United States flagged vessels when compared with foreign-flagged vessels. During the
past several years, certain interest groups have lobbied Congress to repeal the Jones Act to facilitate foreign flag
competition for trades and cargoes reserved for United States flagged vessels under the Jones Act and cargo preference
laws. If the Jones Act were to be modified to permit foreign competition that would not be subject to the same United
States government imposed costs, we may need to lower the prices we charge for our services in order to compete with
foreign competitors, which would adversely affect our cash flow and ability to make distributions to our unitholders.
Following Hurricane Katrina and again after Hurricane Rita, emergency suspensions of the Jones Act were effectuated by
the United States government. The last suspension ended on October 24, 2005. Future suspensions of the Jones Act or
other similar actions could result in similar consequences.
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Our marine transportation business would be adversely affected if the United States Government purchases or
requisitions any of our vessels under the Merchant Marine Act.
We are subject to the Merchant Marine Act of 1936, which provides that, upon proclamation by the President of
the United States of a national emergency or a threat to the national security, the United States Secretary of Transportation
may requisition or purchase any vessel or other watercraft owned by United States citizens (including us, provided that we
are considered a United States citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased or
requisitioned by the United States government under this law, we would be entitled to be paid the fair market value of the
vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our
push boats or tugboats is requisitioned or purchased and its associated tank barge is left idle, we would not be entitled to
receive any compensation for the lost revenues resulting from the idled barge. We also would not be entitled to be
compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our push boats,
tugboats or tank barges. If any of our vessels are purchased or requisitioned for an extended period of time by the United
States government, such transactions could have a material adverse affect on our results of operations, cash flow and ability
to make distributions to our unitholders.
Regulations affecting the domestic tank vessel industry may limit our ability to do business, increase our costs
and adversely impact our results of operations and ability to make distributions to our unitholders.
The OPA 90 provides for the phase out of single-hull vessels and the phase-in of the exclusive operation of
double-hull tank vessels in U.S. waters for barges that carry petroleum products that are regulated under OPA. Under OPA,
substantially all tank vessels that do not have double hulls will be phased out by 2015 and will not be permitted to enter
U.S. ports or trade in U.S. waters. The phase-out dates vary based on the age of the vessel and other factors. All but one of
our offshore tank barges are double-hull vessels that have no phase out date. We have five single-hull barges that will be
phased out of the petroleum product trade by the year 2015. The phase out of these single-hull vessels in accordance with
OPA may require us to make substantial capital expenditures, which could adversely affect our operations and market
position and reduce our cash available for distribution.
Our profitability is dependent upon prices and market demand for natural gas and NGLs, which are beyond our
control and have been volatile.
We are subject to significant risks due to fluctuations in commodity prices. These risks relate primarily to: (1) the
purchase of certain volumes of natural gas at a price that is a percentage of a relevant index and (2) certain processing
contracts for Prism Gas whereby we are exposed to natural gas and NGL commodity price risks.
The margins we realize from purchasing and selling a portion of the natural gas that we transport through our
pipeline systems decrease in periods of low natural gas prices because our gross margins are based on a percentage of the
index price. For the years ended December 31, 2010, and 2009, Prism Gas purchased approximately 18% and 19%,
respectively, of our gas at a percentage of relevant index. Accordingly, a decline in the price of natural gas could have an
adverse impact on our results of operations.
In the past, the prices of natural gas and NGLs have been extremely volatile and we expect this volatility to
continue. For example, in 2009, the spot price of Henry Hub natural gas ranged from a high of $6.10 per MMBtu to a low
of $1.84 per MMBtu. In 2010, the same price ranged from $7.51 per MMBtu to $3.18 per MMBtu. On December 31,
2010, the spot price was $4.22 per MMBtu.
We may not be successful in balancing our purchases and sales. In addition, a producer could fail to deliver
contracted volumes or deliver in excess of contracted volumes, or a consumer could purchase less than contracted volumes.
Any of these actions could cause our purchases and sales not to be balanced. If our purchases and sales are not balanced,
we will face increased exposure to commodity price risks and could have increased volatility in our operating income.
The markets and prices for residue gas and NGLs depend upon factors beyond our control. These factors include
demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors,
including:
•
•
•
the impact of weather on the demand for oil and natural gas;
the level of domestic oil and natural gas production;
the level of domestic industrial and manufacturing activity;
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•
•
•
•
•
•
the availability of imported oil and natural gas;
actions taken by foreign oil and gas producing nations;
the availability of local, intrastate and interstate transportation systems;
the availability and marketing of competitive fuels;
the impact of energy conservation efforts; and
the extent of governmental regulation and taxation.
Our commodity hedging activities may have a material adverse effect on our earnings, profitability, liquidity,
cash flows and financial condition.
As of December 31, 2010, Prism Gas has hedged approximately 37% and 10% of its commodity risk by volume
for 2011 and 2012, respectively. As of March 2, 2011, Prism Gas has hedged approximately 45% and 14% of its
commodity risk by volume for 2011 and 2012, respectively.
These hedging arrangements are in the form of swaps for crude oil, natural gas and natural gasoline. We
anticipate entering into additional hedges in 2011 and beyond to further reduce our exposure to commodity price
movements. The intent of these arrangements is to reduce the volatility in our cash flows resulting from fluctuations in
commodity prices.
We entered into these derivative transactions with investment grade banks. While we anticipate that future
derivative transactions will be entered into with investment grade counterparties, and that we will actively monitor the
credit rating of such counterparties, it is nevertheless possible that losses will result from counterparty credit risk in the
future.
Management will continue to evaluate whether to enter into any new hedging arrangements, but there can be no
assurance that we will enter into any new hedging arrangements or that our future hedging arrangements will be on terms
similar to our existing hedging arrangements. Also, we may seek in the future to further limit our exposure to changes in
natural gas, NGL and condensate commodity prices, and we may seek to limit our exposure to changes in interest rates by
using financial derivative instruments and other hedging mechanisms from time to time. To the extent we hedge our
commodity price and interest rate risk we may forego the benefits we would otherwise experience if commodity prices or
interest rates were to change in our favor.
Despite our hedging program, we remain exposed to risks associated with fluctuations in commodity prices. The
extent of our commodity price risk is related largely to the effectiveness and scope of our hedging activities. For example,
the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual
natural gas, NGL and condensate prices that we realize in our operations. Furthermore, we have entered into derivative
transactions related to only a portion of the volume of our expected natural gas supply and production of NGLs and
condensate from our processing plants; as a result, we will continue to have direct commodity price risk to the unhedged
portion. Our actual future production may be significantly higher or lower than we estimated at the time we entered into the
derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity
price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial
instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow
from our sale of the underlying physical commodity, resulting in a reduction of our liquidity.
As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of
our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, even though
our management monitors our hedging activities, these activities can result in substantial losses. Such losses could occur
under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging
arrangement, the hedging arrangement is imperfect or ineffective, or our hedging policies and procedures are not properly
followed or do not perform as planned. We cannot assure our unitholders that the steps we take to monitor our hedging
activities will detect and prevent violations of our risk management policies and procedures, particularly if deception or
other intentional misconduct is involved. For additional information regarding our hedging activities, please see “Item 7A.
Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”
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Our interest rate swap activities may have a material adverse effect on our earnings, profitability, liquidity, cash
flows and financial condition.
We are subject to interest rate risks associated with interest rate swap agreements related to our Senior Notes. Pursuant to
the terms of these interest rate swap agreements, we pay a variable rate interest payment based on the three-month LIBOR
and receive a fixed rate. The risk associated with these interest rate swaps exposes us to an increase in interest rates which
would result in an increase in interest expense and a corresponding decrease in net income. For additional information
regarding our interest rate swap activities, please see “Item 7A. Quantitative and Qualitative Disclosures about Market
Risk — Interest Rate Risk.”
The industry in which we operate is highly competitive, and increased competitive pressure could adversely
affect our business and operating results.
We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil,
natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas and
NGLs than we do. Some of these competitors may expand or construct gathering, processing and transportation systems
that would create additional competition for the services we provide to our customers. In addition, our customers who are
significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of
using ours. Likewise, our customers who produce NGLs may develop their own systems to transport NGLs in lieu of using
ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues
and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive
pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make
cash distributions to our unitholders.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies
or a change in policy by those agencies may result in increased regulation of our assets, which may cause our
revenues to decline and operating expenses to increase.
We believe that our natural gas gathering operations meet the tests the FERC uses to establish a pipeline’s status
as a gatherer exempt from FERC regulation under the NGA, but FERC regulation still affects these businesses and the
markets for products derived from these businesses. FERC’s policies and practices across the range of its oil and natural
gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release
and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive
policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure our unitholders that FERC
will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of
access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission
services and federally unregulated gathering services has been the subject of regular litigation, so, in such a circumstance,
the classification and regulation of some of our gathering facilities and intrastate transportation pipelines may be subject to
change based on future determinations by FERC and the courts.
Other state and local regulations also affect our business. Our gathering lines are subject to ratable-take and
common-purchaser statutes in Louisiana and Texas. Ratable-take statutes generally require gatherers to take, without
undue discrimination, oil or natural gas production that may be tendered to the gatherer for handling. Similarly, common
purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer.
These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport
oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we
operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural
gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and
natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but may
nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production
rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited
state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the
rates, terms and conditions of a gathering line providing transportation service.
Panther Interstate Pipeline Energy, LLC is also subject to regulation by FERC with respect to issues other than
ratemaking.
Under the NGA, FERC has the authority to regulate natural gas companies, such as Panther Interstate Pipeline
Energy, LLC with respect to: rates, terms and conditions of service; the types of services Panther Interstate Pipeline
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Energy, LLC may provide to its customers; the construction of new facilities; the acquisition, extension, expansion or
abandonment of services or facilities; the maintenance and retention of accounts and records; and relationships of affiliated
companies involved in all aspects of the natural gas and energy business. FERC’s actions in any of these areas or
modifications to its current regulations could impair Panther Interstate Pipeline Energy, LLC’s ability to compete for
business, the costs it incurs to operate, or the acquisition or construction of new facilities.
We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations requiring pipeline
operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do
the most harm in “high consequence areas.” The regulations require operators to:
•
•
•
•
•
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence
area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.
We currently estimate that we will incur costs of less than $0.5 million between 2010 and 2012 to implement
pipeline integrity management program testing along certain segments of our natural gas and NGL pipelines. This does not
include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be
necessary as a result of the testing program, which costs could be substantial.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our
operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore
subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid
rights of way or if such rights of way lapse or terminate. We obtain the rights to construct and operate our pipelines on land
owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our
inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of
operations and financial condition and our ability to make cash distributions to our unitholders.
Risks Relating to an Investment in the Common Units
Units available for future sales by us or our affiliates could have an adverse impact on the price of our common
units or on any trading market that may develop.
Martin Resource Management through its subsidiaries currently holds 889,444 subordinated units and 5,703,823
common units. The subordinated units will have no distribution rights until February 2012. At the end of such second
anniversary, the subordinated units will automatically convert to common units, having the same distribution rights as
existing common units.
Common units will generally be freely transferable without restriction or further registration under the Securities
Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the
registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise.
Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any
type without a vote of the unitholders. Our general partner may also cause us to issue an unlimited number of additional
common units or other equity securities of equal rank with the common units, without unitholder approval, in a number
of circumstances such as:
•
the issuance of common units in additional public offerings or in connection with acquisitions that
increase cash flow from operations on a pro forma, per unit basis;
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•
•
•
the conversion of subordinated units into common units;
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 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. Martin Resource Management owns an
approximate 31.6% limited partnership interest in us. Therefore, it is unlikely that our general partner would be removed
involuntarily without the consent of one or more affiliates of our general partner.
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.
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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
•
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:
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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.
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;
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. Additionally, if Martin Resource Management no longer controls
our general partner, amounts we owe under our credit facility may become immediately due and payable.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or
substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership
agreement on the ability of the owner of our general partner to transfer its ownership interest in our general partner to a
third party. A new owner of our general partner could replace the directors and officers of our general partner with its own
designees and control the decisions taken by our general partner. Martin Resource Management and its affiliates have
pledged their interests in our general partner and us to their bank group. If, at any time, Martin Resource Management no
longer controls our general partner, the lenders under our credit facility may declare all amounts outstanding thereunder
immediately due and payable. If such event occurs, we may be required to refinance our debt on unfavorable terms, which
could negatively impact our results of operations and our ability to make distribution to our unitholders.
Our general partner has a limited call right that may require unitholders to sell their common units at an
undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner
will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less
than all, of the remaining common units held by unaffiliated persons at a price not less than the then-current market price.
As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any
return on their investment. Unitholders may also incur a tax liability upon a sale of their units. No provision in our
partnership agreement, or in any other agreement we have with our general partner or Martin Resource Management,
prohibits our general partner or its affiliates from acquiring more than 80% of our common units. For additional
information about this call right and unitholders’ potential tax liability, please see “Risk Factors — Tax Risks — Tax gain
or loss on the disposition of our common units could be different than expected.”
Our common units have a limited trading volume compared to other publicly traded securities.
Our common units are quoted on the Nasdaq Global Select Market (“NASDAQ”) under the symbol “MMLP.”
However, daily trading volumes for our common units are, and may continue to be, relatively small compared to many
other securities quoted on the NASDAQ. The price of our common units may, therefore, be volatile.
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Failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes–Oxley
Act could have a material adverse effect on our unit price.
In order to comply with Section 404 of the Sarbanes–Oxley Act, we periodically document and test our internal
control procedures. Section 404 of the Sarbanes–Oxley Act requires annual management assessments of the effectiveness
of our internal controls over financial reporting addressing these assessments. During the course of our testing we may
identify deficiencies, which we may not be able to address in time to meet the deadline imposed by the Sarbanes–Oxley
Act for compliance with the requirements of Section 404. In addition, if we fail to maintain the adequacy of our internal
controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that
we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with
Section 404 of the Sarbanes–Oxley Act. Failure to achieve and maintain an effective internal control environment could
have a material adverse effect on the price of our common units.
Risks Relating to Our Relationship with Martin Resource Management
Existing litigation between Ruben Martin and Scott Martin and related parties concerning the ownership,
management and operation of Martin Resource Management, the owner of our General Partner, could adversely
affect us.
There are several pending lawsuits between Ruben Martin, the President, Chief Executive Officer and member of
the board of directors of our General Partner, and Scott Martin, who is Ruben Martin’s brother, and related parties
concerning the ownership, management and operation of Martin Resource Management, the owner of our General Partner.
We are not a party to any of those lawsuits and they do not assert any claims (i) against us, (ii) concerning our governance
or operations or (iii) against our directors, officers or employees with respect to their service to us. The existence of those
lawsuits, however, including any ultimate outcomes that might be deemed negative to us or our existing management team
could adversely affect our ability to access capital markets or obtain additional credit or negatively impact our business,
results of operations and/or ability to make distributions to our unitholders. Any similar effects from such litigation on
Martin Resource Management or its existing management team could also adversely affect us.
In addition, such litigation, depending on its ultimate outcome, could also result in changes in the existing boards
of directors and management teams of Martin Resource Management and us. To the extent that any such adverse
circumstances occur, they could be deemed by our lenders to have a “material adverse effect” on us, thereby providing
such lenders with an opportunity to prohibit further borrowings by us under our credit facility and, depending on the
circumstances, assert that an event of default exists thereunder. If any such event of default exists and is continuing, then,
upon the election of our lenders, all outstanding amounts due under our credit facility could be accelerated and could
become immediately due and payable. Similarly, a negative outcome in such litigation could result in a similar result under
the credit facility maintained by Martin Resource Management. While any such litigation remains pending, there can be no
assurance that the litigation parties adverse to our existing management team or the existing management team of Martin
Resource Management will not seek to disrupt, delay or postpone any future attempts by us to access the capital markets.
For a more detailed discussion of these pending litigation matters, please see “Item 9B. Other Information —
Existing Litigation at Martin Resource Management.”
Cash reimbursements due to Martin Resource Management may be substantial and will reduce our cash
available for distribution to our unitholders.
Under our omnibus agreement with Martin Resource Management, Martin Resource Management provides us
with corporate staff and support services on behalf of our general partner that are substantially identical in nature and
quality to the services it conducted for our business prior to our formation. The omnibus agreement requires us to
reimburse Martin Resource Management for the costs and expenses it incurs in rendering these services, including an
overhead allocation to us of Martin Resource 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 March 2, 2011, Martin Resource Management owns an approximate 31.6% limited partnership interest in
us. Furthermore, it owns and controls our general partner, which owns a 2.0% general partner interest and incentive
distribution rights in us. Conflicts of interest may arise between Martin Resource Management and our general partner, on
the one hand, and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own
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interests and the interests of Martin Resource Management over the interests of our unitholders. Potential conflicts of
interest between us, Martin Resource Management and our general partner could occur in many of our day-to-day
operations including, among others, the following situations:
• Officers of Martin Resource Management who provide services to us also devote significant time to the
businesses of Martin Resource Management and are compensated by Martin Resource Management for
that time.
• Neither our partnership agreement nor any other agreement requires Martin Resource Management to
pursue a business strategy that favors us or utilizes our assets or services. Martin Resource Management’s
directors and officers have a fiduciary duty to make these decisions in the best interests of the shareholders
of Martin Resource Management without regard to the best interests of the unitholders.
• Martin Resource Management may engage in limited competition with us.
• Our general partner is allowed to take into account the interests of parties other than us, such as Martin
Resource Management, in resolving conflicts of interest, which has the effect of reducing its fiduciary
duty to our unitholders.
• Under our partnership agreement, our general partner may limit its liability and reduce its fiduciary duties,
while also restricting the remedies available to our unitholders for actions that, without the limitations and
reductions, might constitute breaches of fiduciary duty. As a result of purchasing units, our unitholders
will be treated as having consented to some actions and conflicts of interest that, without such consent,
might otherwise constitute a breach of fiduciary or other duties under applicable state law.
• Our general partner determines which costs incurred by Martin Resource Management are reimbursable
by us.
• Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for
any services rendered on terms that are fair and reasonable to us or from entering into additional
contractual arrangements with any of these entities on our behalf.
• Our general partner controls the enforcement of obligations owed to us by Martin Resource Management.
• Our general partner decides whether to retain separate counsel, accountants or others to perform services
for us.
• The audit committee of our general partner retains our independent auditors.
•
In some instances, our general partner may cause us to borrow funds to permit us to pay cash distributions,
even if the purpose or effect of the borrowing is to make incentive distributions.
• Our general partner has broad discretion to establish financial reserves for the proper conduct of our
business. These reserves also will affect the amount of cash available for distribution.
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
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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. Thus,
“qualifying income” includes income from providing marine transportation services to customers with respect to crude oil,
natural gas and certain products thereof but does not include rental income from leasing vessels to customers. The recent
decision of the United States Court of Appeals for the Fifth Circuit in Tidewater Inc. v. United States, 565 F.3d 299 (5th
Cir. April 13, 2009) held that marine time charter agreements are “leases” that generate rental income for purposes of a
foreign sales corporation provision of the Code.
After the Tidewater decision, there was some uncertainty regarding the status of a significant portion of our
income as “qualifying income” and, thus, whether we were classified as a partnership for federal income tax purposes. As a
result of the Tidewater decision, we requested and obtained a favorable private letter ruling from the U.S. Internal Revenue
Service (“IRS”) to confirm that gross income from our marine time charter agreements constitutes “qualifying income”
under Section 7704 of the Internal Revenue Code. Additionally, after receiving such private letter ruling from the IRS, the
IRS issued Action on Decision 2010-01 I.R.B. 2010-22 on May 17, 2010, stating that the IRS disagreed and did not
acquiesce with the Fifth Circuit’s analysis and application of specific factors in the Tidewater case and took the position
that time charters should be treated as service contracts and not leases.
Moreover, current law may change so as to cause us to be treated as a corporation for federal income tax purposes
or otherwise subject us to entity-level taxation. At the federal level, members of Congress have considered substantive
changes to the existing U.S. tax laws that would have affected certain publicly traded partnerships. Although the legislation
considered would not have appeared to affect our tax treatment, we are unable to predict whether any such change or other
proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof
may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our
common units. At the state level, because of widespread state budget deficits and other reasons, several states are
evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other
forms of taxation. For example, we are required to pay Texas franchise tax at a maximum effective rate of 0.7% of our
gross income apportioned to Texas in the prior year. Imposition of any such tax on us by any other state will reduce the
cash available for distribution to you.
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
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
- 42 -
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 foreign persons face unique tax issues from owning common units that may result in
adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and
non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt
from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business
income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest
effective tax rate applicable to individuals, and non-U.S. persons will be required to file federal income tax returns and pay
tax on their share of our taxable income.
We treat a purchaser of our common units as having the same tax benefits without regard to the 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. A successful IRS challenge
to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the
timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the
value of our common units or result in audit adjustments to our unitholders’ tax returns.
Unitholders may be subject to state, local and foreign taxes and return filing requirements as a result of investing
in our common units.
In addition to federal income taxes, unitholders may be subject to other taxes, such as state, local and foreign
income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various
jurisdictions in which we do business or own property. Unitholders may be required to file state, local and foreign income
tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own
property and may be subject to penalties for failure to comply with those requirements. We own property and conduct
business in Alabama, Arkansas, California, Georgia, Florida, Illinois, Louisiana, Mississippi, Nebraska, Texas and Utah.
- 43 -
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 United States federal income tax treatment of publicly traded partnerships, including us, or an
investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any
modification to the United States federal income tax laws and interpretations thereof may or may not be applied
retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for
United States federal income tax purposes that is not taxable as a corporation (referred to as the “Qualifying Income
Exception”), affect or cause us to change our business activities, affect the tax considerations of an investment in us,
change the character or treatment of portions of our income and adversely affect an investment in our common units. For
example, in response to certain recent developments, members of Congress are considering substantive changes to the
definition of qualifying income under Internal Revenue Code Section 7704(d) and the treatment of certain types of income
earned from profits interests in partnerships. It is possible that these efforts could result in changes to the existing United
States tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes
or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our
common units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result
in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or
more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other
things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one
fiscal year. For purposes of determining whether the 50% threshold is met, multiple sales of the same units are counted
only once. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable
income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of
our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable
income for the year of termination. Our termination currently would not affect our classification as a partnership for federal
income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new
partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a
termination occurred. The IRS recently announced a relief 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
- 44 -
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.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Properties
A description of our properties is contained in Item 1. Business.
We believe we have satisfactory title to our assets. Some of the easements, rights-of-way, permits, licenses or
similar documents relating to the use of the properties that have been transferred to us in connection with our initial public
offering and the assets we acquired in our acquisitions, required the consent of third parties, which in some cases is a
governmental entity. We believe we have obtained sufficient third-party consents, permits and authorizations for the
transfer of assets necessary for us to operate our business in all material respects. With respect to any third-party consents,
permits or authorizations that have not been obtained, we believe the failure to obtain these consents, permits or
authorizations will not have a material adverse effect on the operation of our business.
Title to our property may be subject to encumbrances, including liens in favor of our secured lender. We believe
none of these encumbrances materially detract from the value of our properties or our interest in these properties, or
materially interfere with their use in the operation of our business.
Item 3. Legal Proceedings
From time to time, we are subject to certain legal proceedings claims and disputes that arise in the ordinary course
of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in
the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity.
In addition to the foregoing, as a result of a routine inspection by the U.S. Coast Guard of our tug Martin
Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, we were informed that an investigation was
commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq., and the
MARPOL Protocol 73/78 during the fourth quarter of 2007. We cooperated with the investigation and no formal
charges, fines and/or penalties have been asserted against us. Counsel representing us in this matter has informed us
that the investigation is now finished and the matter has been closed.
- 45 -
Item 4. Reserved
PART II
Item 5. Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity
Securities
Our common units are traded on the NASDAQ under the symbol “MMLP.” As of March 2, 2011 there were
approximately 19 holders of record and approximately 16,468 beneficial owners of our common units. In addition, as of
that date there were 889,444 subordinated units representing limited partner interests outstanding. All of the subordinated
units are held by Martin Resource Management through a subsidiary. There is no established public trading market for our
subordinated units. The following table sets forth the high and low closing sale prices of our common units for the periods
indicated, based on the daily composite listing of stock transactions for the NASDAQ and cash distributions declared per
common and subordinated units during those periods:
Fiscal 2010:
Quarters Ended
March 31, 2010
June 30, 2010
September 30, 2010
December 31, 2010
Fiscal 2009:
Quarters Ended
March 31, 2009
June 30, 2009
September 30, 2009
December 31, 2009
Common Units
Distributions Declared per Unit
High
$34.25
$32.45
$33.87
$39.37
Low
$29.34
$27.00
$28.78
$32.85
Common
$0.750
$0.750
$0.750
$0.760
Common Units
Distributions Declared per Unit
High
$21.00
$21.96
$28.50
$31.69
Low
$14.89
$17.33
$20.70
$26.02
Common
$0.750
$0.750
$0.750
$0.750
Subordinated1
$ —
$ —
$ —
$ —
Subordinated1
$0.750
$0.750
$0.750
$0.750
1
All of our original 4,253,362 subordinated units which were issued upon the formation of the Partnership and subsequently converted into common
units on a one-for-one basis received distributions prior to their conversion. The 889,444 subordinated units issued in connection with the acquisition
of the Cross assets will not receive cash distributions until February 2012, the first distribution paid after they automatically convert into common
units in November 2011.
On March 1, 2011, the last reported sales price of our common units as reported on the NASDAQ was $38.93 per
unit.
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.
In August 2010, we completed a public offering of 1,000,000 common units. 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. As a result of these simultaneous transactions, our general
partner was not required to contribute cash to us in order to maintain its 2% general partner interest in us since there was
no net increase in the outstanding limited partner units.
In February 2010, in connection with our public offering of 1,650,000 common units, our general partner
contributed $1.1 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. Until our current subordinated units convert into
common units in November 2011, the subordinated units will not have the right to receive distributions of available cash
from operating surplus .
Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate
to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures,
reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as
necessary, reserves to comply with the terms of any of our agreements or obligations. Our distributions are effectively
made 98% to unitholders and 2% to our general partner, subject to the payment of incentive distributions to our general
- 46 -
partner if certain target cash distribution levels to common unitholders are achieved. Distributions to our general partner
increase to 15%, 25% and 50% based on incremental distribution thresholds as set forth in our partnership agreement.
Our ability to distribute available cash is contractually restricted by the terms of our credit facility. Our credit
facility contains covenants requiring us to maintain certain financial ratios. We are prohibited from making any
distributions to unitholders if the distribution would cause a default or an event of default, or a default or an event of
default exists, under our credit facility. Please read “Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations — Liquidity and Capital Resources — Description of Our Credit Facility.”
Item 6. Selected Financial Data
The following table sets forth selected financial data and other operating data of Martin Midstream Partners L.P.
for the years ended December 31, 2010, 2009, 2008, 2007 and 2006 is derived from the audited consolidated financial
statements of Martin Midstream Partners L.P.
The following selected financial data are qualified by reference to and should be read in conjunction with our
Consolidated and Combined Financial Statements and Notes thereto and “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” included elsewhere in this document.
2010
2009
2008
(Dollars in thousands, except per unit amounts)
2007
2006
Income Statement Data:
Revenues..........................................................
Cost of product sold.........................................
Operating expenses..........................................
Selling, general, and administrative ................
Depreciation and amortization ........................
Total costs and expenses..................................
Other operating income ...................................
Operating income.............................................
Equity in earnings of unconsolidated entities .
Interest expense ...............................................
Debt prepayment premium ..............................
Other, net .........................................................
Income before income taxes ............................
Income taxes ....................................................
Net income.......................................................
$ 912,118
$ 662,385
$ 1,246,444
$ 804,327
$ 576,384
693,902
116,402
21,118
40,656
872,078
136
40,176
9,792
(33,716)
—
287
16,539
517
$ 16,022
457,259
117,438
19,775
39,506
633,978
6,013
34,420
7,044
(18,995)
—
326
22,795
592
$ 22,203
1,013,526
126,808
19,062
34,893
1,194,289
209
52,364
13,224
(21,433)
—
801
44,956
1,398
$ 43,558
618,689
104,165
13,918
26,323
763,095
703
41,935
10,941
(15,125)
—
405
38,156
5,595
$ 32,561
459,170
65,387
10,977
17,597
553,131
3,356
26,609
8,547
(12,466)
(1,160)
713
22,243
—
$ 22,243
Net income per limited partner unit.................
Weighted average limited partner units...........
$0.63
17,525,089
$1.17
14,680,807
$2.72
14,529,826
$1.67
14,018,799
$1.69
12,602,000
Balance Sheet Data (at Period End):
Total assets.......................................................
Due to affiliates................................................
Long-term debt ................................................
Partner’s capital (owner’s equity) ...................
$ 785,478
6,957
372,862
274,806
$ 685,939
13,810
304,372
264,951
$ 706,322
23,085
295,000
246,379
$ 656,604
17,119
225,000
246,765
$ 457,461
10,474
174,021
198,525
Cash Flow Data:
Net cash flow provided by (used in):
Operating activities .....................................
Investing activities ......................................
Financing activities .....................................
37,518
(81,318)
49,224
47,592
(14,675)
(34,944)
86,340
(106,621)
24,151
61,209
(130,295)
69,896
39,317
(95,098)
52,991
Other Financial Data:
Maintenance capital expenditures ...................
Expansion capital expenditures .......................
Total capital expenditures................................
4,653
12,367
$ 17,020
7,601
28,572
$36,173
17,998
89,435
$ 107,433
11,955
109,474
$ 121,429
12,391
78,267
$ 90,658
Cash dividends per common unit (in dollars) .
$ 3.00
$ 3.00
$ 2.91
$ 2.60
$ 2.44
The following tables present our historical results of operations, the effect of including the results of the Cross
assets which are included in our terminalling and storage segment and the revised total amounts included in our
consolidated financial statements:
- 47 -
Revenues
Costs and expenses:
Year Ended December 31, 2009
Historical
Martin Midstream
Partners LP
Cross Assets
Results
Revised Total
(Dollars in thousands, except per unit amounts)
$ 633,776
$ 28,609
$ 662,385
Cost of products sold (excluding depreciation and amortization)
Operating expenses ....................................................................................
Selling, general and administrative ............................................................
Depreciation and amortization .....................................................................
Total costs and expenses .....................................................................
Other operating income .........................................................................................
Operating income .........................................................................................
Equity in earnings of unconsolidated entities ..............................................
Interest expense ............................................................................................
Other, net
Net income before taxes ........................................................................................
Income tax benefit (expense) .......................................................................
Net income ............................................................................................................
457,259
98,677
18,090
35,143
609,169
6,160
30,767
7,044
(18,124)
303
19,990
549
$ 20,539
—
18,761
1,685
4,363
24,809
(147)
3,653
—
(871)
23
2,805
( 1,141)
$ 1,664
457,259
117,438
19,775
39,506
633,978
6,013
34,420
7,044
(18,995)
326
22,795
( 592)
$ 22,203
Revenues
Costs and expenses:
Year Ended December 31, 2008
Historical
Martin Midstream
Partners LP
Cross Assets
Results
Revised Total
(Dollars in thousands, except per unit amounts)
$ 1,213,958
$ 32,486
$ 1,246,444
Cost of products sold (excluding depreciation and amortization)
Operating expenses .....................................................................................
Selling, general and administrative ............................................................
Depreciation and amortization .....................................................................
Total costs and expenses .....................................................................
Other operating income .........................................................................................
Operating income .........................................................................................
Equity in earnings of unconsolidated entities ..............................................
Interest expense ............................................................................................
Other, net
Net income before taxes ........................................................................................
Income tax benefit (expense) .......................................................................
Net income ............................................................................................................
1,013,526
102,894
16,939
31,218
1,164,576
209
49,591
13,224
(19,777)
483
43,521
( 711)
$ 42,810
—
23,914
2,123
3,675
29,712
—
2,773
—
(1,656)
318
1,435
( 687)
$ 748
1,013,526
126,808
19,062
34,893
1,194289
209
52,364
13,224
(21,433)
801
44,956
( 1,398)
$ 43,558
Revenues
Costs and expenses:
Year Ended December 31, 2007
Historical
Martin Midstream
Partners LP
Cross Assets
Results
Revised Total
(Dollars in thousands, except per unit amounts)
$ 765,822
$ 38,505
$ 804,327
Cost of products sold (excluding depreciation and amortization)
Operating expenses ....................................................................................
Selling, general and administrative ............................................................
Depreciation and amortization .....................................................................
Total costs and expenses .....................................................................
Other operating income .........................................................................................
Operating income .........................................................................................
Equity in earnings of unconsolidated entities ..............................................
Interest expense ............................................................................................
Other, net
Net income before taxes ........................................................................................
Income tax benefit (expense) .......................................................................
Net income ............................................................................................................
618,689
83,533
11,985
23,442
737,649
703
28,876
10,941
(14,533)
299
25,583
( 644)
$ 24,939
—
20,632
1,933
2,881
25,446
—
13,059
—
(592)
106
12,573
( 4,951)
$ 7,622
618,689
104,165
13,918
26,323
763,095
703
41,935
10,941
(15,125)
405
38,156
( 5,595)
$ 32,561
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
References in this annual report to “we,” “ours,” “us” or like terms when used in a historical context refer to the
assets and operations of Martin Resource 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. You should read the
following discussion of our financial condition and results of operations in conjunction with the consolidated financial
- 48 -
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 United States Gulf
Coast region. Our four primary business lines include:
• Terminalling and storage services for petroleum and by-products;
• Natural gas services;
• Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution; and
• Marine transportation services for petroleum products and by-products.
The petroleum products and by-products we gather, process, transport, store and market are produced
primarily by major and independent oil and gas companies who often turn to third parties, such as us, for the
transportation and disposition of these products. In addition to these major and independent oil and gas companies, our
primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale
purchasers of these products. We generate the majority of our cash flow from fee-based contracts with these customers.
Our location in the Gulf Coast region of the United States provides us strategic access to a major hub for petroleum
refining, natural gas gathering and processing and support services for the exploration and production industry.
We were formed in 2002 by Martin Resource Management, a privately-held company whose initial
predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then,
Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its
management identified and capitalized on the needs of producers and purchasers of hydrocarbon products and by-
products and other bulk liquids. As of March 2, 2011, Martin Resource Management owns an approximate 31.6%
limited partnership interest in us. Furthermore, it owns and controls our general partner, which owns a 2.0% general
partner interest and incentive distribution rights in us.
The historical operation of our business segments by Martin Resource Management provides us with several
decades of experience and a demonstrated track record of customer service across our operations. Our current lines of
business have been developed and systematically integrated over this period of more than 50 years, including natural
gas services (1950s); sulfur (1960s); marine transportation (late 1980s) and terminalling and storage (early 1990s). This
development of a diversified and integrated set of assets and operations has produced a complementary portfolio of
midstream services that facilitates the maintenance of long-term customer relationships and encourages the development
of new customer relationships.
- 49 -
2010 Developments and Subsequent Events
Global financial markets and economic conditions have been, and continue to be volatile. Numerous events
have restricted current liquidity in the capital markets throughout the United States and around the world. One of the
features driving investment in master limited partnerships, including us, has been 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. Growth opportunities have been, and may be further constrained by a lack of liquidity in the financial markets.
During much of 2010 the financial markets were available to us. As such, we were able to issue senior unsecured long-
term debt in the first quarter 2010 and equity in both the first and third quarters of 2010. Additionally, as discussed in
the Subsequent Events section within this item, we were able to issue equity in February 2011 for the purpose of
reducing outstanding indebtedness under our credit facility.
Conditions in our industry continued to be challenging throughout 2010. For example:
• The general decline in drilling activity by gas producers in our areas of operations in Northeast Texas which
began during the fourth quarter of 2008 as a result of the global economic crisis continues. Several gas
producers in our areas of operation have substantially reduced drilling activity during 2009 and 2010 as
compared to their drilling levels during 2008.
• Coupled with the general decline in drilling activity is the federal government’s enhanced safety regulations
and inspection requirements as it relates to deep-water drilling in the Gulf of Mexico. On October 12, 2010,
the United States Government lifted the moratorium on deep water permitting and drilling. However, these
enhanced safety regulations and inspection requirements of the Bureau of Ocean Energy Management,
Regulation, and Enforcement (BOEMRE) continue to provide uncertainty surrounding the requirements for
and pace of issuance of permits on the Gulf of Mexico Outer Continental Shelf (OCS).
• The decline in the demand for marine transportation services based on decreased refinery production resulted
in an oversupply of equipment which was partially offset by the marine transportation services required in the
efforts to clean up the BP oil spill in the Gulf of Mexico.
Despite the reduced drilling activity and the decline in the demand for marine transportation services, we are
positioning ourselves to benefit from a recovering economy. In particular:
• We adjusted our business strategy for 2009 and 2010 to focus on maximizing our liquidity, maintaining a
stable asset base, and improving the profitability of our assets by increasing their utilization while controlling
costs. We reduced our capital expenditures in 2009, but increased them in 2010 based on our capital raised in
both the debt and equity markets during the year.
• We continue to evaluate opportunities to enter into commodity hedging transactions to further reduce our
commodity price risk.
• We completed the disposition of certain non-strategic assets including the April 2009 sale of the Mont Belvieu
Railcar Unloading Facility for $19.6 million, and we may consider marketing certain other non-strategic assets
in the future.
• Our near-term financial focus is to ensure that we have appropriate levels of liquidity to fund our growth
programs and potentially increase the distribution rate to our unitholders. The uncertain economic
environment of recent years and ongoing litigation at Martin Resource Management created a challenge in
obtaining such liquidity. However, in the past year we have had access to the capital markets and now have
appropriate levels of liquidity and operating cash flows to adequately fund our growth.
Recent Acquisitions
Acquisition of the Darco Gathering System. On November 12, 2010, we, through our wholly owned
subsidiary, Prism Gas, acquired approximately 20 miles of natural gas gathering pipeline and various equipment located
in Harrison County, Texas for approximately $25.0 million. We financed this acquisition with borrowings under our
revolving loan facility.
- 50 -
Acquisition by Waskom of the Harrison Pipeline System. On January 15, 2010, we, through Prism Gas, as 50%
owner and the operator of Waskom Gas Processing Company (“WGPC”), through WGPC’s 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. Our share of the acquisition cost is approximately $20.0 million.
Other Developments
Public Offerings. On August 17, 2010, we completed a public offering of 1.0 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.
On February 8, 2010, we completed a public offering of 1,650,000 common units, resulting in net proceeds of
$50.6 million, after payment of underwriters’ discounts, commissions and offering expenses. Our general partner
contributed $1.1 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner
interest in us. The net proceeds were used to pay down revolving debt under our credit facility.
Debt Financing Activities. Effective March 26, 2010, our credit facility was amended to (i) decrease the size
of our aggregate facility from $350.0 million to $275.0 million, (ii) convert all term loans to revolving loans, (iii) extend
the maturity date from November 9, 2012 to March 15, 2013, (iv) permit us to invest up to $40.0 million in our joint
ventures, (v) eliminate the covenant that limits our ability to make capital expenditures, (vi) decrease the applicable
interest rate margin on committed revolver loans, (vii) limit our ability to make future acquisitions and (viii) adjust the
financial covenants. For a more detailed discussion regarding our credit facility, see “Description of Our Long-Term
Debt—Credit Facility” within this Item.
On March 26, 2010, we completed a private placement of $200.0 million in aggregate principal amount of
8.875% senior unsecured notes due 2018 (“2018 Notes”) to qualified institutional buyers under Rule 144A. We received
proceeds of approximately $197.2 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.
Pursuant to the terms of a registration rights agreement entered into in connection with the offering of the 2018
Notes, we filed an exchange offer registration statement with the SEC on September 16, 2010 with respect to an offer to
exchange the 2018 Notes for registered notes with substantially identical terms. The registration statement was declared
effective by the SEC and the exchange offer was completed in the fourth quarter of 2010.
Subsequent Events
Public Offering. On February 9, 2011, we completed a public offering of 1,874,500 common units, our
general partner contributed $1.5 million in cash to in order to maintain its 2% general partner interest in us
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 was recorded in property, plant and
equipment. These assets are located across the Louisiana Gulf Coast. This acquisition was funded by borrowings under
our revolving loan facility.
Quarterly Distribution. On January 24, 2011, we declared a quarterly cash distribution of $0.76 per common unit
for the fourth quarter of 2010, or $3.04 per common unit on an annualized basis, to be paid on February 14, 2011 to
unitholders of record as of February 3, 2011, reflecting a $0.01 increase over the quarterly distribution paid in respect to the
third quarter of 2010.
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
- 51 -
using assumptions about matters that are highly uncertain. However, we have described below the critical accounting
policies that we believe could impact our consolidated and condensed financial statements most significantly.
You should also read Note 2, “Significant Accounting Policies” in Notes to Consolidated Financial Statements
contained in this annual report on Form 10-K. Some of the more significant estimates in these financial statements include
the amount of the allowance for doubtful accounts receivable and the determination of the fair value of our reporting units
as it relates to our annual goodwill evaluation.
Derivatives
All derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair
value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a
derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the
hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is
recognized in earnings. Our hedging policy allows us to use hedge accounting for financial transactions that are designated
as hedges. Derivative instruments not designated as hedges or hedges that become ineffective are being marked to market
with all market value adjustments being recorded in the consolidated statements of operations. As of December 31, 2010,
we have designated a portion of our derivative instruments as qualifying cash flow hedges. Fair value changes for these
hedges have been recorded in other comprehensive income as a component of partners’ capital.
Product Exchanges
We enter into product exchange agreements with third parties whereby we agree to exchange natural gas
liquids (“NGLs”) and sulfur with third parties. We record the balance of exchange products due to other companies
under these agreements at quoted market product prices and the balance of exchange products due from other
companies at the lower of cost or market. Cost is determined using the first-in, first-out method. Revenue and costs
related to product exchanges are recorded on a gross basis.
Revenue Recognition
Revenue for our four operating segments is recognized as follows:
Terminalling and storage – Revenue is recognized for storage contracts based on the contracted monthly tank
fixed fee. For throughput contracts, revenue is recognized based on the volume moved through our terminals at the
contracted rate. For our tolling agreement, revenue is recognized based on the contracted monthly reservation fee and
throughput volumes moved through the facility. When lubricants and drilling fluids are sold by truck, revenue is
recognized upon delivering product to the customers as title to the product transfers when the customer physically
receives the product.
Natural gas services – Natural gas gathering and processing revenues are recognized when title passes or
service is performed. NGL distribution revenue is recognized when product is delivered by truck to our NGL customers,
which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, we
recognize NGL distribution revenue when the customer receives the product from either the storage facility or pipeline.
Sulfur services – Revenue is recognized when the customer takes title to the product at our plant or the
customer facility.
Marine transportation – Revenue is recognized for contracted trips upon completion of the particular trip. For
time charters, revenue is recognized based on a per day rate.
Equity Method Investments
We use the equity method of accounting for investments in unconsolidated entities where the ability to exercise
significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and
advances plus our share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and
distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to
property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing
equity method goodwill is not amortized but is evaluated for impairment, annually. This goodwill is not subject to
amortization and is accounted for as a component of the investment. Equity method investments are subject to
impairment evaluation. No portion of the net income from these entities is included in our operating income.
- 52 -
We own an unconsolidated 50% of the ownership interests in Waskom Gas Processing Company (“Waskom”),
Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). Each of
these interests is accounted for under the equity method of accounting.
Goodwill
Goodwill is subject to a fair-value based impairment test on an annual basis. We are required to identify our
reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including
the existing goodwill and intangible assets. We are required to determine the fair value of each reporting unit and
compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds
the fair value of the reporting unit, we would be required to perform the second step of the impairment test, as this is an
indication that the reporting unit goodwill may be impaired.
All four of our “reporting units”, terminalling and storage, marine transportation, natural gas services and
sulfur services, contain goodwill.
We have performed the annual impairment tests as of September 30, 2010, September 30, 2009, and
September 30, 2008, 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 September 30, 2010, 2009 and 2008 the estimated fair value of each of our four
reporting units was in excess of its carrying value resulting in no impairment.
As a result of the deterioration in the overall stock market subsequent to September 30, 2008 and the decline in
our unit price, we reviewed specific factors, as outlined in under certain provisions of ASC 350-20, to determine if we
had a trigging event that required us to test our goodwill for impairment as of December 31, 2008. These factors
included whether there have been any significant fundamental changes since our annual impairment test to (i) our
business as a whole or to the reporting units, including regulatory changes, (ii) our level of operating cash flows, (iii)
our expectation of future levels of operating cash flows, (iv) our executive management team and (v) the carrying value
of our other long-lived assets. While these factors did not indicate a triggering event occurred, our unit price fell to a
point by December 31, 2008, that resulted in our total market capitalization being less than our partner’s equity. We
determined this to be a triggering event requiring us to perform an impairment test as of December 31, 2008. As a
result of our goodwill impairment test for each of the four reporting units as of December 31, 2008, no impairment was
determined to exist.
No such triggering events occurred that would cause us to perform an impairment test at either December 31,
2010 or 2009.
Significant changes in these estimates and assumptions could materially affect the determination of fair value
for each reporting unit which could give rise to future impairment. Changes to these estimates and assumptions can
include, but may not be limited to, varying commodity prices, volume changes and operating costs due to market
conditions and/or alternative providers of services.
Environmental Liabilities and Litigation
We have not historically experienced circumstances requiring us to account for environmental remediation
obligations. If such circumstances arise, we would estimate remediation obligations utilizing a remediation feasibility
study and any other related environmental studies that we may elect to perform. We would record changes to our
estimated environmental liability as circumstances change or events occur, such as the issuance of revised orders by
governmental bodies or court or other judicial orders and our evaluation of the likelihood and amount of the related
eventual liability.
Because the outcomes of both contingent liabilities and litigation are difficult to predict, when accounting for
these situations, significant management judgment is required. Amounts paid for contingent liabilities and litigation
have not had a materially adverse effect on our operations or financial condition and we do not anticipate they will in
the future.
Allowance for Doubtful Accounts
In evaluating the collectability of our accounts receivable, we assess a number of factors, including a specific
customer’s ability to meet its financial obligations to us, the length of time the receivable has been past due and
- 53 -
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 Obligation
We recognize and measure our asset and conditional asset retirement obligations and the associated asset
retirement cost upon acquisition of the related asset and based upon the estimate of the cost to settle the obligation at its
anticipated future date. The obligation is accreted to its estimated future value and the asset retirement cost is
depreciated over the estimated life of the asset.
Estimates of future asset retirement obligations include significant management judgment and are based on
projected future retirement costs. Such costs could differ significantly when they are incurred. Revisions to estimated
asset retirement obligations can result from changes in retirement cost estimates due to surface repair, and labor and
material costs, revisions to estimated inflation rates and changes in the estimated timing of abandonment. For example,
the Company does not have access to natural gas reserves information related to our gathering systems to estimate when
abandonment will occur.
Our Relationship with Martin Resource Management
Martin Resource Management directs our business operations through its ownership and control of our general
partner and under an omnibus agreement. In addition to the direct expenses, under the omnibus agreement, we are required
to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For
the years ended December 31, 2010, 2009 and 2008, the Conflicts Committee of our general partner approved
reimbursement amounts of $3.8, $3.5 and $2.9 million, respectively, reflecting our allocable share of such expenses. The
Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if
any, annually.
We are required to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes
on our behalf or in connection with the operation of our business. Martin Resource Management also licenses certain of its
trademarks and trade names to us under this omnibus agreement.
We are both an important supplier to and customer of Martin Resource Management. Among other things, we
sell sulfuric acid and provide marine transportation and terminalling and storage services to Martin Resource
Management. We purchase land transportation services, underground storage services, sulfuric acid and marine fuel
from Martin Resource Management. All of these services and goods are purchased and sold pursuant to the terms of a
number of agreements between us and Martin Resource Management.
For a more comprehensive discussion concerning the omnibus agreement and the other agreements that we
have entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related
Transactions, and Director Independence – Agreements.”
Results of Operations
The results of operations for the twelve months ended December 31, 2010, 2009 and 2008 have been derived
from our consolidated financial statements.
We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of
products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization
expense from revenues. The following table sets forth our operating revenues and operating income by segment for the
twelve months ended December 31, 2010, 2009 and 2008.
- 54 -
Year ended December 31, 2010:
Terminalling and storage.................................
Natural gas services.........................................
Sulfur services .................................................
Marine transportation ......................................
Indirect selling, general and administrative ....
Operating
Revenues
Revenues
Intersegment
Eliminations
Operating
Revenues
after
Eliminations
Operating
Income
(loss)
Operating
Income
Intersegment
Eliminations
Operating
Income (loss)
after
Eliminations
(In thousands)
$ 119,270
554,482
165,078
82,635
—
$ (4,354)
—
—
(4,993)
—
$ 114,916
554,482
165,078
77,642
—
$ 16,032
4,652
15,886
9,992
(6,386)
$ (1,776)
964
4,280
(3,468)
—
$ 14,256
5,616
20,166
6,524
(6,386)
Total ............................................
$ 921,465
$ (9,347)
$ 912,118
$ 40,176
$ —
$ 40,176
Year ended December 31, 2009:
Terminalling and storage.................................
Natural gas services.........................................
Sulfur services .................................................
Marine transportation ......................................
Indirect selling, general and administrative ....
$ 109,513
408,989
79,631
72,103
—
$ (4,219)
(7)
(2)
(3,623)
—
$ 105,294
408,982
79,629
68,480
—
$ 20,231
4,880
9,575
5,811
(6,077)
$ (2,332)
786
4,201
(2,655)
—
$ 17,899
5,666
13,776
3,156
(6,077)
Total ............................................................
$ 670,236
$ (7,851)
$ 662,385
$ 34,420
$ —
$ 34,420
Year ended December 31, 2008:
Terminalling and storage.................................
Natural gas services.........................................
Sulfur services .................................................
Marine transportation ......................................
Indirect selling, general and administrative ....
$ 122,960
679,375
372,987
80,059
—
$ (4,189)
—
(1,038)
(3,710)
—
$ 118,771
679,375
371,949
76,349
—
$ 15,034
2,780
31,956
8,104
(5,510)
$ (3,635)
945
5,224
(2,534)
—
$ 11,399
3,725
37,180
5,570
(5,510)
Total ............................................................
$1,255,381
$ (8,937)
$1,246,444
$ 52,364
$ —
$ 52,364
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, 2010 Compared to the Year Ended December 31, 2009
Our total revenues before eliminations were $921.5 million for the year ended December 31, 2010 compared to
$670.2 million for the year ended December 31, 2009, an increase of $251.3 million, or 37%. Our operating income before
eliminations was $40.2 million for the year ended December 31, 2010 compared to $34.4 million for the year ended
December 31, 2009, an increase of $5.8 million, or 17%.
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 ................................................................................
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Years Ended December 31,
2010
2009
(In thousands)
$ 71,471
47,799
119,270
44,549
41,857
426
16,650
15,788
244
$ 16,032
$ 73,885
35,628
109,513
31,331
45,783
1,955
15,717
14,727
5,504
$ 20,231
Revenues. Our terminalling and storage revenues increased $9.8 million, or 9%, for the year ended December 31,
2010 compared to the year ended December 31, 2009. Service revenue decreased $2.4 million compared to the prior year
period. This decrease is primarily due to the historical Cross refining margin included in the recast 2009 historical
revenues exceeding the contractual tolling fee for feedstock processing received in 2010 of $4.7 million. This decrease
was offset by an increase in activities at terminals of $2.3 million. Product revenue increased $12.2 million compared to
the prior year period. Of this increase, $10.1 million was due to a 13% increase in average selling price and an 18%
increase in sales volumes at our Mega Lubricants facility. Additionally, $7.5 million of this increase was due to the
conversion of a consigned product delivery agreement with one of our customers to a buy/sell product delivery agreement
during the third quarter of 2010. These increases were partially offset by a $5.4 million decrease due to the sale of our
traditional lubricant business including inventory to Martin Resource Management in April 2009 in return for a service fee
for lubricant volumes moved through our terminals.
Cost of products sold. Our cost of products sold increased $13.2 million, or 42% for the year ended December
31, 2010 compared to the year ended December 31, 2009. Of this increase, $10.1 million was due to an 18% increase in
average cost of product and a 18% increase in sales volumes at our Mega Lubricants facility and $6.7 million of this
increase was due to the conversion of a consigned product delivery agreement with one of our customers to a buy/sell
product delivery agreement during the third quarter of 2010. The remaining $1.0 million increase was due to the increase
in consigned marine delivery expenses. These increases were partially offset by a $4.6 million decrease due to the sale of
our traditional lubricant business including inventory to Martin Resource Management in April 2009 in return for a service
fee for lubricant volumes moved through our terminals
Operating expenses. Operating expenses decreased $3.9 million, or 9%, for the year ended December 31, 2010
compared to the year ended December 31, 2009. This decrease was primarily the result of a reduction of the historical
level of expenses attributable to the Cross assets of $4.6 million. This decrease was offset by an increase in salaries and
burden of $0.7 million.
Selling, general and administrative expenses. Selling, general and administrative expenses decreased $1.5
million, or 78% for the year ended December 31, 2010 compared to the year ended December 31, 2009. This decrease
was primarily a result of the historical level of expenses attributable to the Cross assets.
Depreciation and amortization. Depreciation and amortization increased $0.9 million, or 6%, for the year ended
December 31, 2010 compared to the year ended December 31, 2009. This increase was primarily a result of our recent
acquisitions and capital expenditures.
Other operating income (loss). Other operating income for the year ended December 31, 2010 consisted
primarily of gains and losses on the disposal of assets. Other operating income for the year ended December 31, 2009
consisted primarily of a gain on the sale of our Mont Belvieu terminal on April 30, 2009.
In summary, terminalling and storage operating income decreased $4.2 million, or 21%, for the year ended
December 31, 2010 compared to the year ended December 31, 2009.
Natural Gas Services Segment
The following table summarizes our results of operations in our natural gas services segment.
Revenues:
NGLs..................................................................................................
Natural gas .........................................................................................
Non-cash mark to market and impairment adjustments of
commodity derivatives.......................................................................
Gain (loss) on cash settlements of commodity derivatives ................
Other operating fees ..........................................................................
Total revenues..............................................................................
Cost of products sold:
NGLs .................................................................................................
Natural gas ........................................................................................
Total cost of products sold ...........................................................
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Years Ended December 31,
2010
2009
(In thousands)
$501,919
46,812
$384,124
20,334
253
582
4,916
554,482
482,231
46,187
528,418
(2,490)
3,273
3,748
408,989
364,350
19,261
383,611
Operating expenses .................................................................................
Selling, general and administrative expenses..........................................
Depreciation and amortization ................................................................
7,689
8,588
5,023
4,764
8,627
7,332
4,527
4,892
Other operating income ..........................................................................
Operating income ................................................................................
(112)
$ 4,652
(12)
$ 4,880
NGLs Volumes (Bbls) ...........................................................................
Natural Gas Volumes (Mmbtu) ..............................................................
9,730
11,390
9,880
6,155
*Information above does not include activities relating to Waskom, PIPE,
Matagorda and BCP investments
Equity in Earnings of Unconsolidated Entities .......................................
$ 9,792
$ 7,044
Waskom:
Plant Inlet Volumes (MMcfd) ................................................................
Frac Volumes (Bbls/d) ...........................................................................
281
9,691
243
10,034
Revenues. Our natural gas services revenues increased $145.5 million, or 36% for the year ended December
31, 2010 compared to the year ended December 31, 2009 primarily due to higher commodity prices.
For the year ended December 31, 2010, NGL revenues increased $117.8 million, or 31% and natural gas
revenues increased $26.5 million, or 130%. During 2010, our NGL average sales price per barrel increased $12.71 or
33% and our natural gas average sales price per Mmbtu increased $0.81, or 24% compared to the same period in 2009.
NGL sales volumes for the year remained relatively consistent and natural gas volumes increased 85% compared to the
same period of 2009. The increase in natural gas volumes is primarily due to the Waskom plant shutdown in second
quarter 2009 and the acquisition by Waskom Midstream LLC of the Harrison Gathering system in first quarter 2010.
Our natural gas services segment utilizes derivative instruments to manage the risk of fluctuations in market
prices for its anticipated sales of natural gas, condensate and NGLs. This activity is referred to as price risk
management. For the year ended December 31, 2010, 44% of our total natural gas volumes and 41% of our total NGL
volumes were hedged as compared to 54% and 35%, respectively in 2009. The impact of price risk management and
marketing activities increased total natural gas and NGL revenues $0.8 million for 2010 compared to an increase of $0.8
million in the same period of 2009.
Costs of product sold. Our cost of products increased $144.8 million, or 38%, for the year ended December
31, 2010 compared to the same period in 2009. Of the increase, $117.9 million relates to NGLs and $26.9 million
relates to natural gas. Our NGL per barrel margins remained relatively consistent compared to the same period in 2009.
The percentage increase relating to natural gas cost of products sold is greater than the percentage increase in natural
gas revenues which caused our Mmbtu margins to decrease by 68%. This is primarily a result of operational issues
whereby certain gas volumes are not currently being processed resulting in lower margins.
Operating expenses. Operating expenses decreased $0.9 million, or 11% for the year ended December 31,
2010 compared to the same period of 2009. This decrease was primarily a result of the Marshall Pipeline lease being
assigned to Waskom Gas Processing in 2010 ($0.6 million). In addition, we saw a decrease in large compressor
maintenance $0.3 million in 2010 as compared to 2009.
Selling, general and administrative expenses. Selling, general and administrative expenses increased $1.3
million, or 17% for the year ended December 31, 2010 compared to the same period of 2009. This increase was
primarily a result of increased acquisition costs associated with the Waskom Midstream LLC acquisition ($1.0 million),
offset by a reduction in audit related expenses for Waskom Gas Processing Company ($0.2 million). Additionally, the
increase is attributed to the write-off of an uncollectible customer receivable ($0.5 million).
Depreciation and amortization. Depreciation and amortization increased $0.5 million, or 11%, for the year
ended December 31, 2010 compared to the same period of 2009. This increase was primarily a result of normal capital
expenditure activity during the current year.
In summary, our natural gas services operating income decreased $0.2 million, or 5%, for the year ended
December 31, 2010 compared to the year ended December 31, 2009.
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Sulfur Services Segment
The following table summarizes our results of operations in our sulfur services segment.
Years Ended December 31,
2010
2009
(In thousands)
Revenues ...............................................................................................
Cost of products sold.............................................................................
Operating expenses ...............................................................................
Selling, general and administrative expenses........................................
Depreciation and amortization ..............................................................
Other operating income.........................................................................
Operating income...........................................................................
$ 165,078
122,483
17,013
3,422
6,262
15,898
(12)
$ 15,886
Sulfur (long tons) .................................................................................
Fertilizer (long tons) .............................................................................
Sulfur Services Volumes (long tons) ...................................................
1,129.2
274.9
1,404.1
$ 79,631
43,748
17,113
3,449
6,151
9,170
405
$ 9,575
1,107.5
238.0
1,345.5
Revenues. Our sulfur services revenues increased $85.4 million, or 107%, for the year ended December 31,
2010 compared to the year ended December 31, 2009. This increase was a result of higher market prices in 2010
compared to 2009.
Cost of products sold. Our cost of products sold increased $78.8 million, or 180%, for the year ended
December 31, 2010 compared to the year ended December 31, 2009. This increase was directly related to the increased
price of our raw materials in 2010 compared to 2009. Our overall gross margin per ton increased from $26.66 in 2009
to $30.34 in 2010.
Operating expenses. Our operating expenses decreased $0.1 million, or 1%, for the year ended December 31,
2010 compared to the year ended December 31, 2009. This decrease was a result of decreased costs relating to fuel
prices for marine transportation of our sulfur products.
Selling, general, and administrative expenses. Our selling, general, and administrative expenses increased less
than $0.1 million, or 1%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.
Depreciation and amortization. Depreciation and amortization increased $0.1 million, or 2%, for the year
ended December 31, 2010 compared to the year ended December 31, 2009. This increase was primarily a result of
normal capital expenditure activity during the current year.
In summary, our sulfur services operating income increased $6.3 million, or 66%, for the year ended December
31, 2010 compared to the year ended December 31, 2009.
Marine Transportation Segment
The following table summarizes our results of operations in our marine transportation segment.
Years Ended December 31,
2010
2009
(In thousands)
Revenues............................................................................................ $ 82,635
57,642
Operating expenses ............................................................................
2,296
Selling, general and administrative expenses.....................................
12,721
Depreciation and amortization ...........................................................
9,976
16
Other operating income......................................................................
Operating income ........................................................................... $ 9,992
$ 72,103
52,335
962
13,111
5,695
116
$ 5,811
Revenues. Our marine transportation revenues increased $10.5 million, or 15%, for the year ended December 31,
2010 compared to the year ended December 31, 2009. Our offshore revenues increased $7.7 million primarily due to
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increased utilization of the offshore fleet in 2010. Our inland marine operations increased $2.8 million primarily due to an
increase in inland freight revenue of $1.5 million. This increase was primarily a result of an increased utilization of the
inland fleet, which was offset by decreased day rates in 2010. The remaining $1.3 million increase was due to an increase
in ancillary revenues which consisted primarily of fuel and tankerman services.
Operating expenses. Operating expenses increased $5.3 million, or 10%, for the year ended December 31, 2010
compared to the year ended December 31, 2009. This was primarily a result of an increase in barge leases of $4.6 million
and an increase in wages and burden costs of $1.1 million. These increases were offset by a decrease in repairs and
maintenance expenses of $0.7 million.
Selling, general and administrative expenses. Selling, general and administrative expenses increased $1.3
million, or 139% for the year ended December 31, 2010 compared to the year ended December 31, 2009. This increase
was primarily a result of bad debt in 2010.
Depreciation and amortization. Depreciation and amortization decreased $0.4 million, or 3%, for the year ended
December 31, 2010 compared to the year ended December 31, 2009. This decrease was primarily a result of equipment
disposals offset by capital expenditures made in the last 12 months.
Other operating income. Other operating income for the year ended December 31, 2010 and the year ended
December 31, 2009 consisted of gains and losses on the disposal of assets.
In summary, our marine transportation operating income increased $4.2 million, or 72%, for the year ended
December 31, 2010 compared to the year ended December 31, 2009.
Equity in Earnings of Unconsolidated Entities
For the years ended December 31, 2010 and 2009, equity in earnings of unconsolidated entities relates to our
unconsolidated interests in Waskom Gas Processing Company (“Waskom”), Matagorda, PIPE and BCP. With respect to
BCP, the lease contract terminated in June 2009, and, as such, the investment was fully amortized as of June 30, 2009.
Equity in earnings of unconsolidated entities was $9.8 million for the year ended December 31, 2010,
compared to $7.0 million for the year ended December 31, 2009, an increase of $2.8 million. This increase is a result of
several factors including the acquisition by Waskom Midstream LLC of the Harrison Gathering system on January 1,
2010 and the Waskom plant and fractionator expansion completed at the end of the second quarter of 2009.
Interest Expense
Our interest expense for all operations was $33.8 million for 2010 compared to $19.0 million for 2009, an
increase of $14.8 million, or 78%. This increase was primarily due to an increase in average debt outstanding and an
increase in the average interest rates paid on the indebtedness throughout 2010 compared to 2009.
Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses were $6.4 million for 2010 compared to $6.1 million for
2009, an increase of $0.3 million or 5%.
Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses
for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering,
general office expense and employee benefit plans and other general corporate overhead functions we share with Martin
Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource
Management personnel that provide such centralized services. Generally accepted accounting principles also permit other
methods for allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a
segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of
judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in
the past or in the future, is or will be the most accurate or appropriate method of allocation these expenses. Other methods
could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income.
In addition to the direct expenses, under the omnibus agreement, we are required to reimburse Martin Resource
Management for indirect general and administrative and corporate overhead expenses. For the years ended December
31, 2010 and 2009, the Conflicts Committee of our general partner approved reimbursement amounts of $3.8 and $3.5
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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, 2009 Compared to the Year Ended December 31, 2008
Our total revenues before eliminations were $670.2 million for the year ended December 31, 2009
compared to $1,255.4 million for the year ended December 31, 2008, a decrease of $585.2 million, or 47%. Our operating
income before eliminations was $34.4 million for the year ended December 31, 2009 compared to $52.4 million for the
year ended December 31, 2008, a decrease of $18.0 million, or 34%.
The results of operations are described in greater detail on a segment basis below.
Terminalling and Storage Segment
The following table summarizes our results of operations in our terminalling and storage segment.
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 ................................................................................
Years Ended December 31,
2009
2008
(In thousands)
$ 73,885
35,628
109,513
31,331
45,783
1,955
15,717
14,727
5,504
$ 20,231
$ 72,604
50,356
122,960
42,721
50,001
2,243
12,947
15,048
(14)
$ 15,034
Revenues. Our terminalling and storage revenues decreased $13.4 million, or 11%, for the year ended
December 31, 2009 compared to the year ended December 31, 2008. Service revenue accounted for a $1.3 million
increase offset by a $14.7 million decrease in lubricant product sales. The service revenue increase was primarily a result
of new agreements entered into in 2008 and 2009, including a new lubricant terminalling fee of $5.3 million. This service
revenue increase was offset by decreased activity at our terminals of $2.4 million, decreased revenues from the Cross
assets of $1.2 million, and lost revenues due to the sale of our Mont Belvieu terminal of $0.4 million. Of the $14.7 million
lubricant product sales decrease, $12.6 million was due to the sale of our traditional lubricants business, including
inventory, to Martin Resource Management in April 2009 in return for a service fee for lubricant volumes moved through
our terminals. The remaining $2.1 million decrease is due to a 13% decrease in average selling price offset by a 7%
increase in sales volumes at our Mega Lubricant facility.
Cost of products sold. Our cost of products sold decreased $11.4 million, or 27% for the year ended
December 31, 2009 compared to the year ended December 31, 2008. This decrease was primarily due to the sale of our
traditional lubricants business, including inventory to Martin Resource Management in April 2009 in return for a service
fee for lubricant volumes moved through our terminals.
Operating expenses. Operating expenses decreased $4.2 million, or 8%, for the year ended December
31, 2009 compared to the year ended December 31, 2008. This decrease was a result of a $3.2 million decrease from
the Cross assets, a $1.1 million decreases in hurricane expenses that were recorded in 2008, and a decrease in utility cost
of $0.5 million. These decreases were offset by an increase in salaries and burden of $0.3 million and product hauling
costs of $0.3 million.
Selling, general and administrative expenses. Selling, general & administrative expenses decreased
$0.3 million, or 13% for the year ended December 31, 2009 compared to the year ended December 31, 2008. This
decrease was primarily due to the Cross assets.
Depreciation and amortization. Depreciation and amortization increased $2.8 million, or 21%, for the
year ended December 31, 2009 compared to the year ended December 31, 2008. This increase was primarily a result of
our recent acquisitions and capital expenditures.
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primarily of a gain on the sale of our Mont Belvieu terminal on April 30, 2009.
Other operating income (loss). Other operating income for the year ended December 31, 2009 consisted
In summary, terminalling and storage operating income increased $5.2 million, or 35%, for the years
ended December 31, 2009 and 2008.
Natural Gas Services Segment
The following table summarizes our results of operations in our natural gas services segment.
Years Ended December 31,
2009
2008
(In thousands)
$384,124
20,334
$615,966
59,346
Revenues:
NGLs..................................................................................................
Natural gas .........................................................................................
Non-cash mark to market and impairment adjustments of
commodity derivatives.......................................................................
Gain (loss) on cash settlements of commodity derivatives ................
Other operating fees ..........................................................................
Total revenues..............................................................................
Cost of products sold:
NGLs .................................................................................................
Natural gas ........................................................................................
Total cost of products sold ...........................................................
Operating expenses .................................................................................
Selling, general and administrative expenses..........................................
Depreciation and amortization ................................................................
Other operating income ..........................................................................
Operating income ................................................................................
(2,490)
3,273
3,748
408,989
364,350
19,261
383,611
8,627
7,332
4,527
4,892
(12)
$ 4,880
NGLs Volumes (Bbls) ...........................................................................
Natural Gas Volumes (Mmbtu) ..............................................................
9,880
6,155
*Information above does not include activities relating to Waskom, PIPE,
Matagorda and BCP investments
4,930
(3,932)
3,065
679,375
599,835
58,771
658,606
8,633
5,292
4,067
2,777
3
$ 2,780
8,794
7,267
Equity in Earnings of Unconsolidated Entities .......................................
$ 7,044
$ 13,224
Waskom:
Plant Inlet Volumes (MMcfd) ................................................................
Frac Volumes (Bbls/d) ...........................................................................
243
10,034
257
10,542
Revenues. Our natural gas services revenues decreased $270.4 million, or 40% for the year ended December
31, 2009 compared to the year ended December 31, 2008 primarily due to lower commodity prices.
For the year ended December 31, 2009, NGL revenues decreased $231.8 million, or 38% and natural gas
revenues decreased $39.0 million, or 66%. During 2009, our NGL average sales price per barrel decreased $31.17 or
45% and our natural gas average sales price per Mmbtu decreased $4.86, or 60% compared to the same period in 2008.
NGL sales volumes for the year increased 12% and natural gas volumes decreased 15% compared to the same period of
2008. The increase in NGL volumes is primarily due to increased industrial demand experienced during 2009 and the
decrease in natural gas volumes is primarily due to the Waskom plant shutdown in second quarter 2009 and operational
issues on various producer’s gathering lines in fourth quarter 2009.
Our natural gas services segment utilizes derivative instruments to manage the risk of fluctuations in market
prices for its anticipated sales of natural gas, condensate and NGLs. This activity is referred to as price risk
management. For the year ended December 31, 2009, 54% of our total natural gas volumes and 35% of our total NGL
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volumes were hedged as compared to 58% and 33%, respectively in 2008. The impact of price risk management and
marketing activities increased total natural gas and NGL revenues $0.8 million for 2009 compared to an increase of $1.0
million in the same period of 2008.
Costs of product sold. Our cost of products decreased $275.0 million, or 42%, for the year ended December
31, 2009 compared to the same period in 2008. Of the decrease, $235.5 million relates to NGLs and $39.5 million
relates to natural gas. The percentage decrease in NGL cost of products sold is greater than our percentage decrease in
NGL revenues as our NGL per barrel margins increased $0.17, or 9%. The percentage decrease relating to natural gas
cost of products sold is greater than the percentage decrease in natural gas revenues which caused our Mmbtu margins
to increase by 121%. This is primarily a result of revisions to the terms of certain producer contracts.
Operating expenses. Operating expenses remained consistent for the years ended December 31, 2009 and
2008.
Selling, general and administrative expenses. Selling, general and administrative expenses increased $2.0
million, or 39%, for the year ended December 31, 2009 compared to the same period of 2008. This increase was
primarily a result of increased salary expenses due to increased headcount and compensation increases of $1.6 million
and an increase in expense related to uncollectible accounts receivable of $0.4 million.
Depreciation and amortization. Depreciation and amortization increased $0.5 million, or 11%, for the year
ended December 31, 2009 compared to the same period of 2008. This increase was primarily a result of normal capital
expenditure activity during the current year.
In summary, our natural gas services operating income increased $2.1 million, or 76%, for the year ended
December 31, 2009 compared to the year ended December 31, 2008.
Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $7.0 million
and $13.2 million for the year ended December 31, 2009 and 2008, respectively, a decrease of 47%. This decrease is a
result of several factors including significantly lower commodity prices and the Waskom plant shutdown during the
second quarter of 2009 which contributed to our inlet volumes decreasing 5% and our fractionation volumes decreasing
5% for the year ended December 31, 2009 compared to the same period of 2008.
Sulfur Services Segment
The following table summarizes our results of operations in our sulfur services segment.
Revenues ...............................................................................................
Cost of products sold.............................................................................
Operating expenses ...............................................................................
Selling, general and administrative expenses........................................
Depreciation and amortization ..............................................................
Other operating income.........................................................................
Operating income...........................................................................
Years Ended December 31,
2009
2008
(In thousands)
$ 79,631
43,748
17,113
3,449
6,151
9,170
405
$ 9,575
$372,987
314,001
17,963
3,382
5,751
31,890
66
$ 31,956
Sulfur (long tons) .................................................................................
Fertilizer (long tons) .............................................................................
Sulfur Services Volumes (long tons) ...................................................
1,107.4
238.0
1,345.4
1,094.3
227.6
1,321.9
Revenues. Our sulfur services revenues decreased $293.4 million, or 79%, for the year ended December 31,
2009 compared to the year ended December 31, 2008. This decrease was a result of lower market prices in 2009
compared to 2008 while volumes remained relatively constant.
Cost of products sold. Our cost of products sold decreased $270.3 million, or 86%, for the year ended
December 31, 2009 compared to the year ended December 31, 2008. This decrease was directly related to the
decreased price of our raw materials in 2009 compared to 2008. Our overall gross margin per ton decreased from
$44.62 in 2008 to $26.66 in 2009. This is related to commodity prices being extremely high in 2008 compared to a more
normalized year like 2009.
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Operating expenses. Our operating expenses decreased $0.9 million, or 5%, for the year ended December 31,
2009 compared to the year ended December 31, 2008. This decrease was a result of decreased costs relating to fuel
prices for marine transportation of our sulfur products.
Selling, general, and administrative expenses. Our selling, general, and administrative expenses increased less
than $0.1 million, or 2%, for the year ended December 31, 2009 compared to the year ended December 31, 2008.
Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 7%, for the year
ended December 31, 2009 compared to the year ended December 31, 2008. This is attributable to a new sulfur priller at
our Neches facility that came online in the first quarter of 2009.
In summary, our sulfur services operating income decreased $22.4 million, or 70%, for the year ended December
31, 2009 compared to the year ended December 31, 2008.
Marine Transportation Segment
The following table summarizes our results of operations in our marine transportation segment.
Years Ended December 31,
2009
2008
(In thousands)
Revenues............................................................................................ $ 72,103
52,335
Operating expenses ............................................................................
962
Selling, general and administrative expenses.....................................
13,111
Depreciation and amortization ...........................................................
5,695
Other operating income......................................................................
116
Operating income ........................................................................... $ 5,811
$ 80,059
57,346
2,635
12,128
7,950
154
$ 8,104
Revenues. Our marine transportation revenues decreased $8.0 million, or 10%, for the year ended December 31,
2009 compared to the year ended December 31, 2008. Our inland marine revenues declined $6.9 million primarily due to
decreases in ancillary charges of $4.8 million and a $2.1 million decrease due to reduced charter contract rates. Our
offshore revenue decreased $1.1 million primarily from reduction in offshore fleet utilization.
Operating expenses. Operating expenses decreased $5.0 million, or 9%, for the year ended December 31, 2009
compared to the year ended December 31, 2008. This was primarily a result of a decrease in fuel costs of $5.3 million and
outside charter expenses of $2.1 million. These decreases were offset by increases in repair and maintenance of $1.0
million, wage and burden cost of $0.8 million and other operating expenses, including insurance premiums, of $0.6
million.
Selling, general and administrative expenses. Selling, general & administrative expenses decreased $1.7 million,
or 63% for the year ended December 31, 2009 compared to the year ended December 31, 2008. This decrease was
primarily a result of a reduction of bad debt expense in 2009.
Depreciation and amortization. Depreciation and amortization increased $1.0 million, or 8%, for the year ended
December 31, 2009 compared to the year ended December 31, 2008. This increase was the result of capital expenditures
made in the last 12 months.
Other operating income. Other operating income remained relatively flat for the year ended December 31,
2009 compared to the year ended December 31, 2008. In 2009, there were fewer gains recorded on the sale of property
and equipment than in 2008.
ended December 31, 2009 compared to the year ended December 31, 2008.
In summary, our marine transportation operating income decreased $2.3 million, or 28%, for the year
Equity in Earnings of Unconsolidated Entities
For the years ended December 31, 2009 and 2008, equity in earnings of unconsolidated entities relates to
our unconsolidated interests in Waskom Gas Processing Company (“Waskom”), Matagorda, PIPE and BCP. With respect
to BCP, the lease contract terminated in June 2009, and, as such, the investment was fully amortized as of June 20, 2009.
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Equity in earnings of unconsolidated entities was $7.0 million for the year ended December 31, 2009,
compared to $13.2 million for the year ended December 31, 2008, a decrease of $6.2 million. This decrease is a result
of several factors including significantly lower commodity prices and the Waskom plant shutdown during the second
quarter of 2009 which contributed to our inlet volumes decreasing 5% and our fractionation volumes decreasing 5% for
the year ended December 31, 2009 compared to the same period of 2008.
Interest Expense
Our interest expense for all operations was $19.0 million for 2009 compared to $21.4 million for 2008, a
decrease of $2.4 million, or 11%. This decrease was primarily due to a decrease in average debt outstanding and a
decrease in interest rates throughout 2009 compared to 2008. Also, we had interest swap cash settlements of $7.9 million
which increased interest expense in 2009.
Indirect Selling, General and Administrative Expenses
million for 2008, an increase of $0.6 million or 11%.
Indirect selling, general and administrative expenses were $6.1 million for 2009 compared to $5.5
Martin Resource Management allocated to us a portion of its indirect selling, general and administrative
expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance,
engineering, general office expense and employee benefit plans and other general corporate overhead functions we share
with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin
Resource Management personnel that provide such centralized services. Generally accepted accounting principles also
permit other methods for allocation of these expenses, such as basing the allocation on the percentage of revenues
contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a
number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of
allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocation these expenses.
Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce
our net income.
In addition to the direct expenses, under the omnibus agreement, we are required to reimburse Martin
Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended
December 31, 2009 and 2008, the Conflicts Committee of our general partner approved reimbursement amounts of $3.5
and $2.9 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and
approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.
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 the year ended December 31, 2010, we completed several transactions that have improved our liquidity
position. We received net proceeds of $197.2 million from a private placement of senior notes and $50.5 million from a
public offering of common units. We received net proceeds of $28.1 million from a public offering of common units
which did not improve our liquidity position as we redeemed common units owned by Martin Resource Management.
Additionally, we made certain strategic amendments to our 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
Effective March 26, 2010, our credit facility was amended to (i) decrease the size of our aggregate facility
from $350.0 million to $275.0 million, (ii) convert all term loans to revolving loans, (iii) extend the maturity date from
November 9, 2012 to March 15, 2013, (iv) permit us to invest up to $40.0 million in our joint ventures, (v) eliminate the
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covenant that limits our ability to make capital expenditures, (vi) decrease the applicable interest rate margin on
committed revolver loans, (vii) limit our ability to make future acquisitions and (viii) adjust the financial covenants.
For a more detailed discussion regarding our credit facility, see “Description of Our Long-Term Debt—Credit Facility”
within this Item.
On March 26, 2010, we completed a private placement of $200.0 million in aggregate principal amount of
8.875% senior unsecured notes due 2018 (“2018 Notes”) to qualified institutional buyers under Rule 144A. We received
proceeds of approximately $197.2 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.
Pursuant to the terms of a registration rights agreement entered into in connection with the offering of the 2018
Notes, we filed an exchange offer registration statement with the SEC on September 16, 2010 with respect to an offer to
exchange the 2018 Notes for registered notes with substantially identical terms. The registration statement was declared
effective by the SEC and the exchange offer was completed in the fourth quarter of 2010.
For a more detailed discussion regarding our credit facility, see “Description of Our Long-Term Debt—
Senior Notes” within this Item.
Equity Offerings
On February 9, 2011, we completed a public offering of 1,874,500 common units, resulting in net proceeds of
$70.7 million after payment of underwriters’ discounts, commissions and offering expenses. Our general partner
contributed $1.5 million in cash to us in conjunction with the issuance of these units 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 1.0 million common units, representing limited partner
interests in us at a purchase price of $29.13 per common unit. We received 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.
On February 8, 2010, we completed a public offering of approximately 1.65 million common units,
representing limited partner interests in us at a purchase price of $32.35 per common unit. We received net proceeds of
approximately $50.5 million after payment of underwriters’ discounts, commissions and offering expenses. Our general
partner contributed $1.1 million in cash to us in conjunction with the issuance in order to maintain its 2% general
partner interest in us.
Due to the foregoing, we believe that cash generated from operations and our borrowing capacity under our
credit facility will be sufficient to meet our working capital requirements, anticipated maintenance capital expenditures
and scheduled debt payments in 2010.
Due to restrictions on liquidity within the capital markets and the existing litigation at Martin Resource
Management our ability to access the capital markets in the future may be constrained. Our near-term focus is to ensure
we have sufficient liquidity to fund our growth programs, while continuing the present distribution rate to our
unitholders. The uncertain economic environment and the existing litigation at Martin Resource Management has
created a challenging operating environment for us to maintain our liquidity and operating cash flows at levels
consistent with the recent past while maintaining the present distribution rate to our unitholders. We continue to
evaluate our liquidity and capital resources and we have and will continue to consider sales of non-essential assets and
other available options for additional liquidity. For example, in the second quarter of 2009 we sold the assets
comprising the Mont Belvieu railcar unloading facility to Enterprise Products Operating LLC. See Note 16 to our
Financial Statements — Gain on Disposal of Assets.
Within the constraints noted above, we intend to move forward with our commercially supported internal
growth projects. We may revise the timing and scope of other projects as necessary to adapt to existing economic,
capital market and litigation conditions affecting us.
Finally, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to
satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks.
For example, the impact of the uncertain economic environment may significantly affect our customers, including their
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ability to satisfy receivables to us on a timely basis. Please read “Item 1A. Risk Factors – Risks Related to Our
Business” for a discussion of such risks.
Cash Flows and Capital Expenditures
In 2010, cash increased $5.4 million as a result of $37.5 million provided by operating activities, $81.3 million
used in investing activities and $49.2 million provided by financing activities. In 2009, cash decreased $2.0 million as a
result of $47.6 million provided by operating activities, $14.7 million used in investing activities and $34.9 million used in
financing activities. In 2008, cash increased $3.9 million as a result of $86.3 million provided by operating activities,
$106.6 million used in investing activities and $24.2 million provided by financing activities.
For 2010, our investing activities of $81.3 million consisted primarily of capital expenditures, acquisitions,
proceeds from sale of property, insurance proceeds from involuntary conversion of property, plant and equipment, and
investments in and returns of investments from unconsolidated partnerships. Our investment in unconsolidated
partnerships helped to fund $1.2 million and $3.2 million in expansion capital expenditures made by these unconsolidated
entities for the fourth quarter and year ended December 31, 2010, respectively. For 2009, our investing activities of $14.7
million consisted primarily of capital expenditures, acquisitions, proceeds from sale of property, insurance proceeds from
involuntary conversion of property, plant and equipment, and investments in and returns of investments from
unconsolidated partnerships. Our investment in unconsolidated partnerships helped to fund $0.4 million and $3.8 million
in expansion capital expenditures made by these unconsolidated entities for the fourth quarter and year ended December
31, 2009, respectively. For 2008, our investing activities of $106.6 million consisted primarily of capital expenditures,
acquisitions, proceeds from sale of property, insurance proceeds from involuntary conversion of property, plant and
equipment, and investments in and returns of investments from unconsolidated partnerships. Our investment in
unconsolidated partnerships helped to fund $0.9 million and $5.2 million in expansion capital expenditures made by these
unconsolidated entities for the fourth quarter and year ended December 31, 2008, respectively.
For 2010, 2009 and 2008 our capital expenditures for property and equipment were $17.0 million, $44.1 million,
and $107.4 million, respectively.
As to each period:
•
•
•
In 2010, we spent $12.3 million for expansion and $4.7 million for maintenance (including $1.2 million
for maintenance in the fourth quarter of 2010). Our expansion capital expenditures were made in
connection with marine vessel conversions, construction projects associated with our terminalling and
sulfur services businesses. Our maintenance capital expenditures were primarily made in our terminalling
and sulfur services divisions for routine operating equipment improvements.
In 2009, we spent $36.5 million for expansion and $7.6 million for maintenance (including $0.9 million
for maintenance in the fourth quarter of 2009). Our expansion capital expenditures were made in
connection with marine vessel purchases and conversions, construction projects associated with our
terminalling and sulfur services businesses. Our maintenance capital expenditures were primarily made in
our marine transportation segment for routine dry dockings of our vessels pursuant to the United States
Coast Guard requirements.
In 2008, we spent $89.4 million for expansion and $18.0 million for maintenance (including $7.0 million
for maintenance in the fourth quarter of 2008). Our expansion capital expenditures were made in
connection with marine vessel purchases and conversions, construction projects associated with our
terminalling business. Our maintenance capital expenditures were primarily made in our marine
transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard
requirements and in our terminalling and sulfur services at our Neches facility, where $1.5 million in
maintenance capital expenditures was spent in connection with restoration of assets destroyed in
Hurricanes Gustav and Ike.
In 2010, 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 $503.9 million, cash distributions
paid to common and subordinated unitholders of $56.7 million, purchase of treasury units of $0.1 million and payments of
debt issuance costs of $7.5 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
and redemption of common units of $28.1 million.
In 2009, our financing activities consisted of payments of long-term debt under our credit facilities of $432.0
million and borrowings of long-term debt under our credit facilities of $433.7 million, cash distributions paid to common
and subordinated unitholders of $47.5 million, purchase of treasury units of $0.1 million and payments of debt issuance
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costs of $10.4 million. Additional financing activities consisted of $20.0 million in connection with a private equity
offering issuance of 714,285 common units to Martin Resource Management and contributions of $1.3 million from our
general partner to maintain its 2% general partner interest.
In November 2009, we acquired the Cross assets for total consideration of $44.9 million as a result of a non-cash
financing activity. As consideration for the contribution of the Cross assets, we issued 804,721 of our common units and
889,444 subordinated units to Martin Resource Management at a price of $27.96 and $25.16 per limited partner unit,
respectively. In connection with the contribution of the Cross assets, our general partner made a capital contribution of
$0.9 million to us in order to maintain its 2% general partner interest.
In 2008, our financing activities consisted of payments of long-term debt under our credit facilities of $257.2
million and borrowings of long-term debt under our credit facilities of $327.2 million, cash distributions paid to common
and subordinated unitholders of $45.7 million, purchase of treasury units of $0.1 million and payments of debt issuance
costs of $18 thousand.
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, 2010, we had $374.0 million of outstanding indebtedness, consisting of outstanding
borrowings of $197.5 million (net of unamortized discount) under our Senior Notes, $163.0 million under our revolving
credit facility, $7.3 million under a note payable to a bank, and $6.2 million under capital lease obligations. As of
December 31, 2010, we had $111.9 million of available borrowing capacity under our revolving credit facility.
Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31,
2010 is as follows (dollars in thousands):
Type of Obligation
Total
Obligation
Payment due by period
1-3
Years
Less than
One Year
3-5
Years
Due
Thereafter
Long-Term Debt...........................................
Revolving credit facility............................
Senior unsecured notes .............................
Note payable .............................................
Capital leases including current maturities
Non-competition agreements .......................
Throughput commitment
Purchase obligations.....................................
Operating leases ...........................................
Interest expense(1) .......................................
Revolving credit facility............................
Senior unsecured notes .............................
Note payable .............................................
Capital leases ............................................
$163,000
197,457
7,354
6,172
200
64,025
7,760
47,179
15,787
128,688
1,830
5,079
$ —
—
993
130
50
—
7,760
9,690
7,167
17,750
519
972
$163,000
—
2,219
384
100
8,865
—
18,983
$ —
—
2,576
601
50
12,347
—
9,977
$ —
197,457
1,566
5,057
—
42,813
—
8,529
8,620
35,500
800
1,868
—
35,500
442
1,715
—
39,938
69
524
Total contractual cash obligations
$644,531
$45,031
$240,339
$63,208
$295,953
(1) Interest commitments are estimated using our current interest rates for the respective credit agreements over their
remaining terms.
Letter of Credit. At December 31, 2010, 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.
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Description of Our Long-Term Debt
Senior Notes
In March 2010, 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 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 “Notes”). We completed the aforementioned 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.
In March 2010, we completed a private placement of $200.0 million in aggregate principal amount of the 2018
Notes to qualified institutional buyers under Rule 144A. We received proceeds of approximately $197.2 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. Pursuant to the terms of a registration rights
agreement entered into in connection with the offering of the 2018 Notes, we filed an exchange offer registration
statement with the SEC on September 16, 2010 with respect to an offer to exchange the 2018 Notes for registered notes
with substantially identical terms. The registration statement was declared effective by the SEC and the exchange offer
was completed in the fourth quarter of 2010.
Purchase Agreement.
Under the Purchase Agreement, the Issuers agreed to sell the Notes. The Notes were not registered under the
Securities Act of 1933, as amended (the “Securities Act”), or any state securities laws, and unless so registered, the
Notes may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not
subject to, the registration requirements of the Securities Act and applicable state securities laws. The Issuers offered
and issued the Notes only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to
persons outside the United States pursuant to Regulation S.
The Purchase Agreement contained customary representations and warranties of the parties and
indemnification and contribution provisions under which the Issuers and the Guarantors, on one hand, and the Initial
Purchasers, on the other, agreed to indemnify each other against certain liabilities, including liabilities under the
Securities Act. The Issuers also agreed not to issue certain debt securities for a period of 60 days after March 23, 2010
without the prior written consent of Wells Fargo Securities.
Indenture.
Interest and Maturity. On March 26, 2010, the Issuers issued the Notes pursuant to the Indenture in a
transaction exempt from registration requirements under the Securities Act. The Notes were resold to qualified
institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to
Regulation S under the Securities Act. The Notes will mature on April 1, 2018. The interest payment dates are April 1
and October 1, beginning on October 1, 2010.
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 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 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 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 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 twelve-month period beginning on April 1, 2015 and 100.00% for the twelve-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 Notes.
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Certain Covenants. The Indenture restricts our 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 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 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 Notes; (ii) default in payment when due of the principal of, or premium,
if any, on the Notes; (iii) our failure to comply with certain covenants relating to asset sales, repurchases of the 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 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 Notes, by
notice to the Issuers and the Trustee, may declare the 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 Notes to become due and payable.
Credit Facility
On November 10, 2005, we entered into a $225.0 million multi-bank credit facility comprised of a $130.0 million
term loan facility and a $95.0 million revolving credit facility, which included a $20.0 million letter of credit sub-limit.
Effective September 30, 2006, we increased our revolving credit facility by $25.0 million, resulting in a committed $120.0
million revolving credit facility. Effective December 28, 2007, we increased our revolving credit facility by $75.0 million,
resulting in a committed $195.0 million revolving credit facility. Effective December 21, 2009, (i) we increased our
revolving credit facility by approximately $72.7 million, resulting in a committed $267.8 million revolving credit facility
and (ii) decreased our term loan facility by approximately $62.1 million, resulting in a $67.9 million term loan facility.
Effective January 14, 2010, we modified our revolving credit facility to (i) permit investment up to $25.0 million in joint
ventures and (ii) limit our ability to make capital expenditures. Effective February 25, 2010, we increased the maximum
amount of borrowings and letters of credit available under our credit facility from approximately $335.7 million to $350.0
million. Effective March 26, 2010, our credit facility was amended to (i) decrease the size of our aggregate facility from
$350.0 million to $275.0 million, (ii) convert all term loans to revolving loans, (iii) extend the maturity date from
November 9, 2012 to March 15, 2013, (iv) permit us to invest up to $40 million in our joint ventures, (v) eliminate the
covenant that limits our ability to make capital expenditures, (vi) decrease the applicable interest rate margin on committed
revolver loans, (vii) limit our ability to make future acquisitions and (viii) adjust the financial covenants.
As of December 31, 2010, we had approximately $163.0 million outstanding under the revolving credit facility
and $0.1 million of letters of credit issued, leaving approximately $111.9 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 $80.0 million to a high of $324.5 million.
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The credit facility is guaranteed by substantially all of our subsidiaries. Obligations under the credit facility are
secured by first priority liens on substantially all of our assets and those of the guarantors, including, without limitation,
inventory, accounts receivable, bank accounts, marine vessels, equipment, fixed assets and the interests in our subsidiaries
and certain of our equity method investees.
We may prepay all amounts outstanding under the credit facility at any time without premium or penalty (other
than customary LIBOR breakage costs), subject to certain notice requirements. The credit facility requires mandatory
prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, equity issuances and debt
incurrences. Prepayments as a result of asset sales and debt incurrences require a mandatory reduction of the lenders’
commitments under the credit facility equal to 25% of the corresponding mandatory prepayment, but in no event will such
prepayments cause the lenders’ commitments under the credit facility to be less than $250.0 million. Prepayments as a
result of equity issuances do not require any reduction of the lenders’ commitments under the credit facility.
Indebtedness under the credit facility bears interest, at our option, at the Eurodollar Rate (the British Bankers
Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%,
the 30-day Eurodollar Rate plus 1.0%, or the administrative 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 of 0.50% per annum on the
unused revolving credit availability under the credit facility. The letter of credit fee and the applicable margins for our
interest rate vary quarterly based on our leverage ratio (as defined in the new credit facility, being generally computed as
the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other
non-cash charges) and are as follows:
Leverage Ratio
Less than 2.75 to 1.00..................................................................................
Greater than or equal to 2.75 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 ...........................................................
Base Rate
Loans
2.00%
2.25%
2.50%
3.00%
3.25%
Eurodollar Rate
Loans
3.00%
3.25%
3.50%
4.00%
4.25%
Letter of Credit
Fees
3.00%
3.25%
3.50%
4.00%
4.25%
As of December 31, 2010, based on our leverage ratio the applicable margin for existing Eurodollar Rate
borrowings is 4.00%. Effective January 1, 2011, based on our leverage ratio as of September 30, 2010, the applicable
margin for Eurodollar Rate borrowings will remain at 4.00% until the next quarterly determination of our leverage ratio.
The credit facility does not have a floor for the Base Rate or the Eurodollar Rate.
The credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-
quarter period that ends on the last day of each fiscal quarter. Prior to our or any of our subsidiaries’ issuance of $100.0
million or more of unsecured indebtedness, the maximum permitted leverage ratio is 4.00 to 1.00. After our or any of
our subsidiaries’ issuance of $100.0 million or more of unsecured indebtedness, the maximum permitted leverage ratio
is 4.50 to 1.00. After our or any of our subsidiaries’ issuance of $100.0 million or more of unsecured indebtedness, the
maximum permitted senior leverage ratio (as defined in the new credit facility, but generally computed as the ratio of
total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other
non-cash charges) is 2.75 to 1.00. The minimum consolidated interest coverage ratio (as defined in the new credit
facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization
and certain other non-cash charges to consolidated interest charges) is 3.00 to 1.00.
In addition, the credit facility contains various covenants that, among other restrictions, limit our and our
subsidiaries’ ability to:
•
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;
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•
•
•
change the nature of our business;
engage in transactions with affiliates.
enter into certain burdensome agreements;
• make certain amendments to the omnibus agreement and our material agreements;
• make capital expenditures; and
•
permit our joint ventures to incur indebtedness or grant certain liens.
Each of the following will be an event of default under the credit facility:
•
•
•
•
•
•
•
•
•
•
•
failure to pay any principal, interest, fees, expenses or other amounts when due;
failure to meet the quarterly financial covenants;
failure to observe any other agreement, obligation, or covenant in the credit facility or any related loan
document, subject to cure periods for certain failures;
the failure of any representation or warranty to be materially true and correct when made;
our or any of our subsidiaries’ default under other indebtedness that exceeds a threshold amount;
bankruptcy or other insolvency events involving us or any of our subsidiaries;
judgments against us or any of our subsidiaries, in excess of a threshold amount;
certain ERISA events involving us or any of our subsidiaries, in excess of a threshold amount;
a change in control (as defined in the credit facility);
the termination of any material agreement or certain other events with respect to material agreements;
the invalidity of any of the loan documents or the failure of any of the collateral documents to create a lien
on the collateral; 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 there under immediately due and payable. In addition, either a bankruptcy event with respect to Martin
Resource Management or a judgment with respect to Martin Resource Management could independently result in an event
of default under our credit facility if it is deemed to have a material adverse effect on us.
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 1, 2011, our outstanding indebtedness includes $135 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.
- 71 -
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 is the applicable three-month LIBOR rate. This interest rate swap is not accounted for
using hedge accounting and matures in April 2018.
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 is the applicable three-month LIBOR rate. This interest rate swap is not accounted for
using hedge accounting and matures in April 2018.
Effective October 2008, we entered into an interest rate swap that swapped $40.0 million of floating rate to
fixed rate. The fixed rate cost was 2.820% plus our applicable LIBOR borrowing spread. Effective April 2009, we
entered into two subsequent swaps to lower our effective fixed rate to 2.580% plus our applicable LIBOR borrowing
spread. The original swap and the first subsequent swap were accounted for using mark-to-market accounting. The
second subsequent swap was accounted for using hedge accounting. Each of the swaps were scheduled to mature in
October 2010, but were terminated in March 2010.
Effective January 2008, we entered into an interest rate swap that swapped $25.0 million of floating rate to fixed
rate. The fixed rate cost was 3.400% plus our applicable LIBOR borrowing spread. Effective April 2009, we entered into
two subsequent swaps to lower our effective fixed rate to 3.050% plus our applicable LIBOR borrowing spread. The
original swap and the first subsequent swap were accounted for using mark-to-market accounting. The second subsequent
swap was accounted for using hedge accounting. Each of the swaps matured in January 2010.
Effective September 2007, we entered into an interest rate swap that swapped $25.0 million of floating rate to
fixed rate. The fixed rate cost was 4.605% plus our applicable LIBOR borrowing spread. Effective March 2009, we entered
into two subsequent swaps to lower our effective fixed rate to 4.305% plus our applicable LIBOR borrowing spread. The
original swap and the first subsequent swap were accounted for using mark-to-market accounting. The second subsequent
swap was accounted for using hedge accounting. Each of the swaps were scheduled to mature in September 2010, but were
terminated in March 2010.
Effective November 2006, we entered into an interest rate swap that swapped $30.0 million of floating rate to
fixed rate. The fixed rate cost was 4.765% plus our applicable LIBOR borrowing spread. This interest rate swap, which
matured in March 2010, was not accounted for using hedge accounting.
Effective March 2006, we entered into an interest rate swap that swapped $75.0 million of floating rate to fixed
rate. The fixed rate cost was 5.25% plus our applicable LIBOR borrowing spread. Effective February 2009, we entered into
two subsequent swaps to lower our effective fixed rate to 5.10% plus our applicable LIBOR borrowing spread. The
original swap and the first subsequent swap were accounted for using mark-to-market accounting. The second subsequent
swap was accounted for using hedge accounting. Each of the swaps were scheduled to mature in November 2010, but were
terminated in March 2010.
Seasonality
A substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and sulfur-
based fertilizer products, which fluctuate in part based on winter and spring weather conditions. The demand for NGLs is
strongest during the winter heating season. The demand for fertilizers is strongest during the early spring planting season.
However, our terminalling and storage and marine transportation businesses and the molten sulfur business are typically
not impacted by seasonal fluctuations. We expect to derive approximately half of our net income from our terminalling
and storage, marine transportation, natural gas and sulfur businesses. Therefore, we do not expect that our overall net
income will be impacted by seasonality factors. However, extraordinary weather events, such as hurricanes, have in the
past, and could in the future, impact our terminalling and storage and marine transportation businesses. For example,
Hurricanes Gustav and Ike in the third quarter of 2008 and Hurricanes Katrina and Rita in the third quarter of 2005
adversely impacted our operating expenses and adversely impacted our terminalling and storage and marine transportation
business’s revenues.
Impact of Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our
results of operations in 2010, 2009 and 2008. However, inflation remains a factor in the United States economy and could
increase our cost to acquire or replace property, plant and equipment as well as our labor and supply costs. We cannot
assure our unitholders that we will be able to pass along increased costs to our customers.
- 72 -
Increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and
other supplies are recorded in operating expenses. An increase in price of these products would increase our operating
expenses which could adversely affect net income. We cannot assure our unitholders that we will be able to pass along
increased operating expenses to our customers.
Environmental Matters
Our operations are subject to environmental laws and regulations adopted by various governmental authorities in
the jurisdictions in which these operations are conducted. We incurred no significant environmental costs, liabilities or
expenditures to mitigate or eliminate environmental contamination during 2010, 2009 or 2008.
- 73 -
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market
risks associated with commodity prices, counterparty credit and interest rates. For the year ended December 31, 2010,
changes in the fair value of our derivative contracts were recorded both in earnings and accumulated other comprehensive
income (“AOCI”) since we have designated a portion of our derivative instruments as hedges as of December 31, 2010.
Commodity Price Risk
We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Under
our hedging policy, we monitor and manage the commodity market risk associated with the commodity risk exposure of
Prism Gas. In addition, we are focusing on utilizing counterparties for these transactions whose financial condition is
appropriate for the credit risk involved in each specific transaction.
We use derivatives to manage the risk of commodity price fluctuations. These outstanding contracts expose us
to credit loss in the event of nonperformance by the counterparties to the agreements. We have incurred no losses
associated with counterparty nonperformance on derivative contracts.
On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial
condition prior to entering into an agreement, establish a maximum credit limit threshold pursuant to our hedging
policy, and monitor the appropriateness of these limits on an ongoing basis. We have agreements with five
counterparties containing collateral provisions. Based on those current agreements, cash deposits are required to be
posted whenever the net fair value of derivatives associated with the individual counterparty exceed a specific threshold.
If this threshold is exceeded, cash is posted by us if the value of derivatives is a liability to us. As of December 31,
2010, we have no cash collateral deposits posted with counterparties.
We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a
result of gathering, processing and sales activities. Our exposure to these fluctuations is primarily in the gas processing
component of our business. Gathering and processing revenues are earned under various contractual arrangements with
gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements.
Processing revenues are generated primarily through contracts which provide for processing on percent-of-liquids and
percent-of-proceeds basis.
1) Percent-of-liquids contracts: Under these contracts, we receive a fee in the form of a percentage of
the NGLs recovered, and the producer bears all of the cost of natural gas shrink. Therefore, margins
increase during periods of high NGL prices and decrease during periods of low NGL prices.
2) Percent-of-proceeds contracts: Under these contracts, we generally gather and process natural gas on
behalf of certain producers, sell the resulting residue gas and NGLs at market prices and remit to
producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead
of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas
and NGLs to the producer and sell the volumes kept to third parties at market prices. Under these
types of contracts, revenues and gross margins increase as natural gas prices and NGL prices increase,
and revenues and gross margins decrease as natural gas and NGL prices decease.
Market risk associated with gas processing margins by contract type, and gathering and transportation margins
as a percent of total gross margin remained consistent for the years ended December 31, 2010 and 2009 as our contract
mix and volumes associated with those contracts did not differ materially.
The aggregate effect of a hypothetical $1.00/MMbtu increase or decrease in the natural gas price index would
result in an approximate annual gross margin change of $0.7 million. In addition, the aggregate effect of a hypothetical
$10.00/Bbl increase or decrease in the crude oil price index would result in an approximate annual gross margin change
of $0.9 million.
Prism Gas has entered into hedging transactions through 2012 to protect a portion of its commodity exposure
from these contracts. These hedging arrangements are in the form of swaps for crude oil, natural gas and natural
gasoline.
- 74 -
Based on estimated volumes, as of December 31, 2010, we had hedged approximately 37% and 10% of our
commodity risk by volume for 2011 and 2012, respectively. As of March 2, 2011, Prism Gas has hedged approximately
45% and 14% of its commodity risk by volume for 2011 and 2012, respectively.
We anticipate entering into additional commodity derivatives on an ongoing basis to manage our risks
associated with these market fluctuations and will consider using various commodity derivatives, including forward
contracts, swaps, collars, futures and options, although there is no assurance that we will be able to do so or that the
terms thereof will be similar to our existing hedging arrangements.
The relevant payment indices for our various commodity contracts are as follows:
• Natural gas contracts - monthly posting for ANR Pipeline Co. - Louisiana as posted in Platts Inside
FERC’s Gas Market Report;
• Crude oil contracts - WTI NYMEX average for the month of the daily closing prices; and
• Natural gasoline contracts - Mt. Belvieu Non-TET average monthly postings as reported by the Oil Price
Information Service (OPIS).
Derivative Contracts in Place
As of December 31, 2010
Period
January 2011-
December 2011
January 2011-
December 2011
January 2011-
December 2011
January 2011-
December 2011
January 2011-
December 2011
January 2012-
December 2012
January 2012-
December 2012
Underlying
Notional Volume
Commodity
Price
We Receive
Commodity
Price
We Pay
Fair Value
Asset
(In Thousands)
Fair Value
Liability
(In Thousands)
Natural Gas
120,000 (MMBTU)
Index
$6.1250/Mmbtu
$ 201
$ —
Natural Gas
240,000 (MMBTU)
Index
$4.3225/Mmbtu
Crude Oil
24,000 (BBL)
Index
$91.20/bbl
Natural Gasoline
24,000 (BBL)
Index
$87.10/bbl
Natural Gasoline
12,000 (BBL)
Index
$88.85/bbl
Crude Oil
24,000 (BBL)
Index
$88.63/bbl
Natural Gasoline
12,000 (BBL)
Index
$90.20/bbl
—
—
—
—
—
28
51
149
54
126
—
$ 201
44
$ 452
Our principal customers with respect to Prism Gas’ natural gas gathering and processing are large, natural gas
marketing services, oil and gas producers and industrial end-users. In addition, substantially all of our natural gas and
NGL sales are made at market-based prices. Our standard gas and NGL sales contracts contain adequate assurance
provisions which allows for the suspension of deliveries, cancellation of agreements or discontinuance of deliveries to
the buyer unless the buyer provides security for payment in a form satisfactory to us.
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 4.40% as of December 31, 2010. As of March 1, 2011, we had a total of $135.0 million of indebtedness
outstanding under our credit facility, all of which was unhedged floating rate debt. Based on the amount of unhedged
floating rate debt owed by us on December 31, 2010, the impact of a 1% increase in interest rates on this amount of debt
would result in an increase in interest expense and a corresponding decrease in net income of approximately $1.6 million
annually.
Historically, we have managed a portion of our interest rate risk on our revolving credit facility with interest rate
swaps, which reduced our exposure to changes in interest rates by converting variable interest rates to fixed interest rates.
During the first quarter 2010, we terminated all of our interest rate swaps on our revolving credit facility.
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 $216.4 million as of December 31, 2010, based on market
prices of similar debt at December 31, 2010. Market risk is estimated as the potential decrease in fair value of our long-
- 75 -
term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in
approximately a $10.7 million decrease in fair value of our long-term debt at December 31, 2010.
We have entered into interest rate swap agreements to reduce the amount of interest we pay on our Senior
Notes due in April 2018. Pursuant to the terms of these interest rate swap agreements, we pay a variable rate interest
payment based on the three-month LIBOR and receive a fixed rate. The net difference to be paid or received from the
counterparties under the interest rate swap agreement is settled quarterly and is recognized as an adjustment to interest
expense. The risk associated with these interest rate swaps exposes us to an increase in interest rates which would result
in an increase in interest expense and a corresponding decrease in net income.
At December 31, 2010, we are party to interest rate swap agreements as shown below:
Interest Rate Swaps
As of December 31, 2010
Date of Swap
Bank
Maturity
Notional
Amount
Interest Rate
We Pay
Interest
Rate
We Receive
Fair Value
Asset
Fair Value
Liability
(In Thousands) (In Thousands)
September 2010
SunTrust April 2018
$60,000
3 MO LIBOR
2.3150%
September 2010
RBS
April 2018
$40,000
3 MO LIBOR
2.3150%
$1,163
$2,362
778
$1,941
1,568
$3,930
- 76 -
Item 8. Financial Statements and Supplementary Data
The following financial statements of Martin Midstream Partners L.P. (Partnership):
Page
Report of Independent Registered Public Accounting Firm........................................................................................
78
Report of Independent Registered Public Accounting Firm........................................................................................
79
Consolidated Balance Sheets as of December 31, 2010 and 2009 ..............................................................................
80
Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008..............................
81
Consolidated Statements of Changes in Capital for the years ended December 31, 2010, 2009 and 2008.................
82
Consolidated Statements of Comprehensive Income for the years ended December 31, 2010, 2009 and 2008 .........
83
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008 ............................
84
Notes to the Consolidated Financial Statements .........................................................................................................
85
- 77 -
Report of Independent Registered Public Accounting Firm
The Board of Directors
Martin Midstream GP LLC:
We have audited the accompanying consolidated balance sheets of Martin Midstream Partners L.P. and
subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in capital,
comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2010. 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
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
consolidated financial position of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2010 and 2009 and
the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010,
in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December
31, 2010, 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 2, 2011 expressed an unqualified
opinion on the effectiveness of Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting.
/s/ KPMG LLP
Shreveport, Louisiana
March 2, 2011
- 78 -
Report of Independent Registered Public Accounting Firm
The Board of Directors
Martin Midstream GP LLC:
We have audited Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31,
2010, 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 (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our opinion.
A 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, 2010, based on criteria established in Internal Control – Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2010 and 2009, and the related
consolidated statements of operations, changes in capital, comprehensive income, and cash flows for each of the years in the three-year
period ended December 31, 2010, and our report dated March 2, 2011 expressed an unqualified opinion on those consolidated financial
statements.
/s/ KPMG LLP
Shreveport, Louisiana
March 2, 2011
- 79 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
Assets
Cash...........................................................................................................
Accounts and other receivables, less allowance for doubtful accounts of
$2,528 and $481, respectively ............................................................
Product exchange receivables ...................................................................
Inventories.................................................................................................
Due from affiliates ....................................................................................
Fair value of derivatives............................................................................
Other current assets ...................................................................................
Total current assets .............................................................................
December 31,
2010
2009
(Dollars in thousands)
$ 11,380
$ 5,956
95,276
9,099
52,616
6,437
2,142
2,784
179,734
77,413
4,132
35,510
3,051
1,872
1,340
129,274
Property, plant and equipment, at cost ......................................................
Accumulated depreciation.........................................................................
Property, plant and equipment, net .....................................................
632,456
(200,276)
432,180
584,036
(162,121)
421,915
Goodwill....................................................................................................
Investment in unconsolidated entities .......................................................
Debt issuance costs, net.............................................................................
Other assets ...............................................................................................
Liabilities and Partners’ Capital
Current installments 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 ............................................................................
Total current liabilities........................................................................
Long-term debt and capital leases, less current maturities........................
Deferred income taxes...............................................................................
Fair value of derivatives............................................................................
Other long-term obligations ......................................................................
Total liabilities....................................................................................
Partners’ capital.........................................................................................
Accumulated other comprehensive loss....................................................
Total partners’ capital .........................................................................
Commitments and contingencies ..............................................................
See accompanying notes to consolidated financial statements.
37,268
98,217
13,497
24,582
$785,478
$ 1,121
82,837
22,353
6,957
811
282
10,034
124,395
372,862
8,213
4,100
1,102
510,672
273,387
1,419
274,806
37,268
80,582
10,780
6,120
$685,939
$ 111
71,911
7,986
13,810
454
7,227
5,000
106,499
304,372
8,628
—
1,489
420,988
267,027
(2,076)
264,951
$785,478
$685,939
- 80 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
2010
2008
2009
(Dollars in thousands, except per unit
amounts)
Revenues:
Terminalling and storage * .........................................................................
Marine transportation *...............................................................................
$ 67,117
77,642
$ 69,710
68,480
$ 68,552
76,349
Product sales: *
Natural gas services .............................................................................
Sulfur services .....................................................................................
Terminalling and storage .....................................................................
Total revenues......................................................................................
554,482
165,078
47,799
767,359
912,118
408,982
79,629
35,584
524,195
662,385
679,375
371,949
50,219
1,101,543
1,246,444
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 .......................................................................................
Operating income.................................................................................
527,232
122,121
44,549
693,902
116,402
21,118
40,656
872,078
136
40,176
382,542
43,386
31,331
457,259
117,438
19,775
39,506
633,978
6,013
34,420
Other income (expense):
Equity in earnings of unconsolidated entities ..............................................
Interest expense ...........................................................................................
Other, net
Total other income (expense)...............................................................
9,792
(33,716)
287
(23,637)
7,044
(18,995)
326
(11,625)
Net income before taxes ..............................................................................
Income tax benefit (expense)...............................................................................
Net income ..........................................................................................................
16,539
(517)
$ 16,022
22,795
(592)
$ 22,203
657,662
313,143
42,721
1,013,526
126,808
19,062
34,893
1,194,289
209
52,364
13,224
(21,433)
801
(7,408)
44,956
(1,398)
$ 43,558
General partner’s interest in net income1 .............................................................
Limited partners’ interest in net income1 .............................................................
$ 3,869
$ 3,249
$ 3,301
$ 11,045
$ 17,179
$ 39,509
Net income per limited partner unit - basic and diluted .......................................
Weighted average limited partner units - basic....................................................
Weighted average limited partner units - diluted .................................................
$ 0.63
17,525,089
17,525,989
$ 1.17
14,680,807
14,684,775
$ 2.72
14,529,826
14,534,722
¹ General and limited partner’s interest in net income includes net income of the Cross assets since the date of the acquisition.
See accompanying notes to consolidated financial statements.
*Related Party Transactions Included Above
Revenues:
Terminalling and storage ..........................................................................
Marine transportation................................................................................
Product Sales ............................................................................................
$ 46,823
28,194
14,998
$ 19,998
19,370
5,838
$18,362
24,956
26,704
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services ..........................................................................
Sulfur services ..................................................................................
79,321
16,061
56,914
12,583
92,322
13,282
Expenses:
Operating expenses ...........................................................................
Selling, general and administrative ..................................................
49,286
10,918
37,284
7,162
37,661
6,284
- 81 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL
For the years ended December 31, 2010, 2009 and 2008
Partners’ Capital
Parent Net
Investment
Common
Units
Amount
Subordinated
Units
(Dollars in thousands)
Amount
General
Partner
Amount
Accumulated
Comprehensive
Income
Amount
Total
Balances – December 31, 2007 ..............................
$ 10,917
12,837,480
$244,520
1,701,346
$ (6,022)
$ 4,112
$ (6,762)
$ 246,765
Net Income ...............................................................
748
Cash distributions ($2.91 per unit)..........................
Conversion of subordinated units to common units..
Unit-based compensation .........................................
Purchase of treasury units.........................................
—
—
—
—
—
34,978
(37,357)
—
—
4,531
3,301
(4,951)
(3,409)
850,672
(2,754)
(850,672)
2,754
3,000
(3,000)
39
(93)
—
—
—
—
—
—
—
—
—
—
—
—
43,558
(45,717)
—
39
(93)
Adjustment in fair value of derivatives....................
—
—
—
—
—
—
1,827
1,827
Balances – December 31, 2008 ................................
$ 11,665
13,688,152
$ 239,333
850,674
$ (3,688)
$ 4,004
$ (4,935)
$ 246,379
Net Income ...............................................................
1,664
General partner contribution ....................................
Units issued in connection with Cross acquisition....
Recognition of beneficial conversion feature .............
Issuance of common units .........................................
Cash distributions ($3.00 per unit)..........................
Conversion of subordinated units to common units..
Unit-based compensation .........................................
Purchase of treasury units.........................................
—
—
—
—
—
—
—
Contributions to parent .............................................
(13,329)
—
—
16,310
—
—
—
980
—
3,249
1,324
804,721
16,523
889,444
16,434
—
(111)
714,285
20,000
—
(41,064)
—
—
—
111
—
(2,552)
(3,846)
—
—
—
850,674
(5,328)
(850,674)
5,328
3,000
(3,000)
—
98
(78)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
22,203
1,324
32,957
—
20,000
(47,462)
—
98
(78)
(13,329)
Adjustment in fair value of derivatives....................
—
—
—
—
—
—
2,859
2,859
Balances – December 31, 2009 ................................
$ —
16,057,832
$ 245,683
889,444
$ 16,613
$ 4,731
$ (2,076)
$ 264,951
Net Income ...............................................................
Recognition of beneficial conversion feature ..........
Follow-on public offerings.......................................
Redemption of common units ..................................
General partner contribution ....................................
Distributions to parent ..............................................
Cash distributions ($3.00 per unit)..........................
Unit-based compensation .........................................
Purchase of treasury units.........................................
—
—
—
—
—
—
—
—
—
—
—
12,151
(1,108)
2,650,000
78,600
(1,000,000)
(28,070)
—
—
—
3,500
(3,500)
—
(4,590)
(51,886)
113
(108)
—
—
—
—
—
—
—
—
—
—
3,871
1,108
—
—
—
—
—
—
—
1,089
—
—
(4,810)
—
—
—
—
—
—
—
—
—
—
—
—
—
16,022
—
78,600
(28,070)
1,089
(4,590)
(56,696)
113
(108)
Adjustment in fair value of derivatives....................
—
—
—
—
—
—
3,495
3,495
Balances – December 31, 2010 ................................
$ —
17,707,832
$ 250,785
889,444
$ 17,721
$ 4,881
$ 1,419
$ 274,806
See accompanying notes to consolidated financial statements.
- 82 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
Net income ......................................................................................
Changes in fair values of commodity cash flow hedges .................
Commodity cash flow hedging (gains) losses reclassified to
2010
Year Ended December 31,
2009
(Dollars in thousands)
$ 22,203
14
$ 16,022
143
$ 43,558
4,219
2008
earnings....................................................................................
Changes in fair value of interest rate cash flow hedges...................
Interest rate cash flow hedging losses reclassified to earnings........
(617)
(241)
4,210
(2,646)
(1,854)
7,345
3,043
(5,435)
—
Comprehensive income............................................................
$ 19,517
$ 25,062
$ 45,385
See accompanying notes to consolidated financial statements.
- 83 -
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
2010
Year Ended December 31,
2009
(Dollars in thousands)
2008
Cash flows from operating activities:
Net income
$ 16,022
$ 22,203
$ 43,558
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 on disposition or sale of property, plant, and equipment..............................
Gain on involuntary conversion of property, plant, and equipment ......................
Equity in earnings of unconsolidated entities ........................................................
Distributions from unconsolidated entities..........................................................
Distribution in-kind from unconsolidated entities.................................................
Non-cash mark-to-market on derivatives ..............................................................
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 operating activities ................................................
Cash flows from investing activities:
Payments for property, plant, and equipment...............................................................
Acquisitions, net of cash acquired ................................................................................
Payments for plant turnaround costs ............................................................................
Proceeds from sale of property, plant, and equipment .................................................
Insurance proceeds from involuntary conversion of property, plant and
equipment...............................................................................................................
Investments in unconsolidated entities ............................................................................
Return of investments from unconsolidated entities .......................................................
(Contributions to) unconsolidated entities for operations ............................................
Net cash used in investing activities.......................................................
Cash flows from financing activities:
Payments of long-term debt ..........................................................................................
Proceeds from long-term debt ......................................................................................
Net proceeds from follow on public offering ...............................................................
General partner contribution .........................................................................................
Redemption of common units .......................................................................................
Contributions to parent..................................................................................................
Purchase of treasury units ............................................................................................
Proceeds from issuance of common units ....................................................................
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 ...................................................................................................
40,656
4,814
269
(415)
(136)
—
(9,792)
—
10,545
380
113
(17,863)
(4,967)
(17,106)
(3,386)
(1,444)
10,918
14,366
(6,853)
357
5,382
(4,342)
37,518
(17,907)
(46,352)
(1,090)
2,419
—
(20,110)
2,470
(748)
(81,318)
(441,979)
503,856
78,600
1,089
(28,070)
—
(108)
—
(7,468)
(56,696)
49,224
5,424
5,956
39,506
1,689
—
294
(4,996)
(1,017)
(7,044)
650
5,826
2,526
98
(10,471)
2,792
7,135
1,560
2,461
(15,874)
(2,938)
4,133
569
871
(2,381)
47,592
(35,846)
(327)
—
19,445
2,224
—
877
(1,048)
(14,675)
(431,982)
433,700
—
1,324
—
—
(78)
20,000
(10,446)
(47,462)
(34,944)
(2,027)
7,983
34,893
1,120
—
2,442
(131)
(65)
(13,224)
500
9,725
(2,327)
39
19,753
3,988
9,398
1,770
(992)
(14,904)
(13,629)
5,966
(453)
101
(1,190)
86,340
(101,450)
(5,983)
—
463
1,503
—
1,225
(2,379)
(106,621)
(257,191)
327,170
—
—
—
—
(93)
—
(18)
(45,717)
24,151
3,870
4,113
Cash at end of period .............................................................................................................
$ 11,380
$ 5,956
$ 7,983
Supplemental schedule of non-cash investing and financing activities:
Purchase of assets under capital lease obligations
Issuance of common and subordinated units in connection with Cross acquisition
Purchase of assets under note payable
$ —
$ —
$ 7,354
$ 7,764
$ 32,957
$ —
$ —
$ —
$ —
See accompanying notes to consolidated financial statements.
- 84 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(1)
ORGANIZATION AND DESCRIPTION OF BUSINESS
Martin Midstream Partners L.P. (the “Partnership”) is a publicly traded limited partnership with a diverse
set of operations focused primarily in the United Stated Gulf Coast region. Its four primary business lines include:
terminalling and storage services for petroleum products and by-products, natural gas services, sulfur and sulfur-
based products processing, manufacturing, marketing and distribution and marine transportation services for
petroleum products and by-products.
The petroleum products and by-products the Partnership collects, transports, stores and distributes are
produced primarily by major and independent oil and gas companies who often turn to third parties, such as the
Partnership, for the transportation and disposition of these products. In addition to these major and independent oil
and gas companies, our primary customers include independent refiners, large chemical companies, fertilizer
manufacturers and other wholesale purchasers of these products. The Partnership operates primarily in the Gulf
Coast region of the United States, which is a major hub for petroleum refining, natural gas gathering and processing
and support services for the oil and gas exploration and production industry.
The Partnership owns Prism Gas Systems I, L.P. (“Prism Gas”) which is engaged in the gathering,
processing and marketing of natural gas and natural gas liquids, predominantly in Texas and northwest Louisiana.
Prism Gas owns a 50% ownership interest in Waskom Gas Processing Company (“Waskom”), the Matagorda
Offshore Gathering System (“Matagorda”), and Panther Interstate Pipeline Energy LLC (“PIPE”), each accounted
for under the equity method of accounting.
(2)
SIGNIFICANT ACCOUNTING POLICIES
(a) Principles of Presentation and Consolidation
The consolidated financial statements include the financial statements of the Partnership and its wholly-
owned subsidiaries and equity method investees. In the opinion of the management of the 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, 2010 or 2009.
The Partnership acquired the assets of Cross Oil Refining & Marketing Inc. (“Cross”) from Martin
Resource Management (“Martin Resource Management”) in November 2009 as described in Note 5. The
acquisition of the Cross assets was considered a transfer of net assets between entities under common control. The
acquisition of the Cross assets and increase in partners’ capital for the common and subordinated units issued in
November 2009 are recorded at amounts based on the historical carrying value of the Cross assets at that date, and
the Partnership is required to revise its historical financial statements to include the activities of the Cross assets as
of the date of common control. Martin Resource Management acquired Cross in November 2006; however, the
activity for the period Cross was owned by Martin Resource Management during 2006 was not considered
significant to the Partnership’s consolidated financial statements and has been excluded from the consolidated
financial statements. The Partnership’s historical financial statements for 2008 and the period January 1, 2009
through November 24, 2009 have been revised to reflect the financial position, cash flows and results of operations
attributable to the Cross assets as if the Partnership owned the Cross assets for these periods. Net income
attributable to the Cross assets for periods prior to the 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)(o).
(b)
Product Exchanges
The Partnership enters into product exchange agreements with third parties whereby the Partnership agrees
to exchange NGLs and sulfur with third parties. The Partnership records the balance of exchange products due to
- 85 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
other companies under these agreements at quoted market product prices and the balance of exchange products due
from other companies at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”)
method. Revenue and costs related to product exchanges are recorded on a gross basis.
(c)
Inventories
Inventories are stated at the lower of cost or market. Cost is determined by using the first-in, first-out
(FIFO) method for all inventories.
(d) Revenue Recognition
Terminalling and storage – Revenue is recognized for storage contracts based on the contracted monthly
tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through the
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, revenue is recognized upon delivering product to the customers as title to the
product transfers when the customer physically receives the product.
Natural gas services – Natural gas gathering and processing revenues are recognized when title passes or
service is performed. NGL distribution revenue is recognized when product is delivered by truck to our NGL
customers, which occurs when the customer physically receives the product. When product is sold in storage, or by
pipeline, the Partnership recognizes NGL distribution revenue when the customer receives the product from either
the storage facility or pipeline.
Sulfur services – Revenues are recognized when the products are delivered, which occurs when the
customer has taken title and has assumed the risks and rewards of ownership based on specific contract terms at
either the shipping or delivery point.
Marine transportation – Revenue is recognized for contracted trips upon completion of the particular trip.
For time charters, revenue is recognized based on a per day rate.
(e) Equity Method Investments
The Partnership uses the equity method of accounting for investments in unconsolidated entities where the
ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of
capital contributions and advances plus the 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.
The Partnership’s Prism Gas subsidiary owns an unconsolidated 50% interest in Waskom, Matagorda, and
PIPE. As a result, these assets are accounted for by the equity method.
(f) Property, Plant, and Equipment
Owned property, plant, and equipment is stated at cost, less accumulated depreciation. Owned buildings and
equipment are depreciated using straight-line method over the estimated lives of the respective assets.
Equipment under capital leases is stated at the present value of minimum lease payments less accumulated
amortization. Equipment under capital leases is amortized straight line over the estimated useful life of the asset.
Routine maintenance and repairs are charged to operating expense while costs of betterments and renewals are
capitalized. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the
accounts and the difference between net book value of the asset and proceeds from disposition is recognized as gain or
loss.
- 86 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(g) Goodwill and Other Intangible Assets
Goodwill represents the excess of costs over fair value of assets of businesses acquired. Goodwill and
intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not
amortized, but instead tested for impairment at least annually in accordance with certain provisions of ASC 350-20.
Intangible assets with estimated useful lives are amortized over their respective estimated useful lives to their estimated
residual values, and reviewed for impairment under certain provisions of ASC 360-10 related to accounting for
impairment or disposal of long-lived assets. Other intangible assets primarily consist of covenants not-to-compete and
contracts obtained through business combinations and are being amortized over the life of the respective agreements.
Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or
circumstances indicate there may be impairment. The Partnership is required to identify 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. Goodwill is assigned to reporting units at the date the goodwill is initially recorded.
Once goodwill has been assigned to reporting units, it no longer retains its association with a particular acquisition, and
all of the activities within a reporting unit, whether acquired or organically grown, are available to support value of the
goodwill.
The Partnership performed the annual impairment tests as of September 30, 2010, September 30, 2009 and
September 30, 2008, respectively. In performing such tests, it was determined that there were four “reporting units”
which contained goodwill. These reporting units were in each of the four reporting segments: terminalling, natural gas
services, marine transportation, and sulfur services. The estimated fair value of the reporting units with goodwill were
developed using the guideline public company method, the guideline transaction method, and the discounted cash flow
(“DCF”) method using observable market data where available. To the extent the carrying amount of a reporting unit
exceeds the fair value of the reporting unit, the Partnership would be required to perform the second step of the
impairment test, as this is an indication that the reporting unit goodwill may be impaired. At September 30, 2010, 2009
and 2008 the estimated fair value of each of the four reporting units was in excess of its carrying value which indicates
no impairment existed.
As a result of the deterioration in the overall stock market subsequent to September 30, 2008 and the decline
in the Partnership’s unit price, the Partnership reviewed specific factors, as outlined under certain provisions of ASC
350-20, to determine if the Partnership had a trigging event that required it to test the goodwill for impairment as of
December 31, 2008. These factors included whether there have been any significant fundamental changes since the
annual impairment test to (i) the Partnership as a whole or to the reporting units, including regulatory changes, (ii) the
level of operating cash flows, (iii) the expectation of future levels of operating cash flows, (iv) the executive
management team, and (v) the carrying value of the other long-lived assets. While these factors did not indicate a
triggering event occurred, the Partnership’s unit price fell to a point by December 31, 2008 that resulted in the total
market capitalization being less than the partner’s equity. The Partnership determined this to be a triggering event
requiring the Partnership to perform an impairment test as of December 31, 2008. As a result of the goodwill
impairment test for each of the four reporting units as of December 31, 2008, no impairment was determined to exist.
(h) Debt Issuance Costs
Debt issuance costs relating to the Partnership’s line of credit facility and senior notes are deferred and
amortized over the terms of the debt arrangements.
In connection with the Partnership’s issuance of Senior Notes during March 2010, it incurred debt issuance
costs of $6,045.
In connection with the amendment and expansion of the Partnership’s multi-bank credit facility in December,
2009, it incurred debt issuance costs of $10,383. In connection with the amendment and restatement of the
Partnership’s credit facility in March 2010, it incurred additional debt issuance costs of $1,423. Due to a reduction in
the number of lenders under the Partnership’s multi-bank credit agreement, $634 and $495 of the existing debt issuance
costs were determined not to have continuing benefit and were expensed during 2010 and 2009, respectively. These
debt issuance costs, along with the remaining unamortized deferred issuance costs relating to the line of credit facility
as of November 10, 2005 which remain deferred, are amortized over the term of the revised debt arrangement.
- 87 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Amortization of debt issuance cost, which is included in interest expense for the years ended December 31,
2010, 2009 and 2008, totaled $4,814, $1,689, and $1,120, respectively, and accumulated amortization amounted to
$4,920 and $105 at December 31, 2010 and 2009, 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 2010, 2009 or 2008 that would require an assessment for impairment of long-lived assets.
(j) Asset Retirement Obligation
Under ASC 410-20, which relates to accounting requirements for costs associated with legal obligations to
retire tangible, long-lived assets, the Partnership records an Asset Retirement Obligation (“ARO”) at fair value in the
period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent
period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are
depreciated over the useful life of the related asset. The Partnership’s fixed assets include land, buildings,
transportation equipment, storage equipment, marine vessels and operating equipment.
The transportation equipment includes pipeline systems. The Partnership transports NGLs through the
pipeline system and gathering system. The Partnership also gathers natural gas from wells owned by producers and
delivers natural gas and NGLs on the Partnership’s pipeline systems, primarily in Texas and Louisiana to the
fractionation facility of the Partnership’s 50% owned joint venture. The Partnership is obligated by contractual or
regulatory requirements to remove certain facilities or perform other remediation upon retirement of the Partnership’s
assets. However, the Partnership is not able to reasonably determine the fair value of the asset retirement obligations
for the Partnership’s trunk and gathering pipelines and the Partnership’s surface facilities, since future dismantlement
and removal dates are indeterminate. In order to determine a removal date of the Partnership’s gathering lines and
related surface assets, reserve information regarding the production life of the specific field is required. As a
transporter and gatherer of natural gas, the Partnership is not a producer of the field reserves, and the Partnership
therefore does not have access to adequate forecasts that predict the timing of expected production for existing reserves
on those fields in which the Partnership gathers natural gas. In the absence of such information, the Partnership is not
able to make a reasonable estimate of when future dismantlement and removal dates of the Partnership’s gathering
assets will occur. With regard to the Partnership’s trunk pipelines and their related surface assets, it is impossible to
predict when demand for transportation of the related products will cease. The Partnership’s right-of-way agreements
allow us to maintain the right-of-way rather than remove the pipe. In addition, the Partnership can evaluate the
Partnership’s trunk pipelines for alternative uses, which can be and have been found. The Partnership will record such
asset retirement obligations in the period in which more information becomes available for us to reasonably estimate
the settlement dates of the retirement obligations.
(k) Derivative Instruments and Hedging Activities
In accordance with certain provisions of ASC 815-10 related to accounting for derivative instruments and
hedging activities, all derivatives and hedging instruments are included on the balance sheet as an asset or liability
measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting
criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change
in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as
the hedged item is recognized in earnings.
- 88 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Derivative instruments not designated as hedges are being marked to market with all market value
adjustments being recorded in the consolidated statements of operations. As of December 31, 2010, the Partnership has
designated a portion of its derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges
have been recorded in accumulated other comprehensive income as a component of equity.
(l) Comprehensive Income
Comprehensive income includes net income and other comprehensive income. Other comprehensive income
for the Partnership includes unrealized gains and losses on derivative financial instruments. In accordance ASC 815-
10, the Partnership records deferred hedge gains and losses on its derivative financial instruments that qualify as cash
flow hedges as other comprehensive income.
(m) Unit Grants
In August 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.
In August 2009, 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 $77. These units vest in 25% increments beginning in January 2010 and will be fully vested in January 2013.
In May 2008, the Partnership issued 1,000 restricted common units to each of its non-employee directors
under its long-term incentive plan from treasury units purchased by the Partnership in the open market for $93.
These units vest in 25% increments beginning in January 2009 and will be fully vested in January 2012.
The Partnership accounts for the transaction under certain provisions of FASB ASC 505-50-55 related to
equity-based payments to non-employees. The cost resulting from the unit-based payment transactions was $113,
$98, and $39 for the years ended December 31, 2010, 2009 and 2008, respectively.
(n)
Incentive Distribution Rights
The Partnership’s general partner, Martin Midstream GP LLC, holds a 2% general partner interest and
certain incentive distribution rights in the Partnership. Incentive distribution rights represent the right to receive an
increasing percentage of cash distributions after the minimum quarterly distribution, any cumulative arrearages on
common units, and certain target distribution levels have been achieved. The Partnership is required to distribute all
of its available cash from operating surplus, as defined in the partnership agreement. The target distribution levels
entitle the general partner to receive 15% of quarterly cash distributions in excess of $0.55 per unit until all unit
holders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unit
holders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the
years ended December 31, 2010, 2009 and 2008, the general partner received $3,623, $2,896, and $2,495 in
incentive distributions.
(o) Net Income per Unit
In March 2008, the FASB amended the provisions of ASC 260-10 related to earnings per share, which
addresses the application of the two-class method in determining income per unit for master limited partnerships
having multiple classes of securities that may participate in partnership distributions accounted for as equity
distributions. To the extent the partnership agreement does not explicitly limit distributions to the general partner,
any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the
- 89 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
distribution formula for available cash specified in the partnership agreement. When current period distributions are
in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited
partners based on their respective sharing of losses specified in the partnership agreement. ASC 260-10 is to be
applied retrospectively for all financial statements presented and is effective for financial statements issued for fiscal
years beginning after December 15, 2008, and interim periods within those fiscal years.
The Partnership adopted the amended provisions of ASC 260-10 on January 1, 2009. Adoption did not
impact the Partnership’s computation of earnings per limited partner unit as cash distributions exceeded earnings for
the years ended December 31, 2010, 2009 and 2008, respectively, and the IDRs do not share in losses under the
partnership agreement. In the event the Partnership’s earnings exceed cash distributions, ASC 260-10 will have an
impact on the computation of the Partnership’s earnings per limited partner unit. The Partnership agreement does not
explicitly limit distributions to the general partner; therefore, any earnings in excess of distributions are to be
allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in
the Partnership agreement. For years ended December 31, 2010, 2009 and 2008, the general partner’s interest in net
income, including the IDRs, represents distributions declared after period end on behalf of the general partner
interest and IDRs less the allocated excess of distributions over earnings for the periods.
General and limited partner interest in net income includes only net income of the Cross assets since the
date of acquisition. Accordingly, net income of the Partnership is adjusted to remove the net income attributable to
the Cross assets prior to the date of acquisition and such income is allocated to the Parent. The recognition of the
beneficial conversion feature for the period is considered a deemed distribution to the subordinated unit holders and
reduces net income available to common limited partners in computing net income per unit.
For purposes of computing diluted net income per unit, the Partnership uses the more dilutive of the two-
class and if-converted methods. Under the if-converted method, the beneficial conversion feature is added back to
net income available to common limited partners, the weighted-average number of subordinated units outstanding
for the period is added to the weighted-average number of common units outstanding for purposes of computing
basic net income per unit and the resulting amount is compared to the diluted net income per unit computed using
the two-class method.
The following table reconciles net income to limited partners’ interest in net income:
Net income attributable to Martin Midstream Partners L. P .......... $ 16,022
—
Less pre-acquisition income allocated to Parent ............................
Less general partner’s interest in net income:
2010
Years Ended December 31,
2009
$ 22,203
1,664
2008
$ 43,558
748
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
(941)
Less beneficial conversion feature ................................................
1,108
Limited partners’ interest in net income........................................ $ 11,045
3,623
1,187
2,896
949
2,495
914
(596)
111
$ 17,179
(108)
—
$ 39,509
The weighted average units outstanding for basic net income per unit were 17,525,089, 14,680,807, and
14,529,826 for years ended December 31, 2010, 2009 and 2008, respectively. For diluted net income per unit, the
weighted average units outstanding were increased by 900, 3,968, and 4,896 units for the years ended December 31,
2010, 2009 and 2008, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-
term incentive plan.
(p)
Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses are incurred by Martin Resource Management
Corporation (“Martin Resource Management”) and allocated to the Partnership to cover costs of centralized corporate
functions such as accounting, treasury, engineering, information technology, risk management and other corporate
services. Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that
- 90 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
provide such centralized services. Under the omnibus agreement, we are required to reimburse Martin Resource
Management for indirect general and administrative and corporate overhead expenses. For the years ended December
31, 2010, 2009 and 2008, the Conflicts Committee of our general partner approved reimbursement amounts of $3,791,
$3,542, and $2,896, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review
and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.
(q)
Environmental Liabilities and Litigation
The 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.
(r) Accounts Receivable and Allowance for Doubtful Accounts.
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for
doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing
accounts receivable.
(s)
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 24-36 months.
(t)
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 24-36 months.
(u) Use of Estimates
Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities
and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity
with accounting principles generally accepted in the United States of America. Actual results could differ from those
estimates.
(v)
Income Taxes
With respect to the Partnership’s taxable subsidiary (Woodlawn Pipeline Co., Inc.) and the Cross assets
prior to the date of acquisition, income taxes are accounted for under the asset and liability method. Deferred tax
assets and liabilities are recognized for the future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those
temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a
change in tax rates is recognized in income in the period that includes the enactment date.
(3)
FAIR VALUE MEASUREMENTS
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
- 91 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
820 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value of each
asset and liability carried at fair value into one of the following categories:
Level 1: Quoted market prices in active markets for identical assets or liabilities.
Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.
Level 3: Unobservable inputs that are not corroborated by market data.
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 13 for further information on the
Partnership’s derivative instruments and hedging activities.
The following items are measured at fair value on a recurring basis and are subject to the disclosure
requirements of ASC 820 at December 31, 2010:
Fair Value Measurements at Reporting Date Using
Quoted Prices in
Active Markets
for
Identical Assets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
Description
December 31,
2010
(Level 1)
(Level 2)
(Level 3)
Assets
Interest rate derivatives
Natural gas derivatives
Total assets
Liabilities
Interest rate derivatives
Natural gas derivatives
Crude oil derivatives
Natural gas liquids derivatives
Total liabilities
$ 1,941
201
$ 2,142
$ 3,930
28
177
247
$ 4,382
$ —
—
$ —
$ —
—
—
—
$ —
$ 1,941
201
$ 2,142
$ 3,930
28
177
247
$ 4,382
$ —
—
$ —
$ —
—
—
—
$ —
The following items are measured at fair value on a recurring basis and are subject to the disclosure
requirements of ASC 820 at December 31, 2009:
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,
2009
(Level 1)
(Level 2)
(Level 3)
Assets
Interest rate derivatives
Natural gas derivatives
Crude oil derivatives
Natural gas liquids derivatives
Total assets
Liabilities
Interest rate derivatives
$ 1,286
70
275
241
$ 1,872
$ —
—
—
—
$ —
$ 1,286
70
275
241
$ 1,872
$ —
—
—
—
$ —
$ 6,611
$ —
$ 6,611
$ —
- 92 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Fair Value Measurements at Reporting Date Using
Quoted Prices in
Active Markets
for
Identical Assets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
Description
Crude oil derivatives
Natural gas liquids derivatives
Total liabilities
December 31,
2009
290
326
$ 7,227
(Level 1)
—
—
$ —
(Level 2)
(Level 3)
290
326
$ 7,227
—
—
$ —
ASB 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 because of the
short maturity of these instruments.
• Long-term debt including current installments — The carrying amount of the revolving and term
loan facilities approximates fair value due to the debt having a variable interest rate. The estimated fair
value of the Senior Notes was approximately $216,366 as of December 31, 2010, based on market prices
of similar debt at December 31, 2010.
(4)
RECENT ACCOUNTING PRONOUNCEMENTS
In December 2009, FASB amended the provisions of ASC 810 related to the consolidation of variable
interest entities. It requires reporting entities to evaluate former qualifying special purpose entities for consolidation,
changes the approach to determining a variable interest entity’s (“VIE”) primary beneficiary from a quantitative
assessment to a qualitative assessment designed to identity a controlling financial interest and increases the
frequency of required reassessments to determine whether a company is the primary beneficiary of a VIE. It also
clarifies, but does not significantly change, the characteristics that identify a VIE. This amended guidance required
additional year-end and interim disclosures for public companies that are similar to the disclosures required by ASC
810-10-50-8 through 50-19 and 860-10-50-3 through 50-9. The Partnership adopted this amended guidance on
January 1, 2010. The adoption did not have an impact on the Partnership’s financial position or results of operations.
(5)
ACQUISITIONS
(a) Darco Gathering System
On November 1, 2010, the Partnership, through its wholly owned subsidiary, Prism Gas, acquired
approximately 20 miles of natural gas gathering pipeline and various equipment located in Harrison County, Texas.
The final purchase price of approximately $25,015 was funded by borrowings under the Partnership’s credit
agreement.
The purchase price including other intangibles reflected as other assets was allocated as follows:
Property, plant and equipment..............
Other assets...........................................
9,925
15,090
$25,015
The identifiable intangible asset of $15,090 is a life of lease contract with an active producer in the
Haynesville Shale and Cotton Valley sand. The contract is subject to amortization over an approximate useful life
of twenty years.
- 93 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(b) Harrison Gathering System
On January 15, 2010, the Partnership, through Prism Gas Systems I, L.P. (“Prism Gas”), as 50% owner and
the operator of Waskom Gas Processing Company (“Waskom”), through Waskom’s 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
Gathering System. The Partnership’s share of the acquisition cost was approximately $20,000 and was recorded as
an investment in an unconsolidated entity.
(c) East Harrison Pipeline System.
In December 2009, the Partnership acquired, through Prism Gas, from Woodward Partners, Ltd. 6.45 miles
of gathering pipeline referred to as the East Harrison Pipeline System for $327. The system currently transports
approximately 500 Mcfd of natural gas under various transport contracts which provide for a minimum monthly fee.
(d) Cross Refining Assets.
In November 2009, the Partnership closed a transaction with Martin Resource Management Corporation
(“Martin Resource Management”) and Cross Refining & Marketing, Inc. (“Cross”), a wholly owned subsidiary of
Martin Resource Management, in which the Partnership acquired certain specialty lubricants processing assets
(“Assets”) from Cross for total consideration of $44,878 (the “Contribution”). As consideration for the Contribution,
the Partnership issued 804,721 common units and 889,444 subordinated units to Martin Resource Management at a
price of $27.96 and $25.16 per limited partner unit, respectively. In connection with the Contribution, the General
Partner made a capital contribution of $918 in cash to the Partnership in order to maintain its 2% general partner
interest.
The Partnership accounted for the Cross acquisition as a transfer of net assets between entities under
common control pursuant to the provisions of FASB ASC 850. The Cross assets were recorded at $32,957, which
represents the amounts reflected in Martin Resource Management’s historical consolidated financial statements.
The difference between the purchase price and Martin Resource Management’s carrying value of the combined net
assets acquired and liabilities assumed was recorded as an adjustment to partners’ capital.
(6)
ISSUANCE OF COMMON UNITS
On August 17, 2010, the Partnership completed a public offering of 1,000,000 common units, representing
limited partner interests at a purchase price of $29.13 per common unit. The Partnership received net proceeds of
approximately $28,070 after payment of underwriters’ discounts. The Partnership used the net proceeds of $28,070
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 the Partnership for its
payments of commissions and offering expenses. As a result of these simultaneous transactions, the Partnership’s
general partner was not required to contribute cash to the Partnership in conjunction with the issuance of these units
in order to maintain its 2% general partner interest in the Partnership since there was no net increase in the
outstanding limited partner units.
On February 8, 2010, the Partnership completed a public offering of 1,650,000 common units at a price of
$32.35 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per
unit value is in dollars, not thousands). Following this offering, the common units represented a 93.3% limited
partner interest in the Partnership. Total proceeds from the sale of the 1,650,000 common units, net of underwriters’
discounts, commissions and offering expenses were $50,530. The Partnership’s general partner contributed $1,089
in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the
Partnership. On February 8, 2010, the Partnership reduced the outstanding balance under its revolving credit facility
by $45,000.
In addition to the units referred to in Note 5(d) above, in November 2009, the Partnership closed a private
equity sale with Martin Resource Management, under which Martin Resource Management invested $20,000 in cash
- 94 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
in the Partnership in exchange for 714,285 common units of the Partnership. In connection with the issuance of
these common units, the General Partner made a capital contribution to the Partnership of $408 in order to maintain
its 2% general partner interest in the Partnership.
(7) INVENTORIES
Components of inventories at December 31, 2010 and 2009 were as follows:
Natural gas liquids ........................................................................................
Sulfur ............................................................................................................
Sulfur Based Products...................................................................................
Lubricants .....................................................................................................
Other .............................................................................................................
2010
$ 19,775
15,933
9,027
5,267
2,614
$ 52,616
2009
$ 15,002
2,540
10,053
4,684
3,231
$ 35,510
(8) PROPERTY, PLANT AND EQUIPMENT
At December 31, 2010 and 2009, property, plant, and equipment consisted of the following:
Depreciable Lives
2010
2009
Land ...........................................................................
Improvements to land and buildings..........................
Transportation equipment ..........................................
Storage equipment .....................................................
Marine vessels ...........................................................
Operating equipment .................................................
Furniture, fixtures and other equipment.....................
Construction in progress ............................................
—
10-25 years
3-7 years
5-20 years
4-25 years
3-20 years
3-20 years
$ 20,200
53,655
1,816
62,372
226,376
253,271
1,656
13,110
$ 632,456
$ 15,759
48,704
1,786
59,597
210,593
238,956
1,646
6,995
$ 584,036
Depreciation expense for the year ended December 31, 2010, 2009, and 2008 was $38,085, $37,027, and $33,060,
respectively, which includes amortization of fixed assets acquired under capital lease obligations of $280, $116, and
$0 for 2010, 2009, and 2008; respectively. Gross assets under capital leases were $7,764 at December 31, 2010 and
2009. Accumulated amortization associated with capital leases was $396 and $116 at December 31, 2010 and 2009,
respectively.
(9) GOODWILL AND OTHER INTANGIBLE ASSETS
At December 31, 2010 and 2009, goodwill balances consisted of the following:
Carrying amount of goodwill:
Terminalling and storage .................................................................
Natural gas services .........................................................................
Sulfur services .................................................................................
Marine transportation.......................................................................
$ 883
29,010
5,349
2,026
$ 883
29,010
5,349
2,026
2010
2009
$37,268
$37,268
- 95 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
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 $17,504 and $3,103 at December 31, 2010 and 2009, respectively.
Aggregate amortization expense for amortizing intangible assets was $689, $858, and $864, for the years
ended December 31, 2010, 2009 and 2008, respectively, and accumulated amortization amounted to $2,283 and
$2,954 at December 31, 2010 and 2009, respectively.
Estimated amortization expenses for the years subsequent to December 31, 2010 are as follows: 2011 -
$1,232; 2012 - $1,232; 2013 - $1,231; 2014 - $1,150; 2015 - $1,067; subsequent years -$11,592.
10)
LEASES
The Partnership has numerous non-cancelable operating leases primarily for transportation and other
equipment. The leases generally provide that all expenses related to the equipment are to be paid by the lessee.
Management expects to renew or enter into similar leasing arrangements for similar equipment upon the expiration
of the current lease agreements. The Partnership also has cancelable operating lease land rentals and outside marine
vessel charters. Certain of our marine vessels have been acquired under capital leases.
The Partnership’s future minimum lease obligations as of December 31, 2010 consist of the following:
Fiscal year
2011 ...................................................................................................................
2012 ...................................................................................................................
2013 ...................................................................................................................
2014 ...................................................................................................................
2015 ...................................................................................................................
Thereafter ..........................................................................................................
Total
Less amounts representing interest costs
Present value of net minimum capital lease payments
Less current installments
Present value of net minimum capital lease payments, excluding
current installments
Operating
Leases
$ 9,690
7,758
5,918
5,307
5,108
13,398
$47,179
Capital
Leases
$ 1,102
1,117
1,135
1,147
1,169
5,582
11,252
5,080
6,172
130
$ 6,042
Rent expense for operating leases for the years ended December 31, 2010, 2009 and 2008 was $15,710, $11,158 and
$12,527; respectively. The amount recognized in interest expense for capital leases was $991, $250, and $0 for the
years ended December 31, 2010, 2009 and 2008; respectively.
(11)
INVESTMENT IN UNCONSOLIDATED ENTITIES AND JOINT VENTURES
The Partnership’s Prism Gas subsidiary owns an unconsolidated 50% interest in Waskom, the Matagorda
Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). As a result, these
assets are accounted for by the equity method.
On June 30, 2006, the Partnership’s Prism Gas subsidiary, acquired a 20% ownership interest in a
partnership which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). The lease contract
terminated in June 2009, and, as such, the investment was fully amortized as of June 30, 2009.
In accounting for the acquisition of the interests in Waskom, Matagorda and PIPE, the carrying amount of
these investments exceeded the underlying net assets by approximately $46,176. The difference was attributable to
- 96 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
property and equipment of $11,872 and equity method goodwill of $34,304. The excess investment relating to
property and equipment is being amortized over an average life of 20 years, which approximates the useful life of the
underlying assets. Such amortization amounted to $594 for the years ended December 31, 2010, 2009 and 2008,
respectively, has been recorded as a reduction of equity in earnings of unconsolidated equity method investees. The
remaining unamortized excess investment relating to property and equipment was $8,903, $9,497 and $10,091 at
December 31, 2010, 2009 and 2008, respectively. The equity-method goodwill is not amortized; however, it is
analyzed for impairment annually or if changes in circumstance indicate that a potential impairment exists. No
impairment was recorded in 2010, 2009 or 2008.
As a partner in Waskom, the Partnership receives distributions in kind of natural gas liquids (“NGLs”) that are
retained according to Waskom’s contracts with certain producers. The NGLs are valued at prevailing market prices. In
addition, cash distributions are received and cash contributions are made to fund operating and capital requirements of
Waskom.
Activity related to these investment accounts is as follows:
Investment in unconsolidated entities, December 31, 2008
$ 74,978
$ 1,214
Waskom
PIPE
Matagord
a
$ 3,559
BCP
Total
$ 92
$ 79,843
Distributions in kind....................................................................
Distributions from unconsolidated entities…………………………
Contributions to unconsolidated entities:
Cash contributions……………………………………
Contributions to unconsolidated entities for operations…………
Return of investments………………………………………
Equity in earnings:
Equity in earnings (losses) from operations ...................
Amortization of excess investment.................................
(5,826)
(650)
—
958
—
—
—
90
—
(490)
—
—
—
—
(375)
—
—
—
—
(12)
(5,826)
(650)
90
958
(877)
6,934
(550)
602
(15)
182
(29)
(80)
—
7,638
(594)
Investment in unconsolidated entities, December 31 2009
$ 75,844
$ 1,401
$ 3,337
$ -—
$ 80,582
Waskom
PIPE
Matagorda
BCP
Total
Investment in unconsolidated entities, December 31, 2009
$ 75,844
$ 1,401
$ 3,337
$ -—
$ 80,582
Distributions in kind....................................................................
Contributions to unconsolidated entities:
Cash contributions……………………………………
Contributions to unconsolidated entities for operations…………
Cash contributions to fund asset acquisition…………………..
Return of investments………………………………………
Equity in earnings:
Equity in earnings (losses) from operations ...................
Amortization of excess investment.................................
(10,545)
—
628
20,110
(2,100)
—
—
120
—
(30)
—
—
—
—
(340)
—
—
—
—
—
(10,545)
—
748
20,110
(2,470)
10,381
(550)
(165)
(15)
170
(29)
—
—
10,386
(594)
Investment in unconsolidated entities, December 31 2010
$ 93,768
$ 1,311
$ 3,138
$ -—
$ 98,217
Select financial information for significant unconsolidated equity method investees is as follows:
As of December 31,
Years ended December 31,
Total
Assets
Partners’
Capital
Revenues
Net Income
2010
Waskom..........................................................................
$ 122,057
$107,508
$123,210
$ 20,762
2009
Waskom..........................................................................
$ 79,604
$ 70,561
$71,044
$ 13,867
2008
Waskom..........................................................................
$ 78,661
$ 67,730
$115,031
$ 27,292
- 97 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
As of December 31, 2010 and December 31, 2009, the amount of the Partnership’s consolidated retained
earnings that represents undistributed earnings related to the unconsolidated equity method investees is $40,509 and
$32,717, respectively. There are no material restrictions to transfer funds in the form of dividends, loans or
advances related to the equity method investees.
As of December 31, 2010 and 2009, the Partnership’s interest in cash of the unconsolidated equity method
investees is $789 and $704, respectively.
(12)
LONG-TERM DEBT AND CAPITAL LEASES
At December 31, 2010 and December 31, 2009, long-term debt consisted of the following:
** $200,000 Senior notes, 8.875% interest, net of unamortized discount of
$2,543 and $0, respectively, issued March 2010 and due April 2018,
unsecured.........................................................................................................
*** $275,000 Revolving loan facility at variable interest rate (4.40%*
weighted average at December 31, 2010), due March 2013 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 ..........................................................................................................
$67,949 Term loan facility at variable interest rate (4.73%* at December
31, 2009), was terminated and converted to a revolving loan on March 26,
2010, previously secured by substantially all of the Partnership assets,
which included, without limitation, inventory, accounts receivable,
vessels, equipment, fixed assets and the interests in Partnership’s operating
subsidiaries ......................................................................................................
December 31,
2010
December 31,
2009
$197,457
$ —
163,000
230,251
—
67,949
$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 installments ........................................................................................
Long-term debt and capital lease obligations, net of current installments..............
7,354
6,172
373,983
1,121
$372,862
—
6,283
304,483
111
$304,372
* 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 3.00% to 4.25% and the applicable margin for revolving loans that are base prime
rate loans ranges from 2.00% to 3.25%. The applicable margin for existing LIBOR borrowings is 4.00%. Effective
January 1, 2011, the applicable margin for existing LIBOR borrowings will remain at 4.00%. As a result of the
Partnership’s leverage ratio test as of December 31, 2010, effective April 1, 2011, the applicable margin for existing
LIBOR borrowings will remain at 4.00% under the current credit facility.
** 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 is the applicable three-month LIBOR rate. This interest rate swap is not accounted
for using hedge accounting and matures in April 2018.
- 98 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
** 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 is the applicable three-month LIBOR rate. This interest rate swap is not accounted
for using hedge accounting and matures in April 2018.
*** 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 2.820% 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 2.580% 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 3.400% 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 4.605% 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 4.305% 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 4.765% plus the Partnership’s applicable LIBOR borrowing spread. This
cash flow hedge matured in March 2010.
*** 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.
(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% senior unsecured notes due
2018 (the “Notes”). We completed the aforementioned 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 our revolving credit facility.
On September 16, 2010, the Partnership filed a registration statement, pursuant to the registration rights
agreement for the Notes issued in March 2010. The Partnership exchanged the Notes for registered 8.875% senior
unsecured notes due April 2018.
In connection with the issuance of the Notes, all “non-issuer” wholly-owned subsidiaries of the Partnership
issued full, irrevocable, and unconditional guarantees of the Notes. As discussed in Note 22, the Partnership does
not provide separate financial statements of the Operating Partnership because the Partnership has no independent
assets or operations, the guarantees are full and unconditional, and the other subsidiary of the Partnership is minor.
- 99 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Indenture.
Interest and Maturity. On March 26, 2010, the Issuers issued the Notes pursuant to the Indenture in a
transaction exempt from registration requirements under the Securities Act. The Notes were resold to qualified
institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States
pursuant to Regulation S under the Securities Act. The Notes will mature on April 1, 2018. The interest payment
dates are April 1 and October 1, beginning on October 1, 2010.
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 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 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 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 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 twelve-month period beginning on April 1, 2015 and 100.00% for the
twelve-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 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 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 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 Notes; (ii) default in payment when due of the principal of, or
premium, if any, on the Notes; (iii) failure by the Partnership to comply with certain covenants relating to asset
sales, repurchases of the 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 Notes, by notice to the Issuers
and the Trustee, may declare the 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 Notes to become due and payable.
- 100 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Registration Rights Agreement. Under the Registration Rights Agreement, the Issuers and the Guarantors
filed with the SEC, a registration statement with respect to an offer to exchange the Notes for substantially identical
notes that are registered under the Securities Act. Pursuant to the registration rights agreement for the Senior Notes
issued in March 2010, the Partnership filed an exchange offer registration statement on September 16, 2010. The
Partnership exchanged the Notes for registered 8.875% senior unsecured notes due April 2018.
(b) Credit Facility
On November 10, 2005, the Partnership entered into a $225,000 multi-bank credit facility comprised of a
$130,000 term loan facility and a $95,000 revolving credit facility, which included a $20,000 letter of credit sub-limit.
Effective September 30, 2006, the Partnership increased its revolving credit facility by $25,000, resulting in a
committed $120,000 revolving credit facility. Effective December 28, 2007, the Partnership increased its revolving
credit facility by $75,000, resulting in a committed $195,000 revolving credit facility. Effective December 21, 2009, (i)
the Partnership increased its revolving credit facility by approximately $72,722, resulting in a committed $267,722
revolving credit facility and (ii) decreased its term loan facility by approximately $62,051, resulting in a $67,949 term
loan facility. Effective January 14, 2010, the Partnership modified its revolving credit facility to (i) permit investment
up to $25,000 in joint ventures and (ii) limit its ability to make capital expenditures. Effective February 25, 2010, the
Partnership increased the maximum amount of borrowings and letters of credit available under its credit facility from
approximately $335,671 to $350,000. Effective March 26, 2010, the Partnership’s credit facility was amended and
restated to (i) decrease the size of its aggregate facility from $350,000 to $275,000, (ii) convert all term loans to
revolving loans, (iii) extend the maturity date from November 9, 2012 to March 15, 2013, (iv) permit the Partnership to
invest up to $40,000 in its joint ventures, (v) eliminate the covenant that limits its ability to make capital expenditures,
(vi) decrease the applicable interest rate margin on committed revolver loans, (vii) limit its ability to make future
acquisitions and (viii) adjust the financial covenants.
Under the amended and restated credit facility, as of December 31, 2010, the Partnership had $163,000
outstanding under the revolving credit facility. As of December 31, 2010, irrevocable letters of credit issued under
the Partnership’s credit facility totaled $120.
As of December 31, 2010, the Partnership had $111,880 available under its revolving credit facility. The
revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance
permitted investments, acquisitions and capital expenditures. During the current fiscal year, draws on the
Partnership’s credit facility ranged from a low of $80,000 to a high of $324,500.
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. Prior to the Partnership’s or any of its
subsidiaries’ issuance of $100,000 or more of unsecured indebtedness, the maximum permitted leverage ratio is 4.00
to 1.00. After the Partnership or any of its subsidiaries’ issuance of $100,000 or more of unsecured indebtedness,
the maximum permitted leverage ratio is 4.50 to 1.00. After the Partnership or any of its subsidiaries’ issuance of
$100,000 or more of unsecured indebtedness, the maximum permitted senior leverage ratio (as defined in the new
credit facility, but generally computed as the ratio of total secured funded debt to consolidated earnings before
interest, taxes, depreciation, amortization and certain other non-cash charges) is 2.75 to 1.00. The minimum
- 101 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
consolidated interest coverage ratio (as defined in the new credit facility, but generally computed as the ratio of
consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to
consolidated interest charges) is 3.00 to 1.00. The Partnership was in compliance with the covenants contained in
the credit facility as of December 31, 2010.
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 our general partner or 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 the
Partnership’s 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 Partnership’s 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 Partnership’s
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 March 15, 2013. 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.
The Partnership paid cash interest in the amount of $23,663, $18,291, and $18,744 for the years ended
December 31, 2010, 2009, and 2008, respectively. Capitalized interest was $130, $259, and $1,383 for the years
ended December 31, 2010, 2009, and 2009, respectively. In March 2010, the Partnership terminated all of its then
outstanding interest rate swaps resulting in termination fees of $3,850.
(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Partnership’s results of operations are materially impacted by changes in crude oil, natural gas and
natural gas liquids prices and interest rates. In an effort to manage our exposure to these risks, we periodically enter
into various derivative instruments, including commodity and interest rate hedges. We are required to recognize all
derivative instruments as either assets or liabilities at fair value on our Consolidated Balance Sheets and to recognize
certain changes in the fair value of derivative instruments on our Consolidated Statements of Operations.
The Partnership performs, at least quarterly, a retrospective assessment of the effectiveness of our hedge
contracts, including assessing the possibility of counterparty default. If we determine that a derivative is no longer
expected to be highly effective, we discontinue hedge accounting prospectively and recognize subsequent changes in
the fair value of the hedge in earnings. As a result of our effectiveness assessment at December 31, 2010, we believe
certain hedge contracts will continue to be effective in offsetting changes in cash flow or fair value attributable to
the hedged risk.
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
- 102 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
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.
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 accumulated other comprehensive income 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.
In March 2008, the FASB amended the provisions of ASC Topic 820 related to fair value measurements
and disclosures, which changes the disclosure requirements for derivative instruments and hedging activities.
Entities are required to provide enhanced disclosures about (1) how and why an entity uses derivative instruments,
(2) how derivative instruments and related hedged items are accounted for and (3) how derivative instruments and
related hedged items affect an entity’s financial position, financial performance and cash flows. The Partnership
adopted this guidance on January 1, 2009.
Commodity Derivative Instruments
The Partnership is exposed to market risks associated with commodity prices and uses 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 its commodity risk exposure. The Partnership has entered into
hedging transactions through 2012 to protect a portion of its commodity 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 volatility in commodity markets, the Partnership is unable to predict the amount of ineffectiveness
each period, including the loss of hedge accounting, which is determined on a derivative by derivative basis. This may
result, and has resulted in increased volatility in the Partnership’s financial results. Factors that have and may continue
to lead to ineffectiveness and unrealized gains and losses on derivative contracts include: a substantial fluctuation in
energy prices, the number of derivatives the Partnership holds, and significant weather events that have affected energy
production. The number of instances in which the Partnership has discontinued hedge accounting for specific hedges is
primarily due to those reasons. However, even though these derivatives may not qualify for hedge accounting, the
Partnership continues to hold the instruments as it believes they continue to afford the Partnership opportunities to
manage commodity risk exposure.
As of December 31, 2010 and 2009, the Partnership has both derivative instruments qualifying for hedge
accounting with fair value changes being recorded in AOCI as a component of partners’ capital and derivative
instruments not designated as hedges being marked to market with all market value adjustments being recorded in
earnings.
Set forth below is the summarized notional amount and terms of all instruments held for price risk
management purposes at December 31, 2010 (all gas quantities are expressed in British Thermal Units, crude oil and
natural gas liquids are expressed in barrels). As of December 31, 2010, the remaining term of the contracts extend
no later than December 2012, with no single contract longer than one year. For the years ended December 31, 2010,
and 2009, 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.
- 103 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Pricing Terms
Remaining Terms
of Contracts
Fair Value
Transaction Type
Total
Volume
Per Month
Mark to Market Derivatives::
Crude Oil Swap
2,000 BBL
Fixed price of $91.20 settled against WTI
NYMEX average monthly closings
January 2011 to
December 2011
Total commodity swaps not designated as hedging instruments
Cash Flow Hedges:
Natural Gas Swap
10,000 Mmbtu
Fixed price of $6.1250 settled against
IF_ANR_LA first of the month posting
January 2011 to
December 2011
Natural Gas Swap
20,000 Mmbtu
Fixed price of $4.3225 settled against
IF_ANR_LA first of the month posting
January 2011 to
December 2011
Natural Gasoline
Swap
Natural Gasoline
Swap
2,000 BBL
1,000 BBL
Crude Oil Swap
2,000 BBL
Fixed price of $87.10 settled against WTI
NYMEX average monthly closings
January 2011 to
December 2011
Fixed price of $88.85 settled against WTI
NYMEX average monthly closings
January 2011 to
December 2011
Fixed price of $88.63 settled against WTI
NYMEX average monthly closings
January 2012 to
December 2012
Natural Gasoline
Swap
1,000 BBL
Fixed price of $90.20 settled against WTI
NYMEX average monthly closings
January 2012 to
December 2012
Total commodity swaps designated as hedging instruments
Total net fair value of commodity derivatives
(51)
$ (51)
201
(28)
(149)
(54)
(126)
(44)
$ (200)
$ (251)
Based on estimated volumes, as of December 31, 2010, the Partnership had hedged approximately 37% and
10% of its commodity risk by volume for 2011 and 2012, respectively. As of March 2, 2011, Prism Gas has hedged
approximately 45% and 14% of its commodity risk by volume for 2011 and 2012, respectively.
The Partnership anticipates entering into additional commodity derivatives on an ongoing basis to manage
its risks associated with these market fluctuations, and will consider using various commodity derivatives, including
forward contracts, swaps, collars, futures and options, although there is no assurance that the Partnership will be able
to do so or that the terms thereof will be similar to the Partnership’s existing hedging arrangements.
The Partnership’s credit exposure related to commodity cash flow hedges is represented by the positive fair
value of contracts to the Partnership at December 31, 2010. These outstanding contracts expose the Partnership to
credit loss in the event of nonperformance by the counterparties to the agreements. The Partnership has incurred no
losses associated with counterparty nonperformance on derivative contracts.
On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the
counterparty’s financial condition prior to entering into an agreement, establishes a maximum credit limit threshold
pursuant to its hedging policy, and monitors the appropriateness of these limits on an ongoing basis. The Partnership
has agreements with five counterparties containing collateral provisions. Based on those current agreements, cash
deposits are required to be posted whenever the net fair value of derivatives associated with the individual
counterparty exceed a specific threshold. If this threshold is exceeded, cash is posted by the Partnership if the value
of derivatives is a liability to the Partnership. As of December 31, 2010 the Partnership has no cash collateral
deposits posted with counterparties.
- 104 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
The Partnership’s principal customers with respect to Prism Gas’ natural gas gathering and processing are
large, natural gas marketing services, oil and gas producers and industrial end-users. In addition, substantially all of
the Partnership’s natural gas and NGL sales are made at market-based prices. The Partnership’s standard gas and
NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries,
cancellation of agreements or discontinuance of deliveries to the buyer unless the buyer provides security for
payment in a form satisfactory to the Partnership.
Impact of Commodity Cash Flow Hedges
Crude Oil
For the years ended December 31, 2010, 2009 and 2008, net gains and losses on swap hedge contracts
increased crude revenue by $27, decreased crude revenue by $854 and increased crude revenue by $1,745,
respectively. As of December 31, 2010 an unrealized derivative fair value gain of $634 related to current and
terminated cash flow hedges of crude oil price risk was recorded in AOCI. Fair value gains of $760 and fair value
losses of $126 are expected to be reclassified into earnings in 2011 and 2012, respectively. The actual
reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract
settlement date or for those terminated contracts based on the recorded values at December 31, 2010 adjusted for
any impairment, along with the realization of the gain or loss on the related physical volume, which is not reflected
above.
Natural Gas
For the years ended December 31, 2010, 2009 and 2008, net gains and losses on swap hedge contracts
increased gas revenue by $601 and $1,824 and decreased gas revenue by $431, respectively. As of December 31,
2010 an unrealized derivative fair value gain of $158 related to cash flow hedges of natural gas was recorded in
AOCI. This fair value gain is expected to be reclassified into earnings in 2011. The actual reclassification to
earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain
or loss on the related physical volume, which is not reflected above.
Natural Gas Liquids
For the years ended December 31, 2010, 2009 and 2008, net gains and losses on swap hedge contracts
increased liquids revenue by $207 and decreased liquids revenue by $186 and $316, respectively. As of December
31, 2010, an unrealized derivative fair value gain of $645 related to current and terminated cash flow hedges of
natural gas liquids price risk was recorded in AOCI. Fair value gains of $689 and fair value losses of $44 are
expected to be reclassified into earnings in 2011 and 2012, respectively. The actual reclassification to earnings for
contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those
terminated contracts based on the recorded values at December 31, 2010 adjusted for any impairment, along with the
realization of the gain or loss on the related physical volume, which is not reflected above.
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.
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.
- 105 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
The Partnership has entered into interest rate swap agreements with an aggregate notional amount of
$100,000 to hedge its exposure to changes in the fair value of Senior Notes. The Partnership believes the interest
rate hedge contracts will be effective in offsetting changes in fair value attributable to the hedged risk; however, the
contracts were not designated as fair value hedges and therefore, are not receiving hedge accounting but being
marked to market through earnings.
Under the following swap agreements, the Partnership pays a floating rate of interest and receives a fixed
rate based on a three-month U.S. Dollar LIBOR rate to match the fixed rate of the Senior Notes:
Date of Hedge
September 2010
September 2010
Notional Amount
$40,000
$60,000
Paying
Floating Rate
3 Month LIBOR
3 Month LIBOR
Receiving
Fixed Rate
2.3150%
2.3150%
Maturity Date
April 2018
April 2018
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 early extinguishment of all interest rate
swap agreements in March 2010. The amounts remaining in AOCI will be reclassified into interest expense over
the original term of the terminated interest rate derivatives.
The Partnership recognized increases in interest expense of $6,327 and $7,892 for the years ended
December 31, 2010 and 2009, 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
The following table summarizes the fair values and classification of our derivative instruments in our
Consolidated Balance Sheet:
Fair Values of Derivative Instruments in the Consolidated Balance Sheet
Derivative Assets
Derivative Liabilities
Fair Values
December 31,
Fair Values
December 31,
Balance Sheet Location
2010
2009
Balance Sheet Location
2010
2009
Derivatives designated as
hedging instruments:
Interest rate contracts .................... Fair value of derivatives
Commodity contracts .................... Fair value of derivatives
Current Assets:
Interest rate contracts .................... Fair value of derivatives
Commodity contracts .................... Fair value of derivatives
Non-current Assets:
$ —
201
201
$ —
311
311
—
—
—
—
—
—
Current Liabilities:
Fair value of derivatives
Fair value of derivatives
Non-current Liabilities:
Fair value of derivatives
Fair value of derivatives
$ —
230
230
$ 923
—
923
—
171
171
—
—
—
- 106 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Fair Values of Derivative Instruments in the Consolidated Balance Sheet
Derivative Assets
Derivative Liabilities
Fair Values
December 31,
Fair Values
December 31,
Total derivatives designated as
hedging instruments
$ 201
$ 311
$ 401
$ 923
Balance Sheet Location
2010
2009
Balance Sheet Location
2010
2009
Derivatives not designated as
hedging instruments:
Interest rate contracts .................... Fair value of derivatives
Commodity contracts .................... Fair value of derivatives
Current Assets:
Interest rate contracts .................... Fair value of derivatives
Commodity contracts .................... Fair value of derivatives
Non-current Assets:
Total derivatives not designated as
hedging instruments
$ 1,941
—
1,941
$ 1,286
275
1,561
—
—
—
—
—
—
Current Liabilities:
Fair value of derivatives
Fair value of derivatives
Non-current Liabilities:
Fair value of derivatives
Fair value of derivatives
$ —
51
51
$ 5,688
616
6,304
3,930
—
3,930
—
—
—
$ 2,142
$ 1,561
$ 3,981
$ 6,304
Effect of Derivative Instruments on the Consolidated Statement of Operations
For the Years Ended December 31, 2010, 2009 and 2008
Effective Portion
Ineffective Portion and Amount
Excluded from Effectiveness Testing
Location of
Gain or
(Loss)
Reclassified
from
Accumulated
OCI into
Income
Amount of Gain or (Loss)
Reclassified from Accumulated
OCI into Income
Location of
Gain or
(Loss)
Recognized
in Income
on
Derivatives
Amount of Gain or (Loss)
Recognized in Income on
Derivatives
Amount of Gain or (Loss)
Recognized in OCI on Derivatives
2010
2009
2008
2010
2009
2008
2010
2009
2008
Derivatives
designated
as hedging
instruments
Interest rate
contracts .......
Commodity
contracts .......
Total
derivatives
designated
as hedging
instruments
(241)
$(1,854)
$ (5,435)
Interest
Expense
Natural Gas
Services Revenues
$ (4,210)
$(7,345)
$ —
143
14
4,219
547
2,667
(2,819)
Interest
Expense
Natural Gas
Services
Revenues
$ —
$ —
$ —
70
(21)
(224)
$ (98)
$(1,840)
$1,216
$ (3,663)
$ (4,678)
$ (2,819)
$ 70
$ (21)
$ (224)
- 107 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Location of Gain or (Loss)
Recognized in Income on
Derivatives
Amount of Gain or (Loss) Recognized in
Income on Derivatives
2010
2009
2008
Derivatives not designated as hedging
instruments
Interest rate contracts ..................................... Interest Expense
Commodity contracts..................................... Natural Gas Services Revenues
Total derivatives not designated as
hedging instruments
$(2,117)
219
$ (547)
(1,863)
$ (1,052)
4,041
$(1,898)
$ (2,410)
$ 2,989
Amounts expected to be reclassified into earnings for the subsequent twelve month period are losses of $18
for interest rate cash flow hedges and gains of $1,608 for commodity cash flow hedges.
(14) RELATED PARTY TRANSACTIONS
As of December 31, 2010, Martin Resource Management owns 5,703,823 of the Partnership’s common
units and 889,444 subordinated units collectively representing approximately 35.5% of the Partnership’s outstanding
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, 2010 of
approximately 35.5% 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 transactions:
Omnibus Agreement
Omnibus Agreement. The Partnership and its general partner are parties to an omnibus agreement dated
November 1, 2002 with Martin Resource Management that governs, among other things, potential competition and
indemnification obligations among the parties to the agreement, related party transactions, the provision of general
administration and support services by Martin Resource Management and our use of certain of Martin Resource
Management’s trade names and trademarks. The omnibus agreement was amended on November 24, 2009 to
include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other
intermediate cuts.
Non-Competition Provisions. Martin Resource Management has agreed for so long as it controls our
general partner, not to engage in the business of:
• providing terminalling, refining, processing, distribution and midstream logistical services for hydrocarbon
products and by-products;
• providing marine and other transportation of hydrocarbon products and by-products; and
• manufacturing and marketing fertilizers and related sulfur-based products.
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:
o providing land transportation of various liquids,
- 108 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
o distributing fuel oil, sulfuric acid, marine fuel and other liquids,
o providing marine bunkering and other shore-based marine services in Alabama, Louisiana,
Mississippi and Texas,
o operating a small crude oil gathering business in Stephens, Arkansas,
o operating an underground NGL storage facility in Arcadia, Louisiana,
o building and marketing sulfur processing equipment, and
o developing an underground natural gas storage facility in Arcadia, Louisiana;
•
•
•
any business that Martin Resource Management acquires or constructs that has a fair market value of less
than $5.0 million;
any business that Martin Resource Management acquires or constructs that has a fair market value of
$5.0 million or more if the Partnership has been offered the opportunity to purchase the business for fair
market value, and the Partnership declines to do so with the concurrence of the conflicts committee; and
any business that Martin Resource Management acquires or constructs where a portion of such business
includes a restricted business and the fair market value of the restricted business is $5.0 million or more and
represents less than 20% of the aggregate value of the entire business to be acquired or constructed;
provided that, following completion of the acquisition or construction, the Partnership will be provided the
opportunity to purchase the restricted business.
Services. Under the omnibus agreement, Martin Resource Management provides us with corporate staff,
support services, and administrative services necessary to operate our business. 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 the Partnership is
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, the Partnership is required to reimburse Martin
Resource Management for indirect general and administrative and corporate overhead expenses.
Effective October 1, 2010 through September 30, 2011, the Conflicts Committee of the board of directors
of our general partner (the “Conflicts Committee”) approved an annual reimbursement amount for indirect expenses
of $4.2 million. We reimbursed Martin Resource Management for $3.8, $3.5, and $2.9 million of indirect expenses
for the years ending December 31, 2010, 2009, and 2008, 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 us, such as accounting, treasury, clerical billing, information technology, administration
of insurance, general office expenses and employee benefit plans and other general corporate overhead functions 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 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 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.
- 109 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
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 24, 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 the Partnership will reimburse Martin
Resource Management for general and administrative services performed on our 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 with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which
Martin Resource Management operates its land transportation operations. This agreement replaced a prior
agreement effective November 1, 2002 between us and Martin Transport, Inc. for land transportation services.
Under the agreement, Martin Transport Inc. agreed to ship our NGL shipments as well as other liquid products.
Term and Pricing. This agreement was amended in November 2006, January 2007, April 2007 and January
2008 to add additional point-to-point rates and to modify certain fuel and insurance surcharges being charged to the
Partnership. 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 anytime 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 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 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. This
agreement replaced a prior agreement effective November 1, 2002 between the Partnership and Martin Resource
Management covering marine transportation services which expired November 2005. Effective each January 1, this
agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by
giving written notice to the other party at least 60 days prior to the expiration of the then applicable term. The fees
the Partnership charges Martin Resource Management are based on applicable market rates.
Cross Marine Charter Agreements. Cross entered into four marine charter agreements with the Partnership
effective March 1, 2007. These agreements have an initial term of five years and continue indefinitely thereafter
subject to cancellation after the initial term by either party upon a 30 day written notice of cancellation. The charter
hire payable under these agreements will be adjusted annually to reflect the percentage change in the Consumer
Price Index.
Marine Fuel. The Partnership is a party to an agreement with Martin Resource Management under which
Martin Resource Management provides the Partnership 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, the Partnership agreed to
purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management.
- 110 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
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 we charge 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.
Other Agreements
Cross Tolling Agreement. We are party to an agreement 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. The Partnership is party to an agreement under which Martin
Resource Management purchases and markets the sulfuric acid produced by the Partnership’s sulfuric acid
production plant at Plainview, Texas, and which is not consumed by the Partnership’s internal operations. This
agreement, which was amended and restated in August 2008, 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:
Revenues:
2010
2009
2008
Terminalling and storage...........................................................
Marine transportation ................................................................
$46,823
28,194
$19,998
19,370
$18,362
24,956
Product sales:
Natural gas services............................................................
7,686
238
4,024
- 111 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Sulfur services ....................................................................
Terminalling and storage ...................................................
7,146
166
14,998
$90,015
5,445
155
5,838
$45,206
22,631
49
26,704
$70,022
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....................................................
$79,321
16,061
298
$95,680
$56,914
12,583
287
$69,784
$ 92,322
13,282
533
$106,137
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....................................................
$26,730
2,245
5,271
15,040
$49,286
$20,464
1,491
4,496
10,833
$37,284
$22,586
1,625
3,737
9,713
$37,661
The impact of related party selling, general and administrative expenses is reflected in the consolidated
financial statement as follows:
Selling, general and administrative:
Natural gas services............................................................
Sulfur services ....................................................................
Indirect overhead allocation, net of reimbursement ...........
$ 4,729
2,398
3,791
$10,918
$ 1,116
2,504
3,542
$ 7,162
$ 880
2,508
2,896
$ 6,284
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 a distribution to Martin Resource
Management.
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 $4,369 was recorded as a distribution to Martin Resource
Management. These assets are located in Theodore, Alabama and Pascagoula, Mississippi.
The amount of related party interest expense reflected in the consolidated financial statement is $0, $872
and $1,656 for the years ending December 31, 2010, 2009 and 2008, respectively.
(15)
PARTNERS’ CAPITAL
As of December 31, 2010, partners’ capital consists of 17,707,832 common limited partner units,
representing a 93.3% partnership interest, 889,444 subordinated limited partner units, representing 4.7% partnership
interest and a 2% general partner interest. Martin Resource Management through a subsidiary, owned an
approximate 34.7% limited partnership interest consisting of 5,703,823 common limited partner units and 889,444
subordinated limited partner units and a 2% general partner interest.
- 112 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
The Partnership Agreement contains specific provisions for the allocation of net income and losses to each
of the partners for purposes of maintaining their respective partner capital accounts.
Distributions of Available Cash
The Partnership distributes all of its Available Cash (as defined in the Partnership Agreement) within 45
days after the end of each quarter to unitholders of record and to the general partner. Available Cash is generally
defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less the amount of cash
reserves its general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the
proper conduct of the 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.
(16)
GAIN ON DISPOSAL OF ASSETS
On April 30, 2009, the Partnership sold certain assets comprising the Mont Belvieu railcar unloading
facility, which yielded net proceeds from the sale in the amount of $19,610. The assets sold related to twenty railcar
spaces and a newly constructed major expansion that had not been placed in operation. The disposition was
comprised of property, plant and equipment and allocated goodwill included in the Partnership’s terminalling
segment with an aggregate carrying value of $14,329. This transaction yielded a gain on the sale of property, plant,
and equipment in the amount of $5,281. The gain is included in “other operating income” in the consolidated
statement of operations for the year ending December 31, 2009.
In September 2010, the Partnership received $349 from an indemnity escrow. The gain is included in
“other operating income” in the consolidated statement of operations for the year ending December 31, 2010.
Additionally, the Partnership expects to receive payment of $375 in April 2012, which represents payment from an
indemnity escrow resulting from the sale. The Partnership expects to record this amount as a gain in the respective
quarter. The Partnership paid down the outstanding revolving loans under its credit facility with the net cash
proceeds from this sale of assets. The amount paid down is available for future borrowings under the revolving
credit facility.
(17) GAIN ON INVOLUNTARY CONVERSION OF ASSETS
During the third quarter of 2008, several of the Partnership’s facilities in the Gulf of Mexico were in the
path of two major hurricanes, Hurricane Gustav and Hurricane Ike. Physical damage to the Partnership’s assets
caused by the hurricanes, as well as the related removal and recovery costs, are covered by insurance subject to a
deductible. Losses incurred as a result of a single hurricane (an “occurrence”) are limited to a maximum aggregate
deductible of $250 for flood damage and $1,000 minimum plus 2% of total insured value at each location for wind
damage. The partnership’s total flood coverage is $15,000 and total wind coverage is $100,000.
The most significant damage to the Partnership’s assets was sustained at the Neches location. Property
damage also occurred at the Partnership’s Galveston, Sabine Pass, Intracoastal City, Cameron East, Cameron West,
Freeport, Venice, Port Fourchon, Stanolind, Mont Belvieu, and Spindletop locations. Based on an analysis of the
damage as performed by the Partnership estimated its non-cash charge as $1,207 for all locations which is equal to
the net-book value of the damaged assets. A receivable was established for the expected insurance recovery equal to
the impairment charge and for all expenditures related to water damage less the for mentioned deductible.
The Partnership recognized a $1,207 estimated loss during the last half of 2008, which approximates the
Partnership’s hurricane deductible under its applicable insurance policies, incurred as a result of Hurricanes Gustav
and Ike. The loss is included in “operating expenses” in the consolidated statement of operations for the year ended
December 31, 2008.
- 113 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Insurance proceeds received as a result of the aforementioned claims exceeded net book value of the
Partnership’s assets determined to be impaired. During 2009, the Partnership received insurance proceeds of $2,224
for this involuntary conversion of assets, which resulted in a gain of $1,017 which is reported in other operating
income.
(18)
INCOME TAXES
The operations of a partnership are generally not subject to income taxes, except as discussed below,
because its income is taxed directly to its partners. Effective January 1, 2007, the Partnership is subject to the Texas
margin tax as described below. Woodlawn, a subsidiary of the Partnership, is subject to income taxes due to its
corporate structure. A current federal income tax benefit of $ 0 and $1,061 and a current federal income tax expense
of $239, related to the operation of the subsidiary, were recorded for the years ended December 31, 2010, 2009 and
2008, respectively. In connection with the Woodlawn acquisition, the Partnership also established deferred income
taxes of $8,964 associated with book and tax basis differences of the acquired assets and liabilities. The basis
differences are primarily related to property, plant and equipment.
The activities of the Cross assets prior to the acquisition by the Partnership were subject to federal and state
income taxes. Accordingly, income taxes have been included in the Cross assets operating results for 2008 and the
period from January 1, 2009 through November 24, 2009. Related payables/receivables are included in Due to
affiliates and Other current assets, respectively, on the consolidated balance sheet.
A deferred tax benefit of $415 and a deferred tax expense of $294 and $2,442 related to the Woodlawn
basis differences and the basis differences of the Cross assets was recorded for the years ended December 31, 2010,
2009 and 2008, respectively. A deferred tax liability of $ 8,213 and $8,628 related to these basis differences existed
at December 31, 2010 and 2009, respectively. A deferred tax asset related to the activities of the Cross assets of
$165 is included in Other current assets at December 31, 2008.
In 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state
business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new
“taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure,
the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the new 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 $932, $422 and $749 were recorded in income tax expense for the years ended December 31,
2010, 2009 and 2008, respectively.
An income tax receivable of $760 is included in Other current assets at December 31, 2010 and 2009. An
income tax liability of $811, $454 and $414 existed at December 31, 2010, 2009 and 2008, respectively.
The components of income tax expense (benefit) from operations recorded for the years ended December
31, 2010, 2009 and 2008 are as follows:
Current:
Federal .....................................................................................................
State .........................................................................................................
Deferred:
Federal .....................................................................................................
2010
2009
2008
$ — $ (311) $(1,879)
835
609
932
(1,044)
298
932
(415)
2,442
294
$ 517 $ 592 $ 1,398
(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
- 114 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
different products and services. The operating income of these segments is reviewed by the chief operating decision
maker to assess performance and make business decisions.
The accounting policies of the operating segments are the same as those described in Note 2 of the Notes to
Consolidated Financial Statements. The Partnership evaluates the performance of its reportable segments based on
operating income. There is no allocation of administrative expenses or interest expense.
Operating
Revenues
Intersegment
Eliminations
Operating
Revenues
After
Eliminations
Depreciation
and
Amortization
Operating
Income
(Loss) after
Eliminations
Capital
Expenditures
Year ended December 31, 2010:
Terminalling and storage ...............
Natural gas services .......................
Sulfur services ...............................
Marine transportation ....................
Indirect selling, general, and
$ 119,270
554,482
165,078
82,635
$ (4,354)
—
—
(4,993)
$ 114,916
554,482
165,078
77,642
$ 16,650
5,023
6,262
12,721
$ 14,256
5,616
20,166
6,524
administrative ............................
—
—
—
—
(6,386)
Total...........................................
$ 921,465
$ (9,347)
$ 912,118
$ 40,656
$ 40,176
Year ended December 31, 2009:
Terminalling and storage ...............
Natural gas services .......................
Sulfur services ...............................
Marine transportation ....................
Indirect selling, general, and
$ 109,513
408,989
79,631
72,103
$ (4,219)
(7)
(2)
(3,623)
$ 105,294
408,982
79,629
68,480
$ 15,717
4,527
6,151
13,111
$ 17,899
5,666
13,776
3,156
administrative ............................
—
—
—
—
(6,077)
Total...........................................
$ 670,236
$ (7,851)
$ 662,385
$ 39,506
$ 34,420
Year ended December 31, 2008:
Terminalling and storage ...............
Natural gas services .......................
Sulfur services ...............................
Marine transportation ....................
Indirect selling, general, and
$ 122,960
679,375
372,987
80,059
$ (4,189)
—
(1,038)
(3,710)
$ 118,771
679,375
371,949
76,349
$ 12,947
4,067
5,751
12,128
$ 11,399
3,725
37,180
5,570
administrative ............................
—
—
—
—
(5,510)
Total...........................................
$ 1,255,381
$ (8,937)
$1,246,444
$ 34,893
$ 52,364
$ 6,996
1,645
7,107
2,159
—
$ 17,907
$ 18,404
5,010
7,909
4,523
—
$ 35,846
$ 31,439
9,565
6,884
53,562
—
$101,450
The following table reconciles operating income to net income:
Operating income.............................................................
Equity in earnings of unconsolidated entities ..................
Interest expense ...............................................................
Other, net .........................................................................
Income taxes ....................................................................
Net income ...............................................................
2010
$ 40,176
9,792
(33,716)
287
(517)
$ 16,022
Year Ended December 31,
2009
$ 34,420
7,044
(18,995)
326
(592)
$ 22,203
2008
$ 52,364
13,224
(21,433)
801
(1,398)
$ 43,558
Revenues from one customer in the Natural gas services segment were $92,265, $72,492 and $103,424 for
the years ended December 31, 2010, 2009 and 2008, respectively.
Total assets by segment at December 31, 2010 and 2009 are as follows:
Total assets:
Terminalling and storage ...................................................
Natural gas services ...........................................................
Sulfur services ...................................................................
$ 188,234
314,815
138,224
$ 178,941
256,397
110,953
2010
2009
- 115 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Marine transportation ........................................................
Total assets......................................................................
2010
144,205
$ 785,478
2009
139,648
$ 685,939
Investments in unconsolidated entities totaled $98,217 and $80,582 at December 31, 2010 and 2009, respectively,
and are included in the natural gas services segment.
(20) QUARTERLY FINANCIAL INFORMATION
CONSOLIDATED QUARTERLY INCOME STATEMENT INFORMATION
First
Quarter
(Dollar in thousands, except per unit amounts)
Second
Quarter
Fourth
Quarter
(Unaudited)
Third
Quarter
2010
Revenues.......................................................................
Operating Income .........................................................
Equity in earnings of unconsolidated entities ...............
Net income....................................................................
Net income per limited partner unit ² ............................
$242,676
7,563
2,176
1,771
$ 0.04
$211,944
9,102
2,342
3,075
$ 0.10
$195,387
7,703
2,951
4,636
$ 0.19
$262,141
15,808
2,323
6,540
$ 0.30
First¹
Quarter
(Dollar in thousands, except per unit amounts)
Second¹
Quarter
Third¹
Quarter
Fourth¹
Quarter
2009
Revenues.......................................................................
Operating Income .........................................................
Equity in earnings of unconsolidated entities ...............
Net income....................................................................
Net income per limited partner unit ² ............................
$163,051
7,906
2,059
5,213
$ 0.28
$139,201
15,958
1,028
10,760
$ 0.48
$159,272
6,062
2,139
4,274
$ 0.26
$200,861
4,494
1,818
1,956
$ 0.13
First¹
Quarter
(Dollar in thousands, except per unit amounts)
Third¹
Quarter
Second¹
Quarter
Fourth¹
Quarter
2008
Revenues.......................................................................
Operating Income .........................................................
Equity in earnings of unconsolidated entities ...............
Net income....................................................................
Net income per limited partner unit ² ............................
$318,839
7,553
3,510
7,066
$ 0.51
$318,649
6,513
4,372
5,328
$ 0.25
$372,856
16,707
3,503
14,136
$ 0.88
$236,100
21,591
1,839
17,028
$ 1.08
¹ Financial information for 2008 and for the period January 1, 2009 through November 24, 2009 has been revised to include
results attributable to the Cross assets See Note 2(a) — Principles of Presentation and Consolidation
² Net income per limited partner unit is calculated as net income attributable to the limited partners, which excludes income
attributable to the Cross assets See Note 2(o) — Net Income per Unit
(21)
COMMITMENTS AND CONTINGENCIES
As a result of a routine inspection by the U.S. Coast Guard of the Partnership’s tug Martin Explorer at the
Freeport Sulfur Dock Terminal in Tampa, Florida, the Partnership was informed that an investigation was
commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq., and
the MARPOL Protocol 73/78 during the fourth quarter of 2007. The Partnership cooperated with the investigation
and no formal charges, fines and/or penalties have been asserted against the Partnership. Counsel representing the
- 116 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Partnership in this matter has informed the Partnership that the investigation is now finished and the matter has been
closed.
In addition to the foregoing, 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 May 2, 2008, the Partnership received a copy of a petition filed in the District Court of Gregg County,
Texas (the “Court”) by Scott D. Martin (the “Plaintiff”) against Ruben S. Martin, III (the “Defendant”) with respect to
certain matters relating to Martin Resource Management. The Defendant is an executive officer of Martin Resource
Management, the Plaintiff and the Defendant are executive officers of the Partnership’s general partner, the Defendant
is a director of both Martin Resource Management and the Partnership’s general partner, and the Plaintiff is a former
director of Martin Resource Management. The lawsuit alleged that the Defendant breached a settlement agreement with
the Plaintiff concerning certain Martin Resource Management matters and that the Defendant breached fiduciary duties
allegedly owed to the Plaintiff in connection with their respective ownership and other positions with Martin Resource
Management. Prior to the trial of this lawsuit, the Plaintiff dropped his claims against the Defendant relating to the
breach of fiduciary duty allegations. The Partnership is not a party to the lawsuit and the lawsuit does not assert any
claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations or (iii) against the
Defendant with respect to his service as an officer or director of the Partnership’s general partner.
In May 2009, the lawsuit went to trial and on June 18, 2009, the Court entered a judgment (the “Judgment”)
with respect to the lawsuit as further described below. In connection with the Judgment, the Defendant has advised us
that he has filed a motion for new trial, a motion for judgment notwithstanding the verdict and a notice of appeal. In
addition, on June 22, 2009, the Plaintiff filed a notice of appeal with the Court indicating his intent to appeal the
Judgment and in fact, has done such. The Defendant has further advised the Partnership that on June 30, 2009 he posted
a cash deposit in lieu of a bond and the judge has ruled that as a result of such deposit, the enforcement of any of the
provisions in the Judgment is stayed until the matter is resolved on appeal.
The Judgment awarded the Plaintiff monetary damages in the approximate amount of $3,200, attorney’s fees
of approximately $1,600 and interest. In addition, the Judgment grants specific performance and provides that the
Defendant is to (i) transfer one share of his Martin Resource Management common stock to the Plaintiff, (ii) take such
actions, including the voting of any Martin Resource Management shares which the Defendant owns, controls or
otherwise has the power to vote, as are necessary to change the composition of the board of directors of Martin
Resource Management from the current five-person board to a four-person board to consist of the Defendant and his
designee and the Plaintiff and his designee and (iii) take such actions as are necessary to change the trustees of the
Martin Resource Management Employee Stock Ownership Trust (the “MRMC ESOP Trust”) to just the Defendant and
the Plaintiff. The Judgment is directed solely at the Defendant and is not binding on any other officer, director or
shareholder of Martin Resource Management or any trustee of a trust owning Martin Resource Management shares.
The Judgment with respect to (ii) above terminated on February 17, 2010, and with respect to (iii) above on the 30th
day after the election by the Martin Resource Management shareholders of the first successor Martin Resource
Management board after February 17, 2010. However, any enforcement of the Judgment was stayed pending resolution
of the appeal relating to it. In 2010, the Martin Resource Management board of directors removed Ruben S. Martin III
and Scott D. Martin as trustees of the MRMC Employee Stock Ownership Plan and appointed the current trustees,
Melanie Mathews, Johnnie Murry, Gina Patterson and Wesley M. Skelton. An election of the Board of Directors of
Martin Resource Management occurred on June 18, 2010.
On November 3, 2010, the Court of Appeals, Sixth Appellate District of Texas at Texarkana, issued an
opinion on the appeal overturning the Judgment. The Appellate Court’s opinion specifically reversed the Judgment
and rendered a take-nothing judgment against the Plaintiff and in favor of the Defendant. The Plaintiff petitioned
the Supreme Court of Texas to hear his appeal from the Appellate Court, but no further action has been taken by the
parties or the courts.
On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of
themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district
court against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley M.
- 117 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Skelton, in their capacities as directors of Martin Resource Management (the “MRMC Director Defendants”), as well
as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to
their respective positions with Martin Resource Management, Robert Bondurant, Donald Neumeyer and Wesley
Skelton are officers of the Partnership’s general partner. The Partnership is not a party to this lawsuit, and it does not
assert any claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations or (iii) against
the MRMC Director Defendants or other MRMC Defendants with respect to their service to the Partnership.
The SDM Plaintiffs allege, among other things, that the MRMC Director Defendants have breached their
fiduciary duties owed to Martin Resource Management and the SDM Plaintiffs, entrenched their control of Martin
Resource Management and diluted the ownership position of the SDM Plaintiffs and certain other minority
shareholders in Martin Resource Management, and engaged in acts of unjust enrichment, excessive compensation,
waste, fraud and conspiracy with respect to Martin Resource Management. The SDM Plaintiffs seek, among other
things, to rescind the June 2008 issuance by Martin Resource Management of shares of its common stock under its
2007 Long-Term Incentive Plan to the Other MRMC Defendants, remove the MRMC Director Defendants as officers
and directors of Martin Resource Management, prohibit the Defendant, Wesley Skelton and Robert Bondurant from
serving as trustees of the MRMC Employee Stock Ownership Plan, and place all of the Martin Resource Management
common shares owned or controlled by the Defendant in a constructive trust that prohibits him from voting those
shares. The SDM Plaintiffs have amended their Petition to eliminate their claims regarding rescission of the issue by
Martin Resource Management of shares of its common stock to the MRMC Employee Stock Ownership Plan. The case
was abated in July 2009 during the pendency of a mandamus proceeding in the Texas Supreme Court. The Supreme
Court denied mandamus relief on November 20, 2009. As of March 2, 2011, this lawsuit is set to go to trial in July
2011.
The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2008 in a Gregg County,
Texas district court by the daughters of the Defendant against the Plaintiff, both individually and in his capacity as
trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that the Plaintiff has engaged
in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common
stock, and has breached his fiduciary duties owed to the plaintiffs, and who are beneficiaries of such trust, and (ii) a
separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela
Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively,
of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource
Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached
fiduciary duties owed to the plaintiff, who is the beneficiary of such trust, and seeks to remove Karen Yost as the
trustee of such trust. With respect to the lawsuit described in (i) above, the Partnership has been informed that the
Plaintiff has resigned as a trustee of the Ruben S. Martin, III Dynasty Trust. With respect to the lawsuit described in (ii)
above, Angela Jones Alexander amended her claims to include her grandmother, Margaret Martin, as a defendant, but
subsequently dropped her claims against Mrs. Martin. Additionally, all claims pertaining to Karen Yost have been
resolved. All claims pertaining to Defendant have been preliminarily resolved, as the court, on February 9, 2011,
issued an order that granted the parties’ Joint Motion for Administrative Closure. With respect to the lawsuit
referenced in (i) above, the case was tried in October 2009 and the jury returned a verdict in favor of the Defendant’s
daughters against the Plaintiff in the amount of $4,900. On December 22, 2009, the court entered a judgment, reflecting
an amount consistent with the verdict and additionally awarded attorneys’ fees and interest. On January 7, 2010, the
court modified its original judgment and awarded the Defendant’s daughters approximately $2,700 in damages,
including interest and attorneys’ fees. The Plaintiff has appealed the judgment.
On September 24, 2008, Martin Resource Management removed Plaintiff as a director of the general partner
of the Partnership. Such action was taken as a result of the collective effect of Plaintiff’s then recent activities, which
the board of directors of Martin Resource Management determined was detrimental to both Martin Resource
Management and the Partnership. The Plaintiff does not serve on any committees of the board of directors of the
Partnership’s general partner. The position on the board of directors of the Partnership’s general partner vacated by the
Plaintiff may be filled in accordance with the existing procedures for replacement of a departing director utilizing the
Nominations Committee of the board of directors of the general partner of the Partnership. This position on the board
of directors has been filled as of July 26, 2010 by Charles Henry “Hank” Still.
On February 22, 2010 as a result of the Harris County Litigation being derivative in nature, Martin Resource
Management formed a special committee of its board of directors and designated such committee as the Martin
Resource Management authority for the purpose of assessing, analyzing and monitoring the Harris County Litigation
- 118 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
and any other related litigation and making any and all determinations in respect of such litigation on behalf of Martin
Resource Management. Such authorization includes, but is not limited to, reviewing the merits of the litigation,
assessing whether to pursue claims or counterclaims against various persons or entities, assessing whether to appoint or
retain experts or disinterested persons to make determinations in respect of such litigation, and advising and directing
Martin Resource Management’s general counsel and outside legal counsel with respect to such litigation. The special
committee consists of Robert Bondurant, Donald R. Neumeyer and Wesley M. Skelton.
On May 4, 2010, the Partnership received a copy of a petition filed in a new case with the District Clerk of
Gregg County, Texas by Martin Resource Management against the Plaintiff and others with respect to certain
matters relating to Martin Resource Management. As noted above, the Plaintiff is a former director of Martin
Resource Management. The lawsuit alleges that the Plaintiff and others (i) willfully and intentionally interfered
with existing Martin Resource Management contracts and the prospective business relationships of Martin Resource
Management and (ii) published disparaging statements to third-parties with business relationships with Martin
Resource Management, which constituted slander and business disparagement. The Partnership is not a party to the
lawsuit, and the lawsuit does not assert any claims (i) against the Partnership, (ii) concerning the Partnership’s
governance or operations or (iii) against the Plaintiff with respect to his service as an officer or former director of
the general partner of the Partnership.
(22)
CONSOLIDATING FINANCIAL STATEMENTS
In connection with the Partnership’s filing of a shelf registration statement on Form S-3 with the Securities
and Exchange Commission (the “Registration Statement”), Martin Operating Partnership L.P. (the “Operating
Partnership”), the Partnership’s wholly-owned subsidiary, may issue unconditional guarantees of senior or
subordinated debt securities of the Partnership in the event that the Partnership issues such securities from time to
time under the Registration Statement. If issued, the guarantees will be full, irrevocable and unconditional. In
addition, the Operating Partnership may also issue senior or subordinated debt securities under the Registration
Statement which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. The
Partnership does not provide separate financial statements of the Operating Partnership because the Partnership has
no independent assets or operations, the guarantees are full and unconditional and the other subsidiary of the
Partnership is minor. There are no significant restrictions on the ability of the Partnership or the Operating
Partnership to obtain funds from any of their respective subsidiaries by dividend or loan.
(23)
SUBSEQUENT EVENTS
Acquisition of Certain Terminalling Assets. 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. The net book value of the acquired assets was recorded in property, plant and
equipment. These assets are located across the Louisiana Gulf Coast. This acquisition was funded by borrowings
under the Partnership’s revolving loan facility.
Public Offering. 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). Following this offering, the common units
represented a 95.7% limited partnership interest in the Partnership. Total proceeds from the sale of the 1,874,500
common units, net of underwriters’ discounts, commissions and offering expenses were $70,650. 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. On February 9, 2011, the Partnership made a $65,500 payment to
reduce the outstanding balance under its revolving credit facility.
- 119 -
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 Rule 13a-15(e) of the Exchange
Act) as of December 31, 2010. 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, 2010.
(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, 2010. The effectiveness of our internal
control over financial reporting as of December 31, 2010 has been audited by KPMG LLP, our independent registered
public accounting firm, as stated in their report appearing on page 78.
There were no changes in our internal controls over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) 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
Existing Litigation at Martin Resource Management. On May 2, 2008, we received a copy of a petition filed
in the District Court of Gregg County, Texas (the “Court”) by Scott D. Martin (the “Plaintiff”) against Ruben S.
Martin, III (the “Defendant”) with respect to certain matters relating to Martin Resource Management. The Defendant
is an executive officer of Martin Resource Management, the Plaintiff and the Defendant are executive officers of our
general partner, the Defendant is a director of both Martin Resource Management and our general partner, and the
Plaintiff is a former director of Martin Resource Management. The lawsuit alleged that the Defendant breached a
settlement agreement with the Plaintiff concerning certain Martin Resource Management matters and that the
Defendant breached fiduciary duties allegedly owed to the Plaintiff in connection with their respective ownership and
other positions with Martin Resource Management. Prior to the trial of this lawsuit, the Plaintiff dropped his claims
against the Defendant relating to the breach of fiduciary duty allegations. We are not a party to the lawsuit and the
lawsuit does not assert any claims (i) against us, (ii) concerning our governance or operations or (iii) against the
Defendant with respect to his service as an officer or director of our general partner.
In May 2009, the lawsuit went to trial and on June 18, 2009, the Court entered a judgment (the “Judgment”)
with respect to the lawsuit as further described below. In connection with the Judgment, the Defendant has advised us
that he has filed a motion for new trial, a motion for judgment notwithstanding the verdict and a notice of appeal. In
addition, on June 22, 2009, the Plaintiff filed a notice of appeal with the Court indicating his intent to appeal the
Judgment. The Defendant has further advised us that on June 30, 2009 he posted cash deposit in lieu of a bond and the
judge has ruled that as a result of such deposit, the enforcement of any of the provisions in the Judgment is stayed until
the matter is resolved on appeal.
The Judgment awarded the Plaintiff monetary damages in the approximate amount of $3.2 million, attorney’s
fees of approximately $1.6 million and interest. In addition, the Judgment grants specific performance and provides that
the Defendant is to (i) transfer one share of his Martin Resource Management common stock to the Plaintiff, (ii) take
such actions, including the voting of any Martin Resource Management shares which the Defendant owns, controls or
otherwise has the power to vote, as are necessary to change the composition of the board of directors of Martin
- 120 -
Resource Management from the current five-person board to a four-person board to consist of the Defendant and his
designee and the Plaintiff and his designee and (iii) take such actions as are necessary to change the trustees of the
Martin Resource Management Employee Stock Ownership Trust (the “MRMC ESOP Trust to just the Defendant and
the Plaintiff. The Judgment is directed solely at the Defendant and is not binding on any other officer, director or
shareholder of Martin Resource Management or any trustee of a trust owning Martin Resource Management shares.
The Judgment with respect to (ii) above terminated on February 17, 2010, and with respect to (iii) above on the 30th
day after the election by the Martin Resource Management shareholders of the first successor Martin Resource
Management board after February 17, 2010. However, any enforcement of the Judgment was stayed pending resolution
of the appeal relating to it. In 2010, the Martin Resource Management board of directors removed Ruben S. Martin III
and Scott D. Martin as trustees of the MRMC Employee Stock Ownership Plan and appointed the current trustees,
Melanie Mathews, Johnnie Murry, Gina Patterson and Wesley M. Skelton. An election of the Board of Directors of
Martin Resource Management occurred on June 18, 2010.
On November 3, 2010, the Court of Appeals, Sixth Appellate District of Texas at Texarkana, issued an
opinion on the appeal overturning the Judgment. The Appellate Court’s opinion specifically reversed the Judgment
and rendered a take-nothing judgment against the Plaintiff and in favor of the Defendant. The Plaintiff petitioned
the Supreme Court of Texas to hear his appeal from the Appellate Court, but no further action has been taken by the
parties or the courts.
On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of
themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district
court against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley M.
Skelton, in their capacities as directors of Martin Resource Management (the “MRMC Director Defendants”), as well
as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to
their respective positions with Martin Resource Management, Robert D. Bondurant, Donald R. Neumeyer and Wesley
M. Skelton are officers of our general partner. We are not a party to this lawsuit, and it does not assert any claims (i)
against us, (ii) concerning our governance or operations or (iii) against the MRMC Director Defendants or other
MRMC Defendants with respect to their service to us.
The SDM Plaintiffs allege, among other things, that the MRMC Director Defendants have breached their
fiduciary duties owed to Martin Resource Management and the SDM Plaintiffs, entrenched their control of Martin
Resource Management and diluted the ownership position of the SDM Plaintiffs and certain other minority
shareholders in Martin Resource Management, and engaged in acts of unjust enrichment, excessive compensation,
waste, fraud and conspiracy with respect to Martin Resource Management. The SDM Plaintiffs seek, among other
things, to rescind the June 2008 issuance by Martin Resource Management of shares of its common stock under its
2007 Long-Term Incentive Plan to the Other MRMC Defendants, remove the MRMC Director Defendants as officers
and directors of Martin Resource Management, prohibit the Defendant, Wesley M. Skelton and Robert D. Bondurant
from serving as trustees of the MRMC Employee Stock Ownership Plan, and place all of the Martin Resource
Management common shares owned or controlled by the Defendant in a constructive trust that prohibits him from
voting those shares. The SDM Plaintiffs have amended their Petition to eliminate their claims regarding rescission of
the issue by Martin Resource Management of shares of its common stock to the MRMC Employee Stock Ownership
Plan. The case was abated in July 2009 during the pendency of a mandamus proceeding in the Texas Supreme Court.
The Supreme Court denied mandamus relief on November 20, 2009. As of March 2, 2011, this lawsuit is set to go to
trial in July 2011.
The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2009 in a Gregg County,
Texas district court by the daughters of the Defendant against the Plaintiff, both individually and in his capacity as
trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that the Plaintiff has engaged
in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common
stock, and has breached his fiduciary duties owed to the plaintiffs, and who are beneficiaries of such trust, and (ii) a
separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela
Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively,
of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource
Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached
fiduciary duties owed to the plaintiff, who is the beneficiary of such trust, and seeks to remove Karen Yost as the
trustee of such trust. With respect to the lawsuit described in (i) above, we have been informed that the Plaintiff has
- 121 -
resigned as a trustee of the Ruben S. Martin, III Dynasty Trust. With respect to the lawsuit described in (ii) above,
Angela Jones Alexander has amended her claims to include her grandmother, Margaret Martin, as a defendant, but
subsequently dropped her claims against Mrs. Martin. Additionally, all claims pertaining to Karen Yost have been
resolved. All claims pertaining to Defendant have been preliminarily resolved, as the court, on February 9, 2011,
issued an order that granted the parties’ Joint Motion for Administrative Closure. With respect to the lawsuit
referenced in (i) above, the case was tried in October 2009 and the jury returned a verdict in favor of the Defendant’s
daughters against the Plaintiff in the amount of $4.9 million. On December 22, 2009, the court entered a judgment,
reflecting an amount consistent with the verdict and additionally awarded attorneys’ fees and interest. On January 7,
2010, the court modified its original judgment and awarded the Defendant’s daughters approximately $2.7 million in
damages, including interest and attorneys’ fees. The Plaintiff has appealed the judgment.
On September 24, 2008, Martin Resource Management removed Plaintiff as a director of our general partner.
Such action was taken as a result of the collective effect of Plaintiff’s then recent activities, which the board of directors
of Martin Resource Management determined was detrimental to both Martin Resource Management and us. The
Plaintiff does not serve on any committees of the board of directors of our general partner. The position on the board of
directors of our general partner vacated by the Plaintiff may be filled in accordance with the existing procedures for
replacement of a departing director utilizing the Nominations Committee of the board of directors of our general
partner. This position on the board of directors has been filled as of July 26, 2010 by Charles Henry “Hank” Still.
On February 22, 2010 as a result of the Harris County Litigation being derivative in nature, Martin Resource
Management formed a special committee of its board of directors and designated such committee as the Martin
Resource Management authority for the purpose of assessing, analyzing and monitoring the Harris County Litigation
and any other related litigation and making any and all determinations in respect of such litigation on behalf of Martin
Resource Management. Such authorization includes, but is not limited to, reviewing the merits of the litigation,
assessing whether to pursue claims or counterclaims against various persons or entities, assessing whether to appoint or
retain experts or disinterested persons to make determinations in respect of such litigation, and advising and directing
Martin Resource Management’s general counsel and outside legal counsel with respect to such litigation. The special
committee consists of Robert Bondurant, Donald R. Neumeyer and Wesley M. Skelton.
On May 4, 2010, we received a copy of a petition filed in a new case with the District Clerk of Gregg County,
Texas by Martin Resource Management against the Plaintiff and others with respect to certain matters relating to
Martin Resource Management. As noted above, the Plaintiff is a former director of Martin Resource Management.
The lawsuit alleges that the Plaintiff and others (i) willfully and intentionally interfered with existing Martin Resource
Management contracts and the prospective business relationships of Martin Resource Management and (ii) published
disparaging statements to third-parties with business relationships with Martin Resource Management, which
constituted slander and business disparagement. We are not a party to the lawsuit, and the lawsuit does not assert any
claims (i) against us, (ii) concerning our governance or operations or (iii) against the Plaintiff with respect to his service
as an officer or former director of our general partner.
- 122 -
Item 10. Directors, Executive Officers and Corporate Governance
Management of Martin Midstream Partners L.P.
PART III
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 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. The current
members of our Conflicts Committee, nominating committee and compensation 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, Howard Hackney 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, Howard Hackney and Charles H. Still.
The current members of our nominating committee are our outside directors, Joe N. Averett, Jr, Howard
Hackney 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.
Executive officers and directors are elected for one-year terms.
- 123 -
Name
Age
Position with the General Partner
Ruben S. Martin
Robert D. Bondurant
Donald R. Neumeyer
Wesley M. Skelton
Randy Tauscher
Chris Booth
C. Scott Massey
Howard Hackney
Joe N. Averett, Jr.
Charles H. Still
59
52
63
63
45
41
58
71
68
68
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
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.
Donald R. Neumeyer serves as Executive Vice President and Chief Operating Officer of our general partner.
Mr. Neumeyer has served in such capacities since June 2002. Mr. Neumeyer joined Martin Resource Management in
March of 1982 as an operations manager. He has served as Vice President of Operations and Chief Operating Officer
since 1983 and as a Director since 1990. From 1978 to 1982 Mr. Neumeyer was employed by Crystal Oil Company of
Shreveport, Louisiana as Vice President of Marketing, Refining and Gas Processing. From 1970 to 1978 Mr.
Neumeyer was employed by Mobil Oil Corporation in various capacities within its pipeline, crude oil, and gas liquid
operations. Mr. Neumeyer holds a bachelor of science in mechanical engineering from Southern Methodist University
in Dallas and is a registered professional engineer in the state of Texas.
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.
Randy Tauscher serves as Executive Vice President of our general partner. Mr. Tauscher has served in this
capacity since November 1, 2007. 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.
Chris Booth serves as Vice President, General Counsel and Secretary of our general partner. Mr. Booth has
served in the capacities of Vice President and General Counsel since February 2006 and in the capacity of Secretary
since November 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 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.
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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 juris doctor 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.
Howard Hackney serves as a member of the Board of Directors of our general partner. Mr. Hackney has
served as a Director since May 2005. Mr. Hackney currently serves as a director of Texas Bank and Trust of Longview,
Texas and Federal Home Loan Bank of Dallas, Texas, where he is the Chairman of the Audit Committee and a member
of the Executive and Human Resources Committees. His past experience includes service as the President of Texas
Bank and Trust of Longview, Texas, President of Bank One of Longview, Texas, President and a director of Merchant
and Planters National Bank of Sherman, Texas and Executive Vice President and a director of Capital National Bank of
Houston, Texas. Mr. Hackney received a BBA and MBA from Southern Methodist University. Mr. Hackney was
selected to serve as a director on our general partner’s Board of Directors due to his business and financial expertise,
which is a product of his extensive finance and management background.
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 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 BBA
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. Mr. Still is a partner and head of the Houston corporate practice group in the law firm Kelly
Hart & Hallman LLP, having more than 40 years of experience in multiple aspects of corporate law. Prior to joining
Kelly Hart & Hallman LLP in 2008, Mr. Still was an associate and partner in the law firm Fulbright & Jaworski L.L.P.
from 1968 until his retirement in 2008. Mr. Still is currently on the board of directors of OYO Geospace Corporation.
Mr. Still holds a J.D. from the University of Texas School of Law and a B.B.A. in accounting from Texas Tech
University. He is an Adjunct Professor of Law at the University of Texas School of Law. Mr. Still was selected to
serve as a director on our general partner’s Board of Directors due to his extensive corporate legal experience.
Independence of Directors
Messrs. Massey, Hackney, and Still 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, 2010 to December 31, 2010, the Board of Directors of our general partner held 17 meetings.
All directors then in office attended each of these meetings, either in person, by teleconference or by videoconference.
Additionally, the Board of Directors undertook action five times during 2010 without a meeting by acting through
written unanimous consent. We have standing conflicts, audit, compensation and nominating committees of the Board
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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 “Governance” section. The current members of the committees, the number of meetings held by each committee
from January 1, 2010 to December 31, 2010, and a brief description of the functions performed by each committee are
set forth below:
Conflicts Committee (8 meetings). The members of the Conflicts Committee are Messrs. Averett (chairman),
Massey and Still. All of the members of the Conflicts Committee attended all meetings of the committee for the period
noted above. The primary responsibility of the Conflicts Committee is to review matters that the directors believe may
involve conflicts of interest. The Conflicts Committee determines if the resolution of the conflict of interest is fair and
reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or
directors, officers, or employees of its affiliates and must meet the independence standards to serve on an audit
committee of a board of directors established by NASDAQ; provided, however that a director with a family member
who is a partner with a foreign affiliate in the international cooperative of our registered independent public accounting
firm shall be deemed to meet such independence standards if such director meets all other independence standards of
NASDAQ and the board of our general partner affirmatively determines that such family relationship will not impair
such director’s independent judgment as a member of the Conflicts Committee. Any matters approved by the Conflicts
Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a
breach by our general partner of any duties it may owe us or our unitholders.
Audit Committee (4 meetings). The members of the audit committee are Messrs. Massey (chairman), Still and
Hackney. 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. Hackney
(chairman), Massey, Still and Averett. 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 (5 meetings). The members of the nominating committee are Messrs. Still (chairman),
Averett and Hackney. The primary responsibility of the nominating committee is to select and recommend nominees
for election to the Board of Directors of our general partner.
Compensation of Directors
Officers of our general partner who also serve as directors will not receive additional compensation. Non-
employee directors of our general partner are entitled to receive total annual retainer fees of $35,000. 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.
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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 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, 2010, 2011, 2012 and 2013, respectively. 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. These
restricted common units vest in equal installments of 250 units on January 24, 2009, 2010, 2011 and 2012. On May
3, 2007, 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,
2008, 2009, 2010 and 2011, respectively. On January 24, 2006, 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, 2007, 2008, 2009 and 2010, respectively.
Compensation Committee Interlocks and Insider Participation
In addition to the current members of the compensation committee of our general partner that are identified
above , John Gaylord served on the compensation committee until his resignation in May 2010. 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.
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 “Governance” section (at www.martinmidstream.com). This website address is intended to be an
inactive, textual reference only, and none of the material on this website is part of this report. If any substantive
amendments are made to the Code of Ethics and Business Conduct or if we or our general partner grant any waiver,
including any implicit waiver, from a provision of the code to any of our general partner’s executive officers and
directors, we will disclose the nature of such amendment or waiver on that website or in a report on Form 8-K.
Section 16(a) Beneficial Ownership Reporting Compliance
Our general partner’s directors and officers, and beneficial owners of more than 10% of a registered class of
our equity securities are required to file reports of ownership and reports of changes in ownership with the SEC and
NASDAQ. Directors, officers and beneficial owners of more than 10% of our equity securities are also required to
furnish us with copies of all such reports that are filed. Based solely on our review of copies of such forms and
amendments, we believe directors, officers and greater than 10% beneficial owners complied with all filing
requirements during the year ended December 31, 2010, except as follows: five reports on Form 4 following the sale of
common units by subsidiaries of Martin Resource Management Corporation in August 2010 were filed late by each of
Martin Resource LLC, Cross Oil Refining and Marketing, Inc., Martin Resource Management Corporation, Ruben
Martin and Scott Martin, and one report on Form 4 following allocations pursuant to a benefit plan of Martin Resource
Management was filed late by Scott Martin. In addition, two reports on Form 4 following allocations pursuant to a
benefit plan of Martin Resource Management were not filed by Scott Martin.
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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 $81.7 million of direct costs and expenses for the twelve months ended December 31, 2010
compared to $63.1 million for the twelve months ended December 31, 2009. 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, 2010, 2009
and 2008, the Conflicts Committee of our general partner approved reimbursement amounts of $3.8, $3.5 and $2.9
million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and
approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.
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,
2010, 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. 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, 2010, 2009 and 2008, the Conflicts Committee of our general partner approved
reimbursement amounts of $3.8, $3.5 and $2.9 million, respectively, reflecting our allocable share of such expenses.
Please see “Item 13. Certain Relationships and Related Transactions, and Director Independence — Agreements —
Omnibus Agreement” for a discussion of the omnibus agreement.
Compensation Objectives
As we do not directly compensate the executive officers of our general partner, we do not have any set
compensation programs. The elements of Martin Resource Management’s compensation program discussed below,
along with Martin Resource Management’s other rewards, are intended to provide a total rewards package designed
to yield competitive total cash compensation, drive performance and reward contributions in support of the
businesses of Martin Resource Management and other Martin Resource Management affiliates, including us, for
which the Named Executive Officers perform services. Although we bear an allocated portion of Martin Resource
Management’s costs of providing compensation and benefits to the Named Executive Officers, we do not have
control over such costs and do not establish or direct the compensation policies or practices of Martin Resource
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Management. During 2010, 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 inventive 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, car allowances and use of Martin Resource Management vehicles, 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
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business and affairs of our general partner and to the business and affairs of Martin Resource Management. We bear
substantially less than a majority of Martin Resource Management’s costs of providing compensation and benefits to
the Named Executive Officers.
When setting compensation for the Named Executive Officers, the elements of compensation above are
considered holistically to provide an appropriate combination of compensation. Annual base salaries are determined
by the compensation committee of Martin Resource Management following an individual performance review of
each Named Executive Officer. Further, Martin Resource Management, with the approval of Mr. Ruben Martin, the
Chief Executive Officer of Martin Resource Management, normally reviews market data and relevant compensation
surveys when setting base compensation and, when appropriate, engages compensation consultants. Except in the
case of an exceptional amount of time devoted to us, discretionary annual cash awards are based on the performance
of Martin Resource Management. Annual discretionary cash awards, if any, are calculated first by allocating a
portion of Martin Resource Management’s earnings as determined by Martin Resource Management’s compensation
committee for distribution to key employees of Martin Resource Management. Upon such allocation, Mr. Martin
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 only of the grant of
restricted common units to the independent directors of our general partner, are approved by the compensation
committee. Other than the restricted units granted to directors, we do not anticipate that we will grant any awards
under our long-term incentive plan to employees of Martin Resource Management at this time.
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. Donald Neumeyer, Chief Operating Officer, Mr. Wesley Skelton, Chief Administrative Officer 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 2010 Compensation Amounts
With respect to compensation objectives and decisions regarding the Named Executive Officers during
2010, Martin Resource Management took note of market data for determining relevant compensation levels and
compensation program elements through the review of and, in certain cases, participation in, various relevant
compensation surveys. Martin Resource Management analyzed the compensation of similarly situated employees of
the general partners or sponsors of Amerigas Partners LP, Atlas Pipeline Partners LP, Boardwalk Pipeline Partners
LP, Buckeye GP Holdings L.P., Calumet Specialty Products Partners, Copano Energy L.L.C., Crosstex Energy LP,
DCP Midstream LP, Ferrell Gas Partners LP, Genesis Energy LP, Global Partners LP, Hiland Partners LP, Inergy
LP, Magellan Midstream Partners LP, Markwest Energy Partners LP, Oneok Partners LP, Regency Energy Partners
LP, Star Gas Partners LP and Suburban Propane Partners LP. In addition, Martin Resource Management engaged
the services of the internationally recognized Hay Group in analyzing compensation for its executive officers,
including the Named Executive Officers. However, Martin Resource Management does not “benchmark” its
compensation packages, and the ultimate determination of any compensation is subject to the discretion of Martin
Resource Management’s compensation committee, and ultimately, its Chief Executive Officer.
During 2010, 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.
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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
16.8% of the aggregate annual base salaries paid to the Named Executive Officers by Martin Resource Management
during 2010. 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 19% to 60%. 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. Donald Neumeyer, an Executive Vice President and Chief
Operating 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 of our general
partner and Mr. Chris Booth, the Vice President, General Counsel and Secretary of our general partner. Annual base
salaries of the Named Executive Officers were not increased in 2010 by Martin Resource Management.
Discretionary Annual Cash Awards. Discretionary annual cash awards paid to the Named Executive
Officers which are allocable to us are reflected in the summary compensation table below. A discretionary annual
cash award was granted by Martin Resource Management to Mr. Tauscher based upon the substantial amount of
time he devoted to us in 2010. This was the only such award granted in 2010.
Employee Benefit Plan Awards and Other Compensation. No employee benefit plan awards or other
compensation were granted to the Named Executive Officers in 2010 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 for
employees and directors of our general partner and its affiliates who perform services for us. The long-term
incentive plan was amended in January 2006 to clarify the Partnership’s ability to grant restricted common units
under the long-term incentive plan and to remove provisions relating to grants of distribution equivalent rights and
phantom units.
The long-term incentive plan consists of two components, restricted units and unit options. The long-term
incentive plan currently permits the grant of awards covering an aggregate of 725,000 common units, 241,667 of
which may be awarded in the form of restricted units and 483,333 of which may be awarded in the form of unit
options. The plan is administered by the compensation committee of 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 long-term incentive plan 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
long-term incentive plan 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.
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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 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 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, 2010, 2011, 2012 and 2013, respectively. On May 5, 2008, 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, 2009, 2010, 2011 and 2012,
respectively. On May 3, 2007, 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, 2008, 2009, 2010 and 2011, respectively. On January 24, 2006, we issued 1,000 restricted
common units to each of our three independent directors. These restricted common units vest in equal installments
of 250 units on each of the four anniversaries following the grant date. All equity-based awards under our long-term
incentive plan given to our independent directors were approved by the compensation committee.
Unit Options. The long-term incentive plan currently permits the grant of options covering common units.
As of March 2, 2011, 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.
- 132 -
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 ownership plan that covers employees who satisfy certain minimum age and service
requirements. This employee stock ownership plan is referred to as the “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 ESOP 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 ESOP.
Martin Resource Management 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 Phantom Stock Plan. Under Martin Resource Management’s phantom stock
plan, phantom stock units granted thereunder have a ten year life and are non-transferable. Each recipient may
exercise an election to receive either
• an equivalent number of shares of Martin Resource Management, or
• cash based on the latest valuation of the shares of common stock of Martin Resource
Management held by the ESOP.
Any common stock of Martin Resource Management received under this phantom stock plan cannot be
pledged or encumbered. The recipient must sign an agreement waiving any voting rights with respect to shares
received under this plan. Cash distributions are paid in lump-sum or in five equal annual installment, at the election
of the employee. A put option, exercisable at the then fair market value of the common stock, is exercisable by the
employee in the event Martin Resource Management is sold prior to an employee’s election to receive common
stock or cash.
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,
- 133 -
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, car
allowances, 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 periods from January 1, 2010 to December 31, 2010, January 1, 2009 to December
31, 2009 and January 1, 2008 to December 31, 2008.
Name and
Principal Position
Year
Salary ($)
Bonus ($)
Total Compensation
Ruben S. Martin
President and Chief Executive Officer
2010
$100,099
$ -
$100,099
Robert D. Bondurant
Executive Vice President
and Chief Financial Officer
2009
2008
2010
2009
2008
$91,579
$ -
$91,579
$73,500
$ -
$73,500
$53,857
$ -
$53,857
$40,972
$38,040
$ -
$ -
$40,972
$38,040
Donald R. Neumeyer
Executive Vice President and Chief Operating Officer
2010
$52,653
$ -
$52,653
Wesley M. Skelton
Executive Vice President, Controller and Chief Administrative Officer
Randall L. Tauscher
Executive Vice President
$44,296
$ -
$44,296
$37,283
$ -
$37,283
$117,404
$ -
$117,404
$118,544
$ -
$118,544
$108,358
$ -
$108,358
$163,644
$107,500
$271,144
$242,282
$120,000
$363,282
$300,000
$300,000
$600,000
2009
2008
2010
2009
2008
2010
2009
2008
- 134 -
Name and
Principal Position
Year
Salary ($)
Bonus ($)
Total Compensation
Chris H. Booth
Vice President, General Counsel and Secretary
2010
2009
2008
$86,830
$ -
$86,830
$82,225
$ -
$82,225
$77,625
$ -
$77,625
Director Compensation
As a partnership, we are managed by our general partner. The board of directors of our general partner
performs for us the functions of a board of directors of a business corporation. We are allocated 100 percent of the
director compensation of these board members. Martin Resource Management employees who are a member of the
board of directors of our general partner do not receive any additional compensation for serving in such capacity.
The following table sets forth the compensation of our board members for the period from January 1, 2010 through
December 31, 2010.
Name
Fees Earned Paid in
Cash ($)
Stock
Awards ($)(¹,²)
Total ($)
Ruben S. Martin
John P. Gaylord
C. Scott Massey
Howard Hackney
Joe N. Averett, Jr.
Charles H. “Hank” Still
____________
N/A
$17,500
$35,000
$35,000
$17,500
$17,500
N/A
N/A
$32,400¹
$49,900
$32,400¹
$32,400¹
$49,920²
$49,920²
$67,400
$67,400
$67,420
$67,420
(1) On May 3, 2010, we issued 1,000 restricted common units to each of our three non-employee, directors,
John P. Gaylord, C. Scott Massey and Howard Hackney, 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. In calculating the fair value of the award, we multiplied the closing price of our common units
on the NASDAQ on the date of grant, May 3, 2010, by the number of restricted common units granted to
each director.
(2) On August 2, 2010, we issued 1,500 restricted common units to each of two new non-employee, directors,
Joe N. Averett, Jr and Charles H. “Hank” Still, 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. 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, August 2, 2010, by the number of restricted common units granted to
each director.
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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.
/s/ Howard Hackney
Howard Hackney, Committee Chair
/s/ Joe N. Averett, Jr.
Joe N. Averett Jr.
/s/ C. Scott Massey
C. Scott Massey
/s/ Charles H. Still
Charles H. Still
- 136 -
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 2, 2011 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.
Common
Units
Beneficially
Owned
Percentage
of Common
Units
Beneficially
Owned(2)
Subordinated
Units
Beneficially
Owned
Percentage of
Subordinated
Units
Beneficially
Owned
Percentage
of Total
Units
Beneficially
Owned(2)
Name of Beneficial Owner(1)
Martin Resource Management
Corporation(3) ................................
Martin Resource LLC(3) ........................
Cross Refining & Marketing Inc.(3) ......
Scott D. Martin(5) .................................
Keeneland Capital LLC
KCM LLC
Ruben S. Martin(4).................................
Donald R. Neumeyer..............................
Wesley M. Skelton .................................
Robert D. Bondurant ..............................
Chris Booth ............................................
Randall Tauscher....................................
C. Scott Massey(6)(7).............................
Howard Hackney(6) ...............................
Joe N. Averett, Jr.(6) .............................
Charles H. Still(6) .................................
All directors and executive officers as a
5,703,823
5,703,823
—
5,717,480
5,703,823
5,703,823
5,758,137
4,636
4,016
12,277
2,106
8,456
9,500
5,000
3,000
1,800
29.1%
29.1%
—
29.2%
29.1%
29.1%
29.4%
—
—
—
—
—
—
—
—
—
group (10 persons)(9) .....................
5,808,928
29.7%
____________
889,444
—
889,444
889,444
889,444
889,444
889,444
—
—
—
—
—
—
—
—
—
889,444
100%
100%
100%
100%
100%
100%
100%
—
—
—
—
—
—
—
—
—
100%
32.2%
27.9%
4.3%
27.9%
27.9%
27.9%
32.5%
—
—
—
—
—
—
—
—
—
32.7%
(1)
(2)
(3)
(4)
(5)
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.
The percent of class shown is less than one percent unless otherwise noted.
Martin Resource Management Corporation is the owner of Martin Resource LLC and Cross Refining &
Marketing Inc., and as such may be deemed to beneficially own the common units held by Martin Resource
LLC and the common and subordinated units held by Cross Refining & Marketing Inc. The 5,703,823
common units beneficially owned by Martin Resource Management Corporation 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 subordinated units beneficially owned by Martin Resource Management
Corporation through its ownership of Cross Refining & Marketing Inc. have been pledged as security to a
third party to secure payment for a loan made by such third party.
Includes 5,703,823 common units and 889,444 subordinated units beneficially owned by Martin Resource
Management Corporation through its ownership of Martin Resource LLC and Cross Oil Refining &
Marketing, Inc. Ruben S. Martin beneficially owns securities in Martin Resource Management
Corporation representing approximately 23.7% 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 Corporation.
Includes 5,703,823 common units and 889,444 subordinated units beneficially owned by Martin Resource
Management Corporation through its ownership of Martin Resource LLC and Cross Oil Refining &
Marketing, Inc. Scott D. Martin beneficially owns securities in Martin Resource Management Corporation
- 137 -
representing approximately 28.0% of the voting stock thereof. As a result, Scott D. Martin may be deemed
to be the beneficial owner of the common units and the subordinated units owned by Martin Resource
Management Corporation.
(6)
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.
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 500 common units held by his wife.
Based on a Schedule 13G (Amendment No. 6), dated October 20, 2010 filed by Kayne Anderson Capital
Advisors, L.P. with the United States Securities and Exchange Commission. The filing is made jointly
with Richard A. Kayne. The filers report that they have shared voting power with respect to the 871,007
common units. The address of Kayne Anderson Capital Advisors, L.P. is 1800 Avenue of the Stars,
Second Floor, Los Angeles, California 90067.
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 and subordinated units beneficially
owned by Martin Resource Management Corporation as Ruben S. Martin may be deemed to be the
beneficial owner thereof.
(7)
(8)
(9)
Martin Resource Management Corporation owns our general partner and, together with our general partner,
owns approximately 32.2% of our outstanding limited partner units as of March 2, 2011. The table below sets forth
information as of March 2, 2011 concerning (i) each person owning beneficially in excess of 5% of common stock of
Martin Resource Management Corporation, and (ii) the beneficial common stock ownership of (a) each director of
Martin Resource Management Corporation, (b) each executive officer of Martin Resource Management Corporation,
and (c) all such executive officers and directors of Martin Resource Management Corporation 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 Resource Management Corporation Employee Stock Ownership Trust (2).....
CNRT LLC (3) ............................................................................................................
RSM III Investments, Ltd. (4)......................................................................................
Ruben S. Martin III Dynasty Trust (5).........................................................................
SKM Partnership, Ltd. (6) ...........................................................................................
- 138 -
Beneficial Ownership of
Common Stock
Number of
Shares
Percent of
Outstanding
1,922.00
2,266.67
2,266.67
640.00
2,560.00
17.5%
20.7%
20.7%
5.8%
23.4%
Keeneland Capital LLC(..............................................................................................
KCM LLC ...................................................................................................................
Scott D. Martin (6) (7) .................................................................................................
Martin Transport, Inc. (7)
Ruben S. Martin (3) (7) (8) ..........................................................................................
Wesley M. Skelton (2) (10)(11) (12) ...........................................................................
Robert D. Bondurant (10) (11) (12) .............................................................................
Donald R. Neumeyer (10) (11) (12).............................................................................
Randall L. Tauscher (10)(12).......................................................................................
Executive officers and directors as a group (5 individuals)
4,472.00
4,472.00
3,065.00
40.00
2,601.00
2,030.00
200.00
116.00
85.00
5,032.00
40.8%
40.8%
28.0%
*
23.7%
18.6%
1.8%
1.1%
*
45.9%
_____________
* Represents less than 1.0%
(1)
(2)
(3)
(4)
(5)
(6)
(7)
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.
Wesley M. Skelton is a co-trustee of the Martin Resource Management Corporation Employee Stock
Ownership Trust and exercises shared control over the voting and disposition of the securities owned by
this trust. As a result, he may be deemed to be the beneficial owner of the securities held by such trust;
thus, the number of shares of common stock reported herein as beneficially owned by him includes the
1,922 shares owned by such trust. Mr. Skelton disclaims beneficial ownership of these 1,922 shares.
Ruben S. Martin is the president of RSM III Management Corp., which is the general partner of RSM III
Investments Ltd., which is the sole member of CNRT LLC. Courtney Stovall and Robin Martin, as
managers of CNRT LLC exercise control over the voting of the securities owned by this entity. However,
as a result of his position with the general partner of the sole member of this entity, Ruben S. Martin may
be deemed to be the beneficial owner of the securities held by such entity; thus, the number of shares of
common stock reported herein as beneficially owned by such individual includes the 2,266.67 shares
owned by such entity.
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.
Bill Bankston is the trustee of the Ruben S. Martin III Dynasty Trust and exercises control over the voting
and disposition of the securities owned by the trust. As a result, he may be deemed to be the beneficial
owner of the securities held by the trust. These 640 shares have been pledged as security to a third party to
secure payment for a loan made by such third party.
Scott D. Martin is the beneficial owner of the general partner of SKM Partnership, Ltd. and exercises
control over the voting and disposition of the securities owned by this entity. As a result, he may be
deemed to be the beneficial owner of the securities held by such entity; thus, the number of shares of
common stock reported herein as beneficially owned by such individual includes the 2,560 shares owned
by such entity.
Ruben S. Martin beneficially owns securities in Martin Resource Management Corporation representing
approximately 23.7% of the voting stock thereof and serves as its Chairman of the Board and President.
Scott D. Martin beneficially owns securities in Martin Resource Management Corporation representing
approximately 28.0% of the voting stock thereof. Martin Transport, Inc. is a wholly owned subsidiary of
Martin Resource Management Corporation. As a result, Ruben S. Martin may be deemed to be the
beneficial owner of the securities held by Martin Transport, Inc.; thus, the number of shares of common
stock reported herein as beneficially owned by Ruben S. Martin includes the 40 shares owned by Martin
Transport, Inc.
(8)
Ruben S. Martin directly owns 294.33 shares of common stock.
- 139 -
(9)
Scott D. Martin directly owns 505 shares of common stock.
(10) Messrs. Neumeyer, Skelton, Bondurant and Tauscher each have the right to acquire 30, 30, 50, and 50
shares, respectively, by virtue of options issued under Martin Resource Management Corporation’s
nonqualified stock option plan.
(11) Messrs. Neumeyer, Skelton and Bondurant own securities in Martin Resource Martin Corporation of 36, 28
and 100 shares of common stock, respectively, obtained by the exercise of options issued under Martin
Resource Management Corporation’s nonqualified stock option plan.
(12) Messrs. Neumeyer, Skelton, Bondurant and Tauscher own securities in Martin Resource Martin
Corporation of 50, 50, 50 and 35, restricted common shares, respectively, representing shares by virtue of
restricted stock issued under Martin Resource Management Corporation’s 2007 Long-Term Incentive Plan.
(13)
(14)
KCM LLC owns 1,407 shares of Martin Resource Management Corporation and holds options to purchase
additional shares from Scott D. Martin; thus, the number of shares of common stock reported herein as
beneficially owned by KCM LLC includes the 505 shares owned by Scott D. Martin.
KCM LLC owns 1,407 shares of Martin Resource Management Corporation and holds options to purchase
additional shares from SKM Partnership Ltd.; thus, the number of shares of common stock reported herein
as beneficially owned by KCM LLC includes the 2,560 shares owned by such entity.
(15)
Keeneland Capital LLC is the sole member of KCM LLC and, as such, may be deemed to be the beneficial
owner of the securities owned by KCM LLC.
The following table sets forth information regarding securities authorized for issuance under our equity
compensation plans as of December 31, 2010:
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)
Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a))
(c)
N/A
0
0
N/A
$0
$0
N/A
709,500
709,500
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”.
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.
- 140 -
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.
On May 3, 2007, we issued 1,000 restricted common units to each of our three independent directors under
our long-term incentive plan. These restricted common units vest in equal installments of 250 units on each of the
four anniversaries following the grant date.
- 141 -
Item 13. Certain Relationships and Related Transactions, and Director Independence
Martin Resource Management owns 5,703,823 of our common units and 889,444 subordinated units
collectively representing approximately 32.2% of our outstanding limited partnership units as of March 2, 2011. 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, as general partner, to
manage and operate us, and Martin Resource Management’s ownership of approximately 32.2% of our outstanding
limited partnership units, effectively gives Martin Resource Management the ability to veto some of our actions and to
control our management.
Distributions and Payments to the General Partner and its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its
affiliates in connection with our formation, ongoing operation and liquidation. These distributions and payments were
determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
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 ........................................
•
•
•
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 $0.8 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. For the years ended December 31, 2010,
2009 and 2008, the Conflicts Committee of our general partner approved
reimbursement amounts of $3.8, $3.5 and $2.9 million, respectively,
reflecting our allocable share of such expenses. The Conflicts Committee
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Withdrawal or removal of our general
partner................................................
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
We and Martin Resource Management have entered into various agreements that are not the result of arm’s-
length negotiations and consequently may not be as favorable to us as they might have been if we had negotiated them
with unaffiliated third parties.
Omnibus Agreement
We and our general partner are parties to an omnibus agreement with Martin Resource Management 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 hydrocarbon products and by-products;
• providing marine transportation of hydrocarbon 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 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 small crude oil gathering business in Stephens, Arkansas,
• operating an underground NGL storage facility in Arcadia, Louisiana,
• building and marketing of sulfur processing equipment,
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• developing an underground natural gas storage facility in Arcadia, Louisiana,
•
•
•
any business that Martin Resource Management acquires or constructs that has a fair market value of less
than $5.0 million;
any business that Martin Resource Management acquires or constructs that has a fair market value of
$5.0 million or more if 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. For the years ended December 31, 2010, 2009 and 2008, the
Conflicts Committee of our general partner approved reimbursement amounts of $3.8, $3.5 and $2.9 million,
respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve
future adjustments in the reimbursement amount for indirect expenses, if any, annually.
These indirect expenses cover all of the centralized corporate functions Martin Resource Management
provides for us, such as accounting, treasury, clerical billing, information technology, administration of insurance,
general office expenses and employee benefit plans and other general corporate overhead functions we share with
Martin Resource Management retained businesses. The provisions of the omnibus agreement regarding Martin
Resource Management’s services will terminate if Martin Resource Management ceases to control our general partner.
Related Party Transactions. The omnibus agreement prohibits us from entering into any material
agreement with Martin Resource Management without the prior approval of the Conflicts Committee 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 24, 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.
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Motor Carrier Agreement
We are a party to a motor carrier agreement effective January 1, 2006 with Martin Transport, Inc., a wholly
owned subsidiary of Martin Resource Management through which Martin Resource Management operates its land
transportation operations. This agreement replaced a prior agreement effective November 1, 2002 between us and
Martin Transport, Inc. for land transportation services. Under the agreement, Martin Transport, Inc. agreed to ship
our NGL shipments as well as other liquid products.
Term and Pricing. This agreement was amended in November 2006, January 2007, April 2007 and January
2008 to add additional point-to-point rates and to modify certain fuel and insurance surcharges being charged to us.
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 U.S. Department of Energy’s national diesel price list.
Indemnification. Martin Transport has indemnified us against all claims arising out of the negligence or
willful misconduct of Martin Transport and its officers, employees, agents, representatives and subcontractors. We
indemnified Martin Transport against all claims arising out of the negligence or willful misconduct of us and our
officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint
negligence or misconduct of Martin Transport and us, our indemnification obligations will be shared in proportion to
each party’s allocable share of such joint negligence or misconduct.
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.
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. This agreement replaced a prior
agreement between us and Martin Resource Management covering marine transportation services which expired
November 2005. Effective each January 1, this agreement automatically renews for consecutive one-year periods
unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the
expiration of the then- applicable term. The fees we charge Martin Resource Management are based on applicable
market rates.
Cross Marine Charter Agreements. Cross entered into four marine charter agreements with us effective
March 1, 2007. These agreements have an initial term of five years and continue indefinitely thereafter subject to
cancellation after the initial term by either party upon a 30 day written notice of cancellation. The charter hire
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payable under these agreements will be adjusted annually to reflect the percentage change in the Consumer Price
Index.
Marine Fuel. The Partnership is a party to an agreement with Martin Resource Management under which
Martin Resource Management provides the Partnership 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, the Partnership 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 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. The Partnership is party to an agreement under which Martin
Resource Management purchases and markets the sulfuric acid produced by the Partnership’s sulfuric acid
production plant at Plainview, Texas, and which is not consumed by the Partnership’s internal operations. This
agreement, which was amended and restated in August 2008, 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.
Other Related Party Transactions
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). Following this offering, the common units represented a
95.7% limited partnership interest in us. 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 1.0 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.
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
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Resource Management for $36.5 million. The net book value of the acquired assets was recorded in property, plant
and equipment. These assets are located across the Louisiana Gulf Coast.
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 distribution to Martin Resource Management.
Acquisition of Terminalling Assets. On August 26, 2010, we acquired certain shore-based marine
terminalling assets from Martin Resource Management for $11,700. 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
distribution to Martin Resource Management. These assets are located in Theodore, Alabama and Pascagoula,
Mississippi.
Acquisition by Waskom of the Harrison Pipeline System. On January 15, 2010, we, through Prism Gas, as
50% owner and the operator of Waskom Gas Processing Company (“WGPC”), through WGPC’s 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. Our share of the acquisition cost is approximately $20.0 million.
Acquisition of Cross Assets. On November 25, 2009, we closed a transaction with Martin Resource
Management and Cross Refining & Marketing, Inc. (“Cross”), a wholly owned subsidiary of Martin Resource
Management, in which we acquired certain specialty lubricants processing assets (“Assets”) from Cross for total
consideration of $44.9 million (the “Contribution”). As consideration for the Contribution, we issued 804,721 of our
common units and 889,444 subordinated units to Martin Resource Management at a price of $27.96 and $25.16 per
limited partner unit, respectively. The common units will be entitled to receive distributions beginning in February
2010, while the subordinated units will have no distribution rights until the second anniversary of closing of the
Contribution. At the end of such second anniversary, the subordinated units will automatically convert to common
units, having the same distribution rights as existing common units. In connection with the Contribution, our general
partner made a capital contribution of $0.9 million to us in order to maintain its 2% general partner interest in us.
In connection with the closing of the Contribution, we and Martin Resource Management entered into a
long-term, fee for services-based Tolling Agreement whereby Martin Resource Management agreed to pay us for
the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other
intermediate cuts. Under the Tolling Agreement, Martin Resource Management generally agreed to refine a
minimum of 6,500 barrels per day of crude oil at the refinery at a price of $4.00 per barrel. Any additional barrels
will be refined at a price of $4.28 per barrel. In addition, Martin Resource Management agreed to pay a monthly
reservation fee of $1.3 million and a periodic fuel surcharge fee based on certain parameters specified in the Tolling
Agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater
of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the
parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement. The Tolling
Agreement has a 12-year term, subject to certain termination rights specified therein. Martin Resource Management
will continue to market and distribute all finished products under the Cross brand name. In addition, Martin
Resource Management will continue to own and operate the Cross packaging business.
Issuance of Common Units. In November 2009, we issued 714,285 common units to Martin Resource LLC,
an affiliate of Martin Resource Management, for $20.4 million, including a capital contribution of approximately $0.4
million made by our general partner in order to maintain its 2% general partner interest in us. These funds were used to
pay down our revolving line of credit.
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.
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Waskom Agreements. Prism Gas is a party to a product purchase agreement and a gas processing agreement
with Waskom whereby Prism Gas purchases product from and supplies product to Waskom. These intercompany
transactions totaled approximately $70.3 million for the year ended December 31, 2010. In addition, Prism Gas
provides certain administrative services for Waskom pursuant to Waskom’s partnership agreement.
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.
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Item 14. Principal Accounting Fees and Services
KPMG, LLP served as our independent auditors for the fiscal years ended December 31, 2010 and 2009. 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
_________________
2010
2009
$1,122,800(1)
—
1,122,800
$ 795,000(1)
—
795,000
117,730 (2)
105,765 (2)
—
—
$1,240,530
$ 900,765
(1) 2010 and 2009 audit fees include fees for the annual integrated audit, the audit of Waskom Gas Processing
Company, the audit of Martin Midstream GP LLC 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, 2010 and December 31, 2009 were approved
in advance by the Audit Committee.
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Item 15. Exhibits and Financial Statement Schedules
PART IV
(a)
(1)
Financial Statements and Schedules
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, 2010 and 2009
Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008
Consolidated Statements of Changes in Capital for the years ended December 31, 2010, 2009 and
2008
Consolidated Statements of Comprehensive Income for the years ended December 31, 2010 and
2009
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008
Notes to the Consolidated Financial Statements
(2)
Financial Statements of Waskom Gas Processing Company for the year ended December 31,
2010, 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 151 for a list of all exhibits filed as
part of this report.
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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 2, 2011
Martin Midstream Partners L.P.
(Registrant)
By:
Martin Midstream GP LLC
It’s General Partner
By:
/s/ Ruben S. Martin
Ruben S. Martin
President and Chief Executive
Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by
the following persons on behalf of the registrant and in the capacities indicated on the 2nd day of March, 2011.
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/ Howard Hackney
Howard Hackney
/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
- 151 -
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
4.1
4.2
4.3
10.1
10.2
10.3
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, 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 ,
filed February 1, 2011, 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 filed March 26,
2010, 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, filed November 14, 2005, and incorporated herein by
reference).
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
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Exhibit
Number
Exhibit Name
10.4
10.5
Current Report on Form 8-K 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 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
Martin Operating Partnership L.P., Martin Midstream Partners L.P., Martin Operating GP LLC, Prism Gas
Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering
and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., the financial institutions parties thereto, as
lenders, and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the
Partnership’s Current Report on Form 8-K filed January 19, 2010, and incorporated herein by reference).
Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of March 26, 2010, among
Martin Operating Partnership L.P., the Partnership, Martin Operating GP LLC, Prism Gas Systems I, L.P.,
Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing
Company, L.L.C., Woodlawn Pipeline Co., Inc., the financial institution parties to the Credit Agreement and
Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s
Current Report on Form 8-K filed March 26, 2010, and incorporated herein by reference).
Omnibus Agreement dated November 1, 2002, by and among Martin Resource Management, the General
Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current
Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by
reference).
Amendment No. 1 to Omnibus Agreement, dated as of November 25, 2009, by and among Martin Resource
Management, the General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the
Partnership’s Current Report on Form 8-K filed December 1, 2009, and incorporated herein by reference).
10.9* Motor Carrier Agreement dated January 1, 2006, by and between the Operating Partnership and Transport
10.10* Contract for Marine Transportation dated January 1, 2006, by and between the Operating Partnership and
10.7
10.8
10.6
10.11
Martin Resource Management.
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).
10.12 Marine Fuel Agreement dated November 1, 2002, by and between Martin Fuel Service LLC and the
Operating Partnership (filed as Exhibit 10.9 to the Partnership’s Current Report on Form 8-K (SEC File No.
000-50056), filed November 19, 2002, and incorporated herein by reference).
10.13† Martin Midstream Partners L.P. Long-Term Incentive Plan (filed as Exhibit 10.11 to the Partnership’s
Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein
by reference).
10.14† Martin Midstream Partners L.P. Amended and Restated Long-Term Incentive Plan (filed as Exhibit 10.1 to
10.15†
10.16
10.17
10.18
the Partnership’s Current Report on Form 8-K, filed January 26, 2006, and incorporated herein by reference).
Form of Restricted Common Unit Award Notice (filed as Exhibit 10.2 to the Partnership’s Current Report on
Form 8-K, filed January 26, 2006, and incorporated herein by reference).
Assignment and Assumption of Lease and Sublease dated November 1, 2002, by and between the Operating
Partnership and MGSLLC (filed as Exhibit 10.12 to the Partnership’s Current Report on Form 8-K (SEC File
No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
Purchaser Use Easement, Ingress-Egress Easement, and Utility Facilities Easement dated November 1, 2002,
by and between MGSLLC and the Operating Partnership (filed as Exhibit 10.13 to the Partnership’s Current
Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by
reference).
Asset Purchase Agreement by and among the Partnership, the Operating Partnership and Tesoro Marine
Services, L.L.C., dated October 27, 2003 (filed as Exhibit 10.1 to the Partnership’s Amendment No. 1 to
Current Report on Form 8-K (SEC File No. 000-50056), filed January 23, 2004, and incorporated herein by
- 153 -
Exhibit
Number
10.19
10.20
10.21
10.22
Exhibit Name
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, filed September 6, 2005, and incorporated herein by reference).
Amended and Restated Terminal Services Agreement by and between the Operating Partnership and
MFSLLC, dated October 27, 2004 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K
(SEC File No. 000-50056), filed October 28, 2004, and incorporated herein by reference).
Transportation Services Agreement by and between the Operating Partnership and MFSLLC, dated
December 23, 2003 (filed as Exhibit 10.3 to the Partnership’s Amendment No. 1 to Current Report on Form
8-K (SEC File No. 000-50056), filed January 23, 2004, and incorporated herein by reference).
Lubricants and Drilling Fluids Terminal Services Agreement by and between the Operating Partnership and
MFSLLC, dated December 23, 2003 (filed as Exhibit 10.4 to the Partnership’s Amendment No. 1 to Current
Report on Form 8-K (SEC File No. 000-50056), filed January 23, 2004, and incorporated herein by
reference).
10.23† Martin Resource Management Corporation Purchase Plan for Units of Martin Midstream Partners L.P. (filed
10.24
10.25
10.26
10.27
10.28
10.29
21.1*
23.1*
23.2*
31.1*
31.2*
32.1*
32.2*
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).
Stock Purchase Agreement, dated April 27, 2007, by and among Woodlawn Pipeline Co., Inc., Lantern
Resources, L.P., David P. Deison and Prism Gas Systems I, L.P. (filed as Exhibit 10.1 to the Partnership’s
Current Report on Form 8-K, filed May 2, 2007, and incorporated herein by reference).
Asset Purchase Agreement, dated April 27, 2007, by and among Peak Gas Gathering L.P. and Prism Gas
Systems I, L.P. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed May 2, 2007,
and incorporated herein by reference).
Form of Indemnification Agreement (filed as Exhibit 10.1 to the Partnership’s Quarterly Report of Form 10-
Q, 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, Cross Oil Refining & Marketing, Inc., Martin Resource Management and the
Partnership (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed December 1, 2009,
and incorporated herein by reference).
Tolling Agreement, dated as of November 25, 2009, by and between the Operating Partnership and Cross Oil
Refining & Marketing, Inc. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed
December 1, 2009, and incorporated herein by reference).
Amended and Restated Common Unit Purchase Agreement, dated as of November 24, 2009, by and between
the Partnership and Martin Resource Management (filed as Exhibit 10.4 to the Partnership’s Current Report
on Form 8-K filed December 1, 2009, and incorporated herein by reference).
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.”
* 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.
- 154 -
Financial Statement Schedule
Pursuant to Item 15(a)(2)
- 155 -
Waskom Gas
Processing Company
Consolidated Financial Statements December 31,
2010 and 2009 and for each of the years in the three-
year period ended December 31, 2010, (with
Independent Auditors’ Report Thereon)
INDEPENDENT AUDITORS’ REPORT
To the Partners of Waskom Gas Processing Company:
We have audited the accompanying consolidated balance sheets of Waskom Gas Processing Company and subsidiaries
(the “Partnership”) as of December 31, 2010 and 2009 and the related consolidated statements of income, partners’
capital, and cash flows for each of the years in the three-year period ended December 31, 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, 2010 and 2009 and the
results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010,
in conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP Shreveport,
Louisiana March 3, 2011
WASKOM GAS PROCESSING COMPANY
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2010 AND 2009
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
2010
2009
$
961,067
946,206
10,707,976
503,449
24,064
$
23,160
178,032
9,373,492
468,372
-
13,142,762
10,043,055
133,744,130
746,743
(25,826,835)
88,211,154
746,743
(19,396,696)
Net property and equipment
108,664,038
69,561,201
NON-CURRENT ASSETS:
Other non-current assets
TOTAL
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities
Accounts payable—partners
250,000
-
$
122,056,800
$
79,604,257
$
8,824,740
4,978,625
$
6,505,267
1,844,015
Total current liabilities
13,803,365
8,349,282
LONG-TERM LIABILITIES—Asset retirement obligation
744,991
694,177
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL
TOTAL
107,508,444
70,560,798
$
122,056,800
$
79,604,257
See accompanying notes to consolidated financial statements.
WASKOM GAS PROCESSING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
2010
2009
2008
OPERATING REVENUES:
Natural gas processing and other revenues
Natural gas liquid sales
Gain/(loss) on disposal of assets
$
36,297,801
86,911,925
912,004
$
23,421,165
47,623,953
(847)
$
35,868,029
79,225,191
(61,891)
Total operating revenues
124,121,730
71,044,271
115,031,329
OPERATING COSTS AND EXPENSES:
Cost of sales - natural gas liquids
Operating costs
Depreciation and amortization
87,159,671
9,375,703
6,597,686
46,645,393
6,420,633
4,000,412
78,008,310
6,414,677
3,129,246
Total operating costs and expenses
103,133,060
57,066,438
87,552,233
OPERATING INCOME BEFORE TAXES
20,988,670
13,977,833
27,479,096
Income tax expense
NET INCOME
226,589
110,712
186,722
$
20,762,081
$
13,867,121
$
27,292,374
See accompanying notes to consolidated financial statements.
WASKOM GAS PROCESSING COMPANY
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
BALANCE—December 31, 2007
Cash contributions for capital expenditures
Cash distributions in excess of working capital
Cash distributions
Distributions in-kind
Net income
BALANCE—December 31, 2008
Cash contributions for capital expenditures
Cash distributions in excess of working capital
Cash distributions
Distributions in-kind
Net income
Total
Partners'
Capital
57,149,312
12,921,736
(8,583,683)
(1,600,000)
(19,449,952)
27,292,374
$
67,729,787
8,310,458
(6,394,002)
(1,300,000)
(11,652,566)
13,867,121
BALANCE—December 31, 2009
$
70,560,798
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
7,471,259
40,000,000
(4,702,415)
(4,200,000)
(22,383,279)
20,762,081
BALANCE—December 31, 2010
$
107,508,444
See accompanying notes to consolidated financial statements.
WASKOM GAS PROCESSING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
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
Accounts payable and accrued liabilites
Accounts payable - partners
2010
2009
2008
$
20,762,081
$
13,867,121
$
27,292,374
6,597,686
(22,383,279)
(912,004)
4,000,412
(11,652,566)
847
3,129,246
(19,449,952)
61,891
(768,174)
(1,334,484)
(35,077)
(24,064)
2,132,514
3,134,610
1,172,489
983,218
(4,798)
3,989
(354,716)
(1,932,840)
377,441
(581,029)
(30,302)
(3,989)
(125,998)
1,291,569
Net cash provided by operating activities
7,169,809
6,083,157
11,961,251
INVESTING ACTIVITIES:
Additions to property and equipment
Acquisitions, net of cash required
Proceeds from sale/disposal of assets
(7,277,746)
(40,000,000)
2,477,000
(8,773,336)
-
708,449
(13,592,311)
-
15,655
Net cash used in investing activities
(44,800,746)
(8,064,887)
(13,576,656)
FINANCING ACTIVITIES:
Contributions from partners
Distrubutions to partners
47,471,259
(8,902,415)
8,310,458
(7,694,002)
12,921,736
(10,183,683)
Net cash provided by financing activities
38,568,844
616,455
2,738,053
NET INCREASE (DECREASE) IN CASH
937,907
(1,365,274)
1,122,648
CASH—Beginning of year
CASH—End of year
23,160
1,388,434
265,786
$
961,067
$
23,160
$
1,388,434
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Interest paid
$
-
$
-
$
-
Taxes paid
$
112,371
$
221,201
$
206,911
NON-CASH:
State grant receivable
Addition to asset retirement obligation
$
$
-
-
$
$
-
122,777
$
$
1,114,314
130,367
See accompanying notes to consolidated financial statements.
WASKOM GAS PROCESSING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF BUSINESS
Waskom Gas Processing Company (the “Partnership”), a Texas General Partnership, was formed on
November 1, 1995 to construct and operate the Waskom Processing Plant (“the Plant”). As of December 31,
2010 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 285 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 and June of 2009 increasing the capacity from 150 MMcfd to 285
MMcfd. In July 2009 the Waskom fractionator was expanded to a capacity of 14,500 barrels per day from
12,500 barrels per day. An additional expansion is anticipated and currently scheduled to be complete in the
fourth quarter of 2011 which will increase the capacity to 320 MMcfd.
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, Endeavour Pipeline, Inc.,
Samson Lone Star, LLC and Devon Energy Corporation, which collectively represent approximately 80% of the
281 MMcfd of natural gas supplied for the year ended December 31, 2010. BP American Production Company,
Centerpoint Energy Gas Transmission Company and Devon Energy Corporation supplied 64% of the 243
MMcfd and 70% of the 257 MMcfd for the years ended December 31, 2009 and 2008, respectively.
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. Currently, approximately 42%
of the contracts are POL, 39% of the contracts are fee and 16% of the contracts are POP. In addition, there is
one minor contract for processing on a keep-whole basis.
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 a 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:
Gas gathering equipment
Gas plant
Furniture and fixtures
Computer equipment
Computer software
Years
10
20
1
3
3
Depreciation expense was $6,546,872, $3,769,905, and $3,116,460 in 2010, 2009 and 2008, respectively.
Repairs and maintenance are charged to operations as incurred. Renewals and betterments are capitalized.
Inventories—Substantially all inventory at December 31, 2010 and 2009 represents pipe held for future
projects. Such pipe was valued at acquisition cost.
Asset Retirement Obligations—The Partnership records asset retirement obligations (“ARO”) for costs
associated with legal obligations to retire tangible, long-lived assets. The Partnership records as an offset to the
“ARO”, an asset at fair value in the period in which it is incurred by increasing the carrying amount of the
related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate
obligation amount and the capitalized costs are depreciated over the useful life of the related asset. The
Partnership’s asset retirement obligations include purging, plugging and remediation costs associated with the
pipeline. Accretion expense for 2010, 2009 and 2008 was $50,814, $230,507 and $12,786, 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 2010,
2009 and 2008 was $226,589, $110,712 and $186,722, 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 2010, 2009 and 2008, 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 December 31, 2010 and 2009, the Partnership had receivables of
approximately $10,707,976 and $9,373,492, respectively, and payables of approximately $4,978,625 and
$1,844,015, 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 $7,471,259, $8,310,458 and $12,921,736 for 2010, 2009
and 2008, 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 $4,702,415, $6,394,002 and
$8,583,683 in 2010, 2009 and 2008, respectively. Other cash distributions totaled $4,200,000, $1,300,000 and
$1,600,000 for 2010, 2009 and 2008, respectively.
The Partnership purchases gas from third party producers and processes this gas based on processing contracts,
which are primarily POL contracts. The percentage of liquids retained by the Partnership is distributed to the
partners as distributions of products-in-kind based on the partners’ equity interest. Distributions of products in-
kind of $22,383,279, $11,652,566 and $19,449,952 in 2010, 2009 and 2008, 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 $71,734,452,
$46,241,067 and $75,738,508 in 2010, 2009 and 2008, 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
The Partnership has evaluated subsequent events from the balance sheet date through March 2, 2011, the date at
which the financial statements were available to be issued, and determined there are no items to disclose.
MOTOR CARRIER AGREEMENT
Exhibit 10.9
This MOTOR CARRIER AGREEMENT (hereinafter referred to as "Agreement") made effective as of the
1st day of January, 2006, between MARTIN OPERATING PARTNERSHIP, L.P. (hereinafter referred to as
"SHIPPER"), a Delaware limited partnership, and MARTIN TRANSPORT, INC. (hereinafter referred to as
"CARRIER"), a Texas corporation, for the interstate and unregulated intrastate transportation of petroleum or other
bulk liquid products (hereinafter referred to as "COMMODITIES"), by tank truck, in the contiguous United States,
shall be under the terms and conditions hereinafter set forth. This Agreement shall be subject to amendment and/or
modification by Addendum hereafter executed by both SHIPPER and CARRIER and attached hereto and made a
part hereof. The terms and conditions hereunder shall further extend to all shipments of COMMODITIES involving
the CARRIER and the parent, affiliate or subsidiary of SHIPPER as if such parent, affiliate or subsidiary were the
SHIPPER. This Agreement shall replace and supersede any existing motor carrier agreements between the
CARRIER and the SHIPPER, or its parent, affiliates or subsidiaries.
1.
2.
3.
AGREEMENT
A.
General: CARRIER agrees to accept interstate and unregulated intrastate lawful shipments of the
subject COMMODITIES tendered to it by SHIPPER, pursuant to this Agreement and to transport
such COMMODITIES to the destination or destinations designated by SHIPPER, provided such
points of origin and destination are within the scope of CARRIER'S operating authority subject to
the rates and provisions of the applicable Schedule of Actual Rates and Charges as provided in the
Addendum and Exhibit “A”, which are attached hereto and made a part hereof.
B. Licenses, Laws and Regulations: CARRIER, at its sole cost, and expense, shall procure and maintain
all licenses and permits required by local, state, or federal authorities with respect to the
transportation and related services rendered hereunder and shall comply with all applicable laws
and regulations pertaining to such transportation and services.
TERM
The initial term of this Agreement shall be for a one year period beginning on the commencement date (as
herein defined) and thereafter shall automatically renew on an annual basis, until canceled by either party
by providing at least thirty (30) days written notice to the other party prior to the expiration of the then
existing annual term. For the purposes of this Agreement, the "commencement date" shall be January 1,
2006.
EQUIPMENT
CARRIER shall provide all equipment necessary to perform the transportation required hereunder, which
equipment shall: (i) be suitable for particular transportation required, (ii) include any special equipment that
is requested by SHIPPER and agreed to by CARRIER when the shipping order is placed, and (iii) comply
with the specifications for equipment for such transportation prescribed by any applicable governmental
regulations (including those of the United States Department of Transportation). CARRIER shall maintain,
and at all times make available to SHIPPER, sufficient suitable equipment to transport SHIPPER'S
COMMODITIES.
4.
CARRIER'S PERFORMANCE
A.
General: CARRIER agrees to accept from SHIPPER, and provide transportation services for all
COMMODITIES required by SHIPPER, during the initial term and any renewal term of this
Agreement. All transportation hereunder shall be performed: (i) at CARRIER'S sole expense, (ii)
to the best of CARRIER'S knowledge, in full compliance with all applicable governmental laws,
ordinances, regulations, orders licenses, permits, and all requirements of CARRIER'S insurance,
and (iii) with maximum dispatch consistent with the CARRIER'S best judgment as to safety and
efficiency, except as is specifically provided to the contrary elsewhere in this Agreement.
B.
Services: It is understood that the CARRIER shall secure the services of, supervise and be
responsible for all persons operating trucking equipment hereunder and CARRIER shall hold
C.
SHIPPER harmless from any claim, except for those claims arising as a result of SHIPPER’S
negligence, including fees in defense thereof, by drivers for wages, industrial accidents, workers
compensation, withholding and unemployment taxes, or any other actions arising from the
performance of this contract which shall be subject to Section 8(C) below.
Drivers: CARRIER'S drivers shall comply with all reasonable operational procedures requested
by SHIPPER. CARRIER'S drivers shall promptly report all commodity spills, shortages (less
routine heels) or accidents which occur in the course of the performance of this Agreement. In the
interest of safety, CARRIER'S drivers shall not unload COMMODITIES until the SHIPPER, its
agents or employees shall have inspected the shipping orders and have directed the driver to and
specified the proper unloading facilities.
5.
SHIPPER'S PAYMENT
CARRIER shall bill SHIPPER for the freight charges on all shipments as soon after delivery of such
shipments as sufficient information is received to prepare such invoices. All invoices for linehaul expenses
are to be paid in full within fifteen (15) days of receipt by SHIPPER of CARRIER'S invoice or such other
notification as is mutually agreeable to the parties. Payments to CARRIER by SHIPPER hereunder shall be
sent to the following address:
Martin Transport, Inc.
P. O. Box 191
Kilgore, Texas 75663
6.
COMPUTATION OF CHARGES
Freight charges shall be computed on the actual basis of the rates provided in the applicable Schedule of
Actual Rates and Charges set forth on Exhibit “A” attached hereto, subject to the terms and conditions
contained therein.
7.
TERMINATION
A. Non-Performance: In the event of non-performance by SHIPPER or CARRIER, as the case may
be, of any of the obligations contained in the Agreement, SHIPPER or CARRIER as the
complaining party shall provide written notice of such non-performance to the other party. The
non-performing party shall then have (14) days from the date of such notice within which to
remedy the non-performance. Thereafter, if the non-performance remains uncorrected or if an
acceptable remedy is not reached within fourteen (14) days of such notice, the complaining party
may terminate this Agreement at any time upon giving the non-performing party seven (7) days
prior written notice. If this Agreement is terminated in accordance with this subsection, all
obligations of the parties, as contained in this Agreement and the Addendum and Exhibits hereto,
shall be terminated; provided, SHIPPER shall continue to be responsible for all sums due to
CARRIER for services received prior to the date of termination.
B. Default or Insolvency: If a petition in bankruptcy should be filed by CARRIER, or if CARRIER
should be adjudicated as bankrupt, or if CARRIER should make a general assignment for the
benefit of creditors, or if a receiver should be appointed on account of the insolvency of
CARRIER, SHIPPER may, without prejudice to any other right of remedy, terminate this
Agreement upon giving CARRIER at least five (5) days prior written notice to such termination.
CARRIER shall have the same rights as SHIPPER under this item.
8.
INSURANCE AND INDEMNITY
A.
Liability: CARRIER shall be responsible for any loss, damage or destruction of shipments
tendered to it by SHIPPER from the time such shipments are loaded at the delivery point until
accepted by SHIPPER as evidenced by unloading at destination point. CARRIER shall reimburse
SHIPPER for loss, damage or injury to the COMMODITIES except when such loss, damage or
injury is caused by the wrongful act or negligence of SHIPPER, its agents or employees, in which
case SHIPPER shall bear it's proportionate share of responsibility for all loss, damage or injury
and all consequential and incidental damages related thereto.
B.
Insurance: CARRIER shall maintain at all times Worker's Compensation Insurance fully
complying with the law of every jurisdiction to which CARRIER is subject, Employer's Liability
Insurance in amounts not less than $250,000 and automotive and general public liability insurance
against injury or death in amounts of not less than $3,000,000 for any one person and $10,000,000
for any one accident or occurrence and against property damage in amounts not less than $250,000
for any one accident or occurrence. All liability insurance policies obtained or maintained by
CARRIER to meet the requirements of this Agreement shall name SHIPPER as an additional
insured as to the operations of CARRIER under this Agreement and shall contain severability of
interests provisions. Promptly after execution of this Agreement, CARRIER shall furnish
SHIPPER properly executed certificates of insurance evidencing that the insurance coverages and
limits required by this Agreement are in effect. If any insurance provided pursuant to this
Agreement expires during the term of the Agreement, renewal certificates of insurance shall be
furnished by CARRIER to SHIPPER thirty (30) days prior to the date of expiration. In addition,
certified, true and exact copies of all insurance policies required under this Agreement shall be
provided to SHIPPER by CARRIER, on timely basis if requested by SHIPPER. All such
certificates and policies shall contain provisions that thirty (30) days' written notice by registered
or certified mail shall be given the SHIPPER of any cancellation, intent not to renew, or reduction
in the policies' coverages, except in the application of the aggregate limits provisions. CARRIER
or any party liable on accounts of loss of or damage to any of said transported COMMODITIES
shall have the full benefit of any insurance that may have been affected upon or on account of said
COMMODITIES, insofar as this shall not void the contracts or policies of insurance. CARRIER
shall not be obligated to reimburse the claimant for any premium paid therein.
C.
INDEMNITY: CARRIER SHALL BE RESPONSIBLE FOR, AND SHALL INDEMNIFY, DEFEND AND
SAVE HARMLESS SHIPPER AND ITS OWNED, CONTROLLED, AFFILIATED, SUBSIDIARY,
ASSOCIATED, INTERRELATED AND OPERATED COMPANIES AND THE STOCKHOLDERS,
DIRECTORS, OFFICERS, AGENTS, EMPLOYEES AND REPRESENTATIVES OF EACH FROM AND
AGAINST, ANY AND ALL CLAIMS, DEMANDS AND CAUSES OF ACTION BROUGHT BY ANY AND ALL
PERSONS, INCLUDING WITHOUT LIMITATION, CARRIER'S OFFICERS, AGENTS, EMPLOYEES,
REPRESENTATIVES, OR SUBCONTRACTORS OR ANY THIRD PARTIES, AND AGAINST ANY AND ALL
JUDGMENTS IN RESPECT THERETO ON ACCOUNT OF PERSONAL INJURY OR DEATH OR ON
ACCOUNT OF PROPERTY DAMAGE OR DESTRUCTION OR LOSS ARISING OUT OF THE NEGLIGENCE
OR WILLFUL MISCONDUCT OF CARRIER, ITS OFFICERS, EMPLOYEES, AGENTS,
REPRESENTATIVES AND SUBCONTRACTORS.
SHIPPER SHALL BE RESPONSIBLE FOR, AND SHALL INDEMNIFY, DEFEND AND SAVE HARMLESS
CARRIER AND ITS OWNED, CONTROLLED, AFFILIATED, SUBSIDIARY, ASSOCIATED,
INTERRELATED AND OPERATED COMPANIES AND THE STOCKHOLDERS, DIRECTORS, OFFICERS,
AGENTS, EMPLOYEES AND REPRESENTATIVES OF SUCH FROM AND AGAINST, ANY AND ALL
CLAIMS, DEMANDS AND CAUSES OF ACTION BROUGHT BY ANY AND ALL PERSONS, INCLUDING
WITHOUT LIMITATION, SHIPPER'S OFFICERS, AGENTS, EMPLOYEES, REPRESENTATIVES, OR
SUBCONTRACTORS OR BY ANY THIRD PARTIES, AND AGAINST ANY AND ALL JUDGMENTS IN
RESPECT THERETO ON ACCOUNT OF PERSONAL INJURY OR DEATH OR ON ACCOUNT OF
PROPERTY DAMAGE OR DESTRUCTION OR LOSS ARISING OUT OF THE NEGLIGENCE OR WILLFUL
MISCONDUCT OF SHIPPER, ITS OFFICERS, EMPLOYEES, AGENTS, REPRESENTATIVES AND
SUBCONTRACTORS.
WHERE PERSONAL INJURY, DEATH, OR LOSS OF OR DAMAGE TO PROPERTY IS THE RESULT OF
THE JOINT NEGLIGENCE OR MISCONDUCT OF CARRIER AND SHIPPER, EACH PARTY'S DUTY
OF INDEMNIFICATION SHALL BE IN PROPORTION TO ITS ALLOCABLE SHARE OF SUCH JOINT
NEGLIGENCE OR MISCONDUCT.
Notwithstanding anything herein to the contrary, any provision within this Agreement that
expands any indemnity obligation of the CARRIER beyond that which can be required pursuant to
Texas Transportation Code Section 623.0155 shall be null and void and without effect.
9.
FORCE MAJEURE
Either CARRIER or SHIPPER shall be excused from performance of its obligations hereunder in the event
and to the extent that such performance is delayed or prevented by any circumstances reasonably beyond its
control, including by fire, explosion, interruption of raw materials, equipment source or fuel supply, strike
or other labor dispute, riot or other civil disturbance, or act or omission of any governmental authority.
10.
LIMITATIONS OF LIABILITY
CARRIER'S Obligations under this Agreement shall always be subject to any limitations imposed by
applicable laws, regulations or other of any governmental authority. In no event shall CARRIER be
responsible for any loss, damage, destruction or delay of shipments which occurs by reason of any act of
God, terrorist attack, labor disturbance, strike, war, riot or civil disturbance, prohibition by government
agency of the movement of goods or any other such similar causes which affect the obligations or
performance of CARRIER, and CARRIER shall not be liable for any loss, damage, destruction or delay
occurring while the COMMODITIES are stopped and held in transit upon the request of SHIPPER or from
riots or strikes. CARRIER shall not be liable for delay causes by highway obstruction, faulty or impassible
highways or lack of capacity on any highway, bridge or ferry.
AGREEMENT CONCLUSIVE
SHIPPER shall arrange for shipments to be tendered to CARRIER on a standard uniform bill of lading or
other such document as may be mutually agreed to between CARRIER and SHIPPER, i.e., scale weight
ticket, subject to the conditions of this Agreement and the attached Addendum or Exhibits. In the event
there is a conflict between the terms of this Agreement and any schedule or bill of lading otherwise
applicable to CARRIER and SHIPPER respecting the movements contemplated hereunder, the terms of
this Agreement and the attached Addendum or Exhibits shall be construed as controlling the intent of the
parties.
ASSIGNMENT
This Agreement and all Addendums or Amendments hereto shall be binding upon and inure to the benefit
of the successors of SHIPPER and CARRIER. Neither party may assign its rights under this Agreement
without the non-assigning party's written approval. However, notwithstanding the above, the parties may
assign their right, duties, obligations and interests in and to this Agreement to a parent, subsidiary, affiliate
or sister corporation; provided, however, the parties shall not be thereby relieved of the responsibilities or
obligations hereunder.
CONFIDENTIALITY
The terms of this Agreement shall be held in strict confidence by SHIPPER and CARRIER and shall not be
disclosed to any third party, provided, however, SHIPPER shall have the right to disclose the terms to it's
freight auditors, provide that a binding confidentiality agreement is continually maintained between
SHIPPER and each such freight auditor.
WAIVER
Failure of either party to insist, in one or more instances, upon performance of any of
Agreement, or the waiver by either party of any term or right of the
deemed or construed as a waiver or a
relinquishment of any such term or right.
the terms of this
other party hereunder, will not be
11.
12.
13.
14.
15.
APPLICABLE LAW
This Agreement is to be construed in accordance with the laws of the State of Texas
effect to the principles of conflict laws. Any legal actions filed may be brought only to the state or federal
courts in Texas.
without giving
16.
NOTICES
Notice, as may be required hereunder, by either party of this Agreement to the other party shall be deemed
to have been accomplished on date of delivery by the United States mail as evidenced by date of return
receipt, when sent by certified mail, postage prepaid, to the following addresses:
SHIPPER:
Martin Operating Partnership L.P.
4200 Stone Road
Kilgore, Texas 75662
CARRIER:
Martin Transport, Inc.
P. O. Box 191
Kilgore, Texas 75663
17.
ENTIRE CONTRACT
Except for the provisions of the schedules and Addenda or Amendments made a part hereof by reference,
this instrument embodies the entire Agreement and understanding between SHIPPER and CARRIER as of
the effective date of this Agreement, and there are no agreements, understandings, conditions, warranties or
representations, oral of written, express or implied, with reference to the subject matter hereof that are not
merged herein or superseded hereby as of the effective date of this Agreement. This Agreement may be
modified only in writing signed by other parties.
18.
AUTHORITY
Each party represents to the other that is has full authority and the necessary approval to enter into and
perform this Agreement in accordance with its terms.
IN WITNESS THEREOF, the parties have executed this Agreement effective January 1, 2006.
MARTIN OPERATING PARTNERSHIP L.P.
By Martin Operating GP LLC, Its General Partner
By Midstream Partners L.P., Its Sole Member
By Martin Midstream GP LLC, Its General Partner
By: /s/ Donald R. Neumeyer
Printed Name: Donald R. Neumeyer
Its Executive Vice President and Chief Operating Officer
MARTIN TRANSPORT, INC.
By: /s/ Johnnie Murry
Printed Name: Johnnie Murry
Its Vice President – Land Transportation
Exhibit 10.10
MARINE TRANSPORTATION AGREEMENT
This MARINE TRANSPORTATION AGREEMENT (this “Agreement”) is executed, effective January 1,
2006 (the “Effective Date”), by and between Martin Operating Partnership, LP, a Delaware limited partnership
(“Owner”), and Midstream Fuel Service, L.L.C., an Alabama limited liability company (“Charterer”), in order to
evidence the agreement of such parties with respect to Owner’s provision of marine transportation services for
Charterer’s products on board Owner’s marine vessels under the following terms and conditions.
1.
TERM. The initial term of this Agreement shall be for one (1) year (the "Initial Term")
commencing on the Effective Date and ending on the first (1st) anniversary of the Effective Date. This Agreement
will automatically renew for successive one (1) year terms (each a "Renewal Term", and together with the Initial
Term, the "Term"), unless either party elects not to renew this Agreement by providing the other party with written
notice of such election at least sixty (60) days prior to the expiration of the Initial Term or Renewal Term, as
applicable, at which point this Agreement will automatically terminate. Upon any such termination, this Agreement
shall thereafter have no further force or effect except as to already accrued rights and obligations, which shall
continue until satisfied.
2.
GENERAL TERMS. During the Term, Charterer agrees that Owner will be the sole and
exclusive provider of marine transportation services for petroleum products owned by Charterer or owned by others
and in transit for sale to Charterer so long as Owner has the required equipment available. Owner shall at all times
provide sufficient and proper equipment for Charterer's performance of such transportation. Said equipment shall be
manned, equipped, supplied and operated by Owner. Owner agrees that said equipment shall be maintained in a
seaworthy, staunch, tight and suitable condition and, to the best of Owner's knowledge, in compliance with all
applicable laws and regulations. In connection with its use of any vessel, Charterer will follow Owner's normal
scheduling, loading and offloading protocols established from time to time, subject to Owner's obligations set forth
in this Agreement.
3.
RATE. Charterer agrees to pay Owner charter hire at the rates established on the attached Exhibit
“B”, plus fuel surcharge as detailed in the attached Exhibit “A”, for each inland tug or each inland barge used
hereunder.”
4.
LOAD AND DISCHARGE. The Load Port shall be FOB Refinery Offtake in the U.S. Gulf of
Mexico. The Discharge Port shall be at the Owner's terminals located along the coast of the U.S. Gulf of Mexico
and the inland waterways feeding into the U.S. Gulf of Mexico.
5.
TITLE TO PRODUCT. Title to all product handled shall remain at all times in the name of the
Charterer. The Charterer agrees not to tender for load any product injurious to the Owner’s vessels or which product
would render the vessels unfit, after cleaning, for the proper storage of similar product.
6.
INVOICING & PAYMENT. Owner will invoice Charterer on a monthly basis. All monthly
Owner invoices to Charterer for rates and cost items will be paid by Charterer within thirty (30) days of invoice date
in accordance with Owner's normal payment protocols, which will be specified in the applicable invoice. Each
monthly invoice shall be itemized to include charges by applicable vessel by day.
7.
DEMISE OF CHARTER. The master of an applicable vessel, although appointed by and in the
employ of Owner and subject to Owner's direction and control, shall observe the reasonable instructions of Charterer
in connection with Charterer's transportation needs under this Agreement; PROVIDED, HOWEVER, THAT
NOTHING IN THIS CLAUSE OR ELSEWHERE IN THIS AGREEMENT SHALL BE CONSTRUED AS
CREATING A DEMISE OF THE APPLICABLE VESSEL TO CHARTERER OR AS VESTING CHARTERER
WITH ANY CONTROL OVER THE PHYSICAL OPERATION OR NAVIGATION OF THE APPLICABLE
VESSEL.
8. OBLIGATION TO CREW AND SUPPLY THE VESSEL. The crew shall be experienced and qualified
personnel. The crew shall be the servants and employees of Owner and not Charterer. The recruitment,
supervision, discharge, and discipline of the applicable vessel’s crew and all other personnel employed by
Owner shall be the sole and exclusive responsibility of Owner.
9. OPERATION OF OWNER’S VESSELS. Owner shall crew, maintain, operate, navigate and supply its
vessels and shall pay all expenses incident to the crewing, operation and navigation of such vessels except as
specifically provided to the contrary herein. Owner shall provide all supplies, food, and items of gear required
to operate its vessels. Owner or Charter, as may be applicable, agrees to tender barges to be towed by the tugs
chartered hereunder that are seaworthy and fit for towage for the voyage contemplated. Owner shall have the
right to refuse towage of any barge tendered by Charterer that Owner reasonably believes to be un-seaworthy or
not fit for towage. Owner shall also have the right, in its discretion, to limit the number of barges towed when
reasonably necessary due to existing river conditions. Owner shall be responsible for dispatching its vessels as
may be required to fulfill its obligations hereunder.
10. FUEL AND OTHER CHARGES. Charterer shall pay Owner a fuel surcharge in accordance with the
attached Exhibit A. Charterer shall pay all mooring, fleeting, switching, clearing, tug assistance, leaving lines,
wharfage tolls, user taxes, or other governmental charges necessary for the towing of barges. Charterer shall pay
for tug charges incurred while dropping and/or picking up barges. If tug service is required to facilitate the safe
or speedy movement of the tow or to assist the tow at locks or bridges, and such tug service for tow assistance
are normally required for tows, then these charges shall be borne by Charterer. Owner will pay all other tug
charges including those required because of mechanical breakdown, crew change, accidents, or operational
shortcomings of the applicable vessel.
11. MAINTENANCE. Owner shall be responsible for maintaining its vessels. Charter shall allow Owner up
to twenty-four (24) hours per month of down time for each vessel chartered hereunder for repairs and
maintenance.
12.
POLLUTION PREVENTION. Owner will, in the case of an escape or discharge of products or
threat of escape or discharge of same from one of its vessels into the navigable waters of the United States, promptly
undertake such measures as are reasonably necessary or which may be required by applicable laws, rules and
regulations to mitigate the resultant pollution damage; provided, however, that Charterer may at its option, and upon
notice to Owner and on the conditions hereinafter set forth, undertake such measures. Charterer shall keep Owner
advised of any such measures to be undertaken by it under such circumstances. Any of such measures actually
undertaken by Charterer shall be at Owner's expense (except to the extent that such escape or discharge was caused
or contributed to by Charterer). If Owner believes that any such measures undertaken by Charterer should not be
undertaken or should be discontinued. Owner may so notify Charterer and thereafter Charterer, if it elects to
continue such measures, shall do so at its own risk and expense.
13.
INDEMNITY. OWNER COVENANTS AND AGREES TO FULLY DEFEND, PROTECT, INDEMNIFY
AND HOLD HARMLESS CHARTERER AND ITS AFFILIATES FROM AND AGAINST EACH AND EVERY CLAIM, DEMAND,
CAUSE OF ACTION, LIABILITY, DAMAGE, COST OR EXPENSE (INCLUDING, BUT NOT LIMITED TO, REASONABLE
ATTORNEY'S FEES AND EXPENSES INCURRED IN THE DEFENSE OF CHARTERER), RESULTING FROM ANY DAMAGE
TO PROPERTY OR INJURY OR DEATH TO PERSONS CAUSED, DIRECTLY OR INDIRECTLY, BY OWNER'S ACTS OR
OMISSIONS IN CONNECTION WITH OWNER'S PROVISION OF MARINE TRANSPORTATION SERVICES HEREUNDER,
EXCEPT TO THE EXTENT CAUSED, DIRECTLY OR INDIRECTLY, BY THE ACTS OR OMISSIONS OF CHARTERER.
CHARTERER COVENANTS AND AGREES TO FULLY DEFEND, PROTECT, INDEMNIFY AND HOLD HARMLESS
OWNER AND ITS AFFILIATES FROM AND AGAINST EACH AND EVERY CLAIM, DEMAND, CAUSE OF ACTION,
LIABILITY, DAMAGE, COST OR EXPENSE (INCLUDING, BUT NOT LIMITED TO, REASONABLE ATTORNEY'S FEES AND
EXPENSES INCURRED IN THE DEFENSE OF OWNER), RESULTING FROM ANY DAMAGE TO PROPERTY OR INJURY OR
DEATH TO PERSONS CAUSED, DIRECTLY OR INDIRECTLY, BY CHARTERER'S ACTS OR OMISSIONS IN CONNECTION
WITH CHARTERER'S USE OF MARINE TRANSPORTATION SERVICES HEREUNDER, EXCEPT TO THE EXTENT CAUSED,
DIRECTLY OR INDIRECTLY, BY THE ACTS OR OMISSIONS OF OWNER.
The foregoing indemnities shall expressly exclude any liability for consequential, punitive, special or
similar damages, including, without limitation, lost profits.
14.
COMPLIANCE WITH LAW. During the Term of this Agreement, Owner shall comply in all
material respects with applicable laws, including, without limitation applicable environmental, health, safety
and financial responsibility laws, rules and regulations, applicable to the use of the vessels for bulk crude oil or
finished lubricating products transportation.
15.
INSURANCE. Owner shall carry the following insurance coverage at its sole expense for the
entire term of this agreement and extensions or renewals thereof with generally acceptable insurance
companies:
1) Hull Insurance subject to not less than the terms and conditions of the 1953 Taylor
Form (REV.70) or its equivalent including S.R. &C.C. in the amount equal to the fair
market value of the vessel(s).
2) Protection & Indemnity Insurance subject to the terms and conditions of not less than
the P&I SP-23 (Revised 1/56) form of policy including collision and towers Liability
and Pollution Buy-Back endorsement in the amount of not less than $1,000,000.00.
3) Pollution Insurance subject to not less than the full limits and conditions available
through the Water Quality Insurance Syndicate for OPA and CERCLA coverage.
4) Excess Liability Insurance underwritten on not less than a following form basis
including excess Protection and Indemnity, Excess Tower’s, Excess Collision and
Excess Pollution Insurance subject to a limit of not less than Ten Million and No/100
Dollars ($10,000,000.00) any one accident or occurrence.
Specified limits of liability may be in any combination of primary and excess coverage. All deductibles with
respect to the insurance coverage required above shall be payable by and for the account of Owner. All
Owner’s insurance policies shall be endorsed as follows:
“It is hereby understood and agreed that Charter and/or any of its respective parent, subsidiary,
affiliate and interrelated companies shall be named as additional insureds with a waiver of
subrogation hereunder.”
Certificates of Insurance shall be furnished to Charterer by Owner’s brokers or underwriters promptly upon
request and further, that Owner shall be obliged to furnish acceptable evidence of the continuity thereof for the
duration of this agreement.
16.
CHARTERER'S REPRESENTATIVES. Charterer's representatives may board any vessel used
under this Agreement at any convenient place to observe cargo-handling operations, to inspect logs and certificates,
and to confirm that Owner is fulfilling its obligations under this Agreement.
17.
DRUG & ALCOHOL ABUSE POLICY. Owner warrants that it will maintain and enforce at all
times during the Term of this Agreement a drug and alcohol abuse policy applicable to its vessels, which complies
in all material respects with the minimum standards promulgated by the U.S. Coast Guard.
18.
CONDITION OF EQUIPMENT. Owner shall, before and at commencement of each voyage by
any vessel under this Agreement, exercise commercially reasonable efforts to ensure that such vessel is seaworthy
and in good operating condition, properly manned, equipped and supplied for the voyage, to ensure that the pipes,
pumps and coils are tight, staunch, and are in good operating condition and fit for the voyage, and to ensure that the
tanks and other spaces in which product is to be carried are in good operating condition and fit for the carriage and
preservation of the same. To the extent required by applicable law, Owner will maintain at all times during the
Term of this Agreement a valid and subsisting certificate or other permit issued by the U.S. Coast Guard (or other
governmental bureau or department having jurisdiction) approving the applicable vessel for the transportation and
carriage of inflammable liquids.
Either party hereto shall have the right to terminate this Agreement in the event
of a material breach by the other party of its obligations hereunder, subject to ten (10) days prior written notice of
DEFAULT.
19.
such breach given by the non-breaching party to the breaching party and the opportunity for such breaching party to
cure such breach during such ten (10) day period.
20.
SUBLET. Charterer shall not be permitted to sublet the use of any vessels to any third party.
21.
FORCE MAJEURE. The vessels, their masters/captains and Owner shall not, unless otherwise
in this Agreement expressly provided, be responsible for any loss or damage arising or resulting from: any act,
default or barratry of the captain, pilots, mariners, or other servants of Owner in the navigation or management of
such vessel; fire, unless caused by the personal design or neglect of Owner; collision, stranding or peril, danger or
accident of navigable waters; saving or attempting to save life or property; wastage in weight or bulk, or any other
loss or damage arising from inherent defect, quality or vice of the cargo; any act or omission of Charterer, Owner,
any other shipper or any consignee of the cargo, their agents or representatives; insufficiency or inadequacy of
marks; explosion, bursting of boilers, breakage of shafts, or any latent defect in hull, equipment or machinery;
unseaworthiness of any vessel unless caused by want or due diligence on the part of Owner to make such vessel
seaworthy or to have it properly manned, equipped and supplied; or from any other cause of whatsoever kind arising
without the actual fault of Owner. And neither the vessels, their masters/captains or Owner, nor the Charterer, shall,
unless otherwise in this Agreement expressly provided, be responsible for any loss or damage or delay or failure in
performing hereunder arising or resulting from; act of God, act of war; act of public enemies, pirates or assailing
thieves; acts of terrorism; arrest or restraint of princes, rulers of people, or seizure under legal process provided bond
is promptly furnished to release such vessel or cargo; strike or lockout or stoppage or restraint of labor from
whatever cause, either partial or general, shortage of labor, or riot or civil commotion.
22.
ASSIGNMENT. Neither party shall assign this Agreement without the express written consent of
the other party.
23.
ENTIRE AGREEMENT. This Agreement shall constitute the entire agreement concerning the
subject hereof between the parties superseding all previous agreements, negotiations and representations made prior
or contemporaneous to the date hereof. This Agreement shall be modified or amended only by written agreement
executed by both parties hereto.
24.
GOVERNING LAW. This Agreement shall be governed by and construed in accordance with
the laws of the State of Texas.
IN WITNESS WHEREOF, the parties have executed this Agreement effective January 1, 2006.
MARTIN OPERATING PARTNERSHIP L.P.
By: Martin Operating GP LLC, Its General Partner
By: Martin Midstream Partners L.P., Its Sole Member
By: Martin Midstream GP LLC, Its General Partner
By: /s/Ruben Martin,
Printed Name: Ruben Martin
Its: President
MIDSTREAM FUEL SERVICE, LLC
By: Martin Resource Management Corporation,
Its Sole Member
By: /s/Ruben Martin,
Printed Name: Ruben Martin
Its: President
SUBSIDIARIES OF
MARTIN MIDSTREAM PARTNERS L.P.
Exhibit 21.1
Subsidiary
Martin Operating GP LLC
Martin Operating Partnership L.P.
Prism Gas Systems GP, L.L.C.
Prism Gas Systems I, L.P.
Jurisdiction of Organization
Delaware
Delaware
Texas
Texas
McLeod Gas Gathering and Processing Company, L.L.C.
Louisiana
Prism Gulf Coast Systems, L.L.C.
Woodlawn Pipeline Co., Inc.
Prism Liquids Pipeline LLC
Texas
Texas
Texas
Consent of Independent Registered Public Accounting Firm
Exhibit 23.1
The Board of Directors
Martin Midstream GP LLC:
We consent to the incorporation by reference in the registration statements (No. 333-148146 , No. 333-117023 and
No. 333-171028) on Form S-3 and (No. 333-140152) on Form S-8 of Martin Midstream Partners L.P. of our reports
dated March 2, 2011, with respect to the consolidated balance sheets of Martin Midstream Partners L.P. and
subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in
capital, comprehensive income, and cash flows for each of the years in the three-year period ended December 31,
2010, and the effectiveness of internal control over financial reporting as of December 31, 2010, which reports
appear in the December 31, 2010 annual report on Form 10-K of Martin Midstream Partners L.P.
/s/ KPMG LLP
Shreveport, Louisiana
March 2, 2011
Independent Auditors’ Consent
Exhibit 23.2
The Board of Directors
Martin Midstream GP LLC:
We consent to the incorporation by reference in the registration statements (No. 333-148146 , No. 333-117023 and
No. 333-171028) on Form S-3 and (No. 333-140152) on Form S-8 of Martin Midstream Partners L.P. and
subsidiaries of our report dated March 2, 2011, with respect to the consolidated balance sheets of Waskom Gas
Processing Company and Subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of
income, partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2010,
which report appears in the December 31, 2010 annual report on Form 10-K of Martin Midstream Partners L.P.
/s/ KPMG LLP
Shreveport, Louisiana
March 2, 2011
CERTIFICATIONS
Exhibit 31.1
I, Ruben S. Martin, certify that:
1.
2.
I have reviewed this annual report on Form 10-K of Martin Midstream Partners L.P.;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report,
fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b.
Designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, 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;
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in
this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over
financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a.
All significant deficiencies and material weaknesses in the design or operation of internal control
over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b.
Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
Date: March 2, 2011
/s/ Ruben S. Martin
Ruben S. Martin,
President and Chief Executive Officer of
Martin Midstream GP LLC,
the General Partner of Martin Midstream Partners L.P.
CERTIFICATIONS
Exhibit 31.2
I, Robert D. Bondurant, certify that:
1.
2.
I have reviewed this annual report on Form 10-K of Martin Midstream Partners L.P.;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report,
fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b.
Designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, 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;
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in
this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over
financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a.
All significant deficiencies and material weaknesses in the design or operation of internal control
over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b.
Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
Date: March 2, 2011
/s/ Robert D. Bondurant
Robert D. Bondurant,
Executive Vice President and Chief Financial Officer of
Martin Midstream GP LLC,
the General Partner of Martin Midstream Partners L.P.
Exhibit 32.1
CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (18 U.S.C.
SECTION 1350)*
In connection with the Annual Report of Martin Midstream Partners L.P., a Delaware limited partnership
(the “Partnership”), on Form 10-K for the year ending December 31, 2010 as filed with the Securities and Exchange
Commission (the “Report”), I, Ruben S. Martin, President and Chief Executive Officer of Martin Midstream GP
LLC, the general partner of the Partnership, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18
U.S.C. Section 1350), that to my knowledge:
(1)
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934; and
(2)
the information contained in the Report fairly presents, in all material respects, the financial
condition and result of operations of the Partnership.
/s/ Ruben S. Martin
Ruben S. Martin,
President and Chief Executive Officer of Martin Midstream GP LLC,
General Partner of Martin Midstream Partners L.P.
March 2, 2011
*A signed original of this written statement required by Section 906 has been provided to Martin Midstream
Partners L.P. (the “Partnership”) and will be retained by the Partnership and furnished to the Securities and
Exchange Commission or its staff upon request. The foregoing certification is being furnished to the Securities and
Exchange Commission and shall not be deemed to be “filed.”
Exhibit 32.2
CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (18 U.S.C.
SECTION 1350)*
In connection with the Annual Report of Martin Midstream Partners L.P., a Delaware limited partnership
(the “Partnership”), on Form 10-K for the year ending December 31, 2010 as filed with the Securities and Exchange
Commission (the “Report”), I, Robert D. Bondurant, Executive Vice President and Chief Financial Officer of Martin
Midstream GP LLC, the general partner of the Partnership, certify, pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002 (18 U.S.C. Section 1350), that to my knowledge:
(1)
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934; and
(2)
the information contained in the Report fairly presents, in all material respects, the financial
condition and result of operations of the Partnership.
/s/ Robert D. Bondurant
Robert D. Bondurant,
Executive Vice President and Chief Financial Officer
of Martin Midstream GP LLC,
General Partner of Martin Midstream Partners L.P.
March 2, 2011
*A signed original of this written statement required by Section 906 has been provided to Martin Midstream
Partners L.P. (the “Partnership”) and will be retained by the Partnership and furnished to the Securities and
Exchange Commission or its staff upon request. The foregoing certification is being furnished to the Securities and
Exchange Commission and shall not be deemed to be “filed.”
M A RTIN MIDSTR e A M PA RTNeRS L .P.
coMPan YinFor Mation
PrinciPaloFFicers
MartinMidstreaMgPllc
rubens.Martiniii
President
Chief executive Officer
robertd.bondurant
executive Vice President
Chief Financial Officer
randalll.tauscher
executive Vice President
Chief Operating Officer
wesleyM.skelton
executive Vice President
Controller
donaldr.neumeyer
executive Vice President
edwardH.grimmiii
Senior Vice President
Marine
scota.shoup
Senior Vice President
Operations
roberte.dunn
Senior Vice President
Prism Gas Systems
Matta.Yost
Senior Vice President
Terminalling and engineering
s.wesleyMartin
Vice President
Business Development
scottboydston
Vice President
Director of Audit Services
ronaldg.garner
Vice President
Fertilizer
JoeMccreery
Vice President
Finance
chrisbooth
Vice President
General Counsel
MelanieMathews
Vice President
Human Resources
alanasumpter
Vice President
Information Technology
tome.redd
Vice President
Natural Gas/LPG Services
MichaelMurley
Vice President
Risk Management
Michaellawrence
Vice President
Sulphur Services
KarenYost
Vice President
Taxation
Johnbenblackburn
Assistant General Counsel
boardoFdirectors
MartinMidstreaMgPllc
rubens.Martiniii
President
Chief executive Officer
Martin Midstream GP LLC
Joen.averett,Jr.
Former President and
Chief executive Officer
Crystal Gas Storage, Inc.
Howardr.Hackney
Director
Texas Bank & Trust
Federal Home Loan Bank of Dallas
c.scottMassey
Certified Public Accountant
C. Scott Massey, CPA LLC
Manager Sandstone Ventures LLC
c.Henry(Hank)still
Of Counsel
Fulbright & Jaworski L.L.P.
byronKelley
Advisory Director of the Partnership
President/Chief executive Officer
CVR Partners, LP
corPorateoFFices
MartinMidstreaMgPllc
4200 B Stone Road
Kilgore, Texas 75662
(903) 983-6200
transFeragent
BNY Mellon Shareowner Services
480 Washington Boulevard
Jersey City, New Jersey 07310
(800) 301-0911
www.bnymellon.com/shareowner
auditors
KPMG LLP
333 Texas Street
Suite 1900
Shreveport, Louisiana 71101
unitstraded
NASDAQ Global Select Market
Symbol: MMLP
investorinForMation
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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Principal Locations Served
natur aL Gas services
Principal Locations Served
suLfur services
•
•
Principal Locations Served
Marine tr ansportation
U.S. Inland and Waterways Served
U.S. Coastwise
• Trans Gulf of Mexico
• Eastern Seaboard to Florida
Principal Locations Served
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TERMINALING
& STORAGE
Natural gas
Sulfur Services
Marine
Transportation
160
140
120
100
80
60
40
20
0
800
700
600
500
400
300
200
100
0
500
400
300
200
100
0
150
135
120
105
90
75
60
45
30
15
0
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
$119
$115
$105
$ 97
$ 36
’06
’07
’08
’09
’10
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
$679
$516
$554
$390
2010 PERCENTAGE OF
$409
OPERATING INCOME
39.90%
’06
’07
’08
’09
’10
suLfur serv ices
2010 Operating Income
$16 MILLION
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
2010 PERCENTAGE OF
OPERATING INCOME
$372
$131
$103
’06
’07
11.58%
$165
$80
’10
’09
’08
2010 Operating Income
$4.7 MILLION
2010 PERCENTAGE OF
OPERATING INCOME
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
39.54%
We process and distribute sulfur produced by oil refineries located in
the United States Gulf Coast region. At our facilities in California and
Texas, we process molten sulfur into prilled sulfur under fee-based volume
contracts and we buy/sell contracts. We also own and operate six sulfur
based fertilizer production plants and one emulsified sulfur blending
plant that primarily manufacture sulfur base-based fertilizer products
for wholesale distribution and industrial users for many industrial and
agriculture applications. Other assets include:
• Sulfuric Acid Production Facility in Plainview, Texas
• Ammonium Sulfate Plant in Plainview, Texas
$76
$78
$68
$ 60
$ 48
2010 Operating Income
$15.9 MILLION
2010 PERCENTAGE OF
OPERATING INCOME
’08
’10
’09
’07
’06
24.87%
2010 Operating Income
$10 MILLION
TERMINALING
& STORAGE
Natural gas
Sulfur Services
Marine
Transportation
160
140
120
100
80
60
40
20
0
800
700
600
500
400
300
200
100
0
500
400
300
200
100
0
150
135
120
105
90
75
60
45
30
15
0
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
$119
$115
$105
$ 97
$ 36
’06
’07
’08
’09
’10
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
$679
$516
$554
$390
$409
2010 PERCENTAGE OF
OPERATING INCOME
’06
’07
’08
’09
’10
39.90%
OPER ATING R EV ENUE
AFTER ELIMINATIONS
(In Millions)
2010 Operating Income
$16 MILLION
$372
2010 PERCENTAGE OF
$165
OPERATING INCOME
$131
$103
$80
’06
’07
’08
’09
’10
11.58%
Marine tr ansportation
2010 Operating Income
OPER ATING R EV ENUE
$4.7 MILLION
AFTER ELIMINATIONS
(In Millions)
2010 PERCENTAGE OF
OPERATING INCOME
$76
$78
$68
39.54%
$ 60
$ 48
FPO
’06
’07
’09
2010 Operating Income
’08
$15.9 MILLION
’10
2010 PERCENTAGE OF
OPERATING INCOME
Our company owns a fleet of marine vessels that transport petroleum
products and by-products primarily in the United States Gulf Coast
region. Transportation services are provided on a fee basis, primarily
under annual contracts. Additionally, operating efficiencies are gained by
having our marine segment manage our sulfur segment’s marine assets.
24.87%
• 44 Marine Tank Barges
• 18 Inland Push Boats
• 5 Offshore Tug Barge Units
2010 Operating Income
$10 MILLION
M I D S T R E A M P A R T N E R S
4200 B Stone Road
Kilgore, Texas 75662
903-983-6200
www.martinmidstream.com