mm ar 2006 cover 5/10/07 11:25 AM Page 1
4200 STONE ROAD
KILGORE, TEXAS 75662
903-983-6200
www.martinmidstream.com
on the cover:
Natural gas processing plant, Waskom, Texas
mm ar 2006 inside cover rev 5/10/07 11:29 AM Page 1
F I N A N C I A L H I G H L I G H T S
(In thousands, except per unit amounts)
F O R T H E Y E A R E N D E D
Total Assets
Revenue
Operating Income
Adjusted EBITDA (1)
Net Income
Distributable Cash Flow (2)
2 0 0 3
–––––––––
2 0 0 4
–––––––––
2 0 0 5
–––––––––
2 0 0 6
–––––––––
$139,685
$188,332
$389,044
$457,461
192,731
294,144
438,443
576,384
11,087
18,918
11,981
15,377
14,729
25,534
12,326
18,026
18,960
33,060
13,880
21,133
26,609
50,459
22,243
32,140
Distributions per Unit (3)
$2.00
$2.10
$2.19
$2.44
(1) See Reconciliation on page following Form 10k.
(2) See Reconciliation on page following Form 10k.
(3) Actual distributions per unit. First quarter 2003 distribution assumes a full quarter distribution.
A R E A S O F O P E R A T I O N S
Terminalling & Storage
Natural Gas Services
Marine Transportation
Sulfur
Fertilizer
Additional operations in:
California
Utah
Illinois
PRINCIPAL OFFICERS
MARTIN MIDSTREAM GP LLC
––––––––––––––––––––––––––––
RUBEN S. MARTIN
President
Chief Executive Officer
ROBERT D. BONDURANT
Executive Vice President
Chief Financial Officer
DONALD R. NEUMEYER
Executive Vice President
Chief Operating Officer
SCOTT D. MARTIN
Executive Vice President
WESLEY M. SKELTON
Executive Vice President
Chief Administrative Officer
pictured above: Don Neumeyer, Bob Bondurant, Scott Martin, Ruben Martin
BOARD OF DIRECTORS
MARTIN MIDSTREAM GP LLC
––––––––––––––––––––––––––––
SCOTT D. MARTIN
Executive Vice President
Martin Midstream GP LLC
C. SCOTT MASSEY
CPA
C. Scott Massey, CPA LLC
Manager
Sandstone Ventures LLC
RUBEN S. MARTIN
President
Chief Executive Officer
Martin Midstream GP LLC
HOWARD R. HACKNEY
Director
Texas Bank & Trust
Federal Home Loan Bank of Dallas
JOHN P. GAYLORD
President
Jacintoport Terminal Company
mm ar 2006 insert rev 5/10/07 11:27 AM Page 2
TO OUR PARTNERS:
Last year, I reported to you my optimism in our diversified
business model going forward and the solid business platform
we had established for future growth. In fact, 2006 was a very
good year for your partnership, as we generated record earn-
ings and record cash flow. In addition, for 2006, we reported a
record $50.5 million in Adjusted EBITDA and customer demand
for our energy midstream services continues to grow. This
growth provides opportunities to expand our infrastructure
and earn attractive returns on our expansions.
Following the increase in our cash distribution for the fourth
quarter of 2006, our current cash distributions are at an annual-
ized rate of $2.48 per unit – up from an annualized rate of $2.00
per unit when we went public in 2002. The total return for 2006,
including unit price appreciation and distributions, was
approximately 20%. While this is an attractive return, I believe
we can improve it going forward with our diversified asset
base, growth strategy and strong management team. The total
return including unit price appreciation and distributions from
November 2002 through 2006 was approximately 120% com-
pared to 67% for the S & P 500 during the same time period.
Our financial performance in 2006 was impacted by increasing
industry costs which are affecting all of our segments, as well as
our organic growth projects and capital maintenance projects.
Our competitors are certainly faced with these same inflationary
pressures. Nonetheless, our focus in 2006 on efficiencies and cus-
tomer service helped us to once again achieve financial growth.
With our five separate, but highly complementary business seg-
ments, MMLP is a unique partnership. We are not as easy to
follow as a pure play partnership, but all of these segments
work well together and collectively reduce our exposure to any
one area of volatility. Our five segments are discussed in the
following pages.
RUBEN S. MARTIN
President and Chief Executive Officer
mm ar 2006 insert rev 5/10/07 11:27 AM Page 3
TERMINALLING & STORAGE
NATURAL GAS SERVICES
The terminalling and storage industry is a key component of
Natural gas is generally produced at the wellhead containing
the petroleum distribution chain. For MMLP, this segment
varying amounts of natural gas liquids (NGLs) as well as certain
encompasses 21 strategically-located facilities across the U.S.
impurities in the gas stream. This untreated natural gas is typi-
Gulf Coast region. Our facilities play a critical role in providing
cally not acceptable to meet specifications of the nation’s major
storage, handling, blending and other ancillary services for
natural gas pipeline systems. Natural gas processing removes
petroleum products, by-products and specialty chemicals on a
these impurities as well as natural gas liquids such as ethane,
fee basis. The business is built on quality service and long term
propane, butane, isobutane, natural gasoline and condensate
relationships with our customers. This asset platform has
from the natural gas. Our acquisition of Prism Gas Systems in
enabled us to grow our business both organically and through
November 2005 marked our entry into natural gas gathering and
acquisitions, as evidenced by a 34% increase in operating
processing and has provided us with a foundation for substantial
income in 2006. Looking ahead to 2007, we expect additional
growth. For example, we are currently expanding our processing
growth in this segment as we continue to expand our termi-
and fractionation capacity by 67% and 32%, respectively. We
nalling and storage facilities.
expect these projects to come online in stages throughout the first
half of 2007. In addition to natural gas gathering and processing,
we have a longstanding presence as a large distributor and mar-
keter of NGLs, such as propane, in the southeast U.S. This was
the original business started by our founder, R.S. Martin Jr., in
1951 and our reputation for quality and dependability in this
business has never been stronger.
mm ar 2006 insert rev 5/10/07 11:28 AM Page 4
MARINE TRANSPORTATION
SULFUR
The marine transportation business is another critical link in the
The sulfur processing, storage and distribution business is a vital
petroleum distribution chain. In the U.S., this industry handles
link to the U.S. refining system. The trend of refining heavier and
30% of petroleum with pipelines, trucks and rail accounting for
more sour crude oil has been unmistakable over the last few
the balance. At MMLP, this segment consists of inland and off-
years and has resulted in an increase of by-product sulfur from
shore tank barges being pushed by power units ranging from 600
the refineries. In addition, new low-sulfur diesel and gasoline
horsepower to 7,000 horsepower. Last year in this letter I dis-
rules are driving investment in refiner upgrades. Demand for
cussed the major repositioning, conversions and acquisitions in
this by-product sulfur is mostly from the phosphate fertilizer
our fleet, which resulted in a temporary decline in results. This
industry. MMLP and our predecessor have nearly 50 years in this
targeted strategy and improved operational excellence resulted
business through our gathering, handling, storing and distribut-
in an increase in this segment’s operating income from $2.4 mil-
ing sulfur by truck, rail, barge and terminal. In 2005 and 2006, we
lion in 2005 to $6.4 million in 2006.
acquired and constructed sulfur processing units on the West
Coast and Gulf Coast. The world sulfur markets are now avail-
able to our customers through this expanded footprint.
(Dollars in millions)
REVENUE
––––––––––––––––––––––––––––––
$576.4
OPERATING INCOME
––––––––––––––––––––––––––––––
$26.6
DISTRIBUTABLE CASH FLOW*
––––––––––––––––––––––––––––––
$32.1
$438.4
$19.0
$294.1
$192.7
$14.7
$11.0
$21.1
$18.0
$15.4
2003
2006
––––––––––––––––––––––––––––––
2004
2005
2003
2006
––––––––––––––––––––––––––––––
2004
2005
2003
2006
––––––––––––––––––––––––––––––
*See Reconciliation on page following Form 10k.
2004
2005
mm ar 2006 insert rev 5/10/07 11:27 AM Page 1
OUTLOOK
Demand and infrastructure requirements for the midstream ener-
gy sector continues to grow. We believe that each of our five seg-
ments will continue to prosper in this environment. Our focus is
to grow in a disciplined, accretive way. Our balance sheet is strong
with over $150 million in overall liquidity and we are well posi-
tioned to future strategic opportunities.
As we continue to pursue our goal of providing our partners with
an attractive total return on their investment, our interests and goals
continue to be closely aligned with those of our public partners.
Martin Resource Management Corporation, our affiliate who pro-
vides us with the necessary personnel to carry out the operation of
our business, has recently started a voluntary employee unit pur-
chase program, whereby its employees can invest a portion of their
payroll dollars in MMLP’s units. Together, our senior management
FERTILIZER
The fertilizer industry is known for its worldwide reach and
team and the employees participating in the unit purchase program
is an essential component of the food chain. The earth’s soil
own over 40% of our outstanding limited partnership units. The
contains less than 20% of the organic plant nutrients needed
commitment of the people who provide us with the services neces-
to meet worldwide food production requirements. As a
sary to carry on our day to day operations is evident in the frequent
result, mineral fertilizer production will continue to grow in
recognition we receive for quality, safety and customer service. My
importance as the world population grows. MMLP occupies
thanks to such people, our Board of Directors, customers and unit
a small niche in the sulfur-based fertilizer products, which is
holders for your support during 2006 as we continue to build value
a small segment of the global fertilizer industry. This seg-
for 2007 and beyond.
ment for MMLP had a disappointing 2006 due to the high
inflationary cost environment and difficulties in securing
adequate feedstock supply. With the upcoming start-up of
our sulfuric acid plant in west Texas expected in May, we
believe much of our concern regarding feedstock supply will
be alleviated. While this segment is less than 10% of
MMLP’s business, these niche products are important to the
agricultural and industrial markets we serve. As such, we
will continue our focus on providing these customers with
high-quality products and services.
RUBEN S. MARTIN
T O T A L R E T U R N S *
(November 2002 through December 2006)
––––––––––––––––––––––––––––––––––––––––––––––––––––––
120%
67%
MMLP
S&P 500
––––––––––––––––––––––––––––––––––––––––––––––––––––––
*Includes unit price appreciation and distributions
mm ar 2006 inside cover rev 5/10/07 11:29 AM Page 1
F I N A N C I A L H I G H L I G H T S
(In thousands, except per unit amounts)
F O R T H E Y E A R E N D E D
Total Assets
Revenue
Operating Income
Adjusted EBITDA (1)
Net Income
Distributable Cash Flow (2)
2 0 0 3
–––––––––
2 0 0 4
–––––––––
2 0 0 5
–––––––––
2 0 0 6
–––––––––
$139,685
$188,332
$389,044
$457,461
192,731
294,144
438,443
576,384
11,087
18,918
11,981
15,377
14,729
25,534
12,326
18,026
18,960
33,060
13,880
21,133
26,609
50,459
22,243
32,140
Distributions per Unit (3)
$2.00
$2.10
$2.19
$2.44
(1) See Reconciliation on page following Form 10k.
(2) See Reconciliation on page following Form 10k.
(3) Actual distributions per unit. First quarter 2003 distribution assumes a full quarter distribution.
A R E A S O F O P E R A T I O N S
Terminalling & Storage
Natural Gas Services
Marine Transportation
Sulfur
Fertilizer
Additional operations in:
California
Utah
Illinois
PRINCIPAL OFFICERS
MARTIN MIDSTREAM GP LLC
––––––––––––––––––––––––––––
RUBEN S. MARTIN
President
Chief Executive Officer
ROBERT D. BONDURANT
Executive Vice President
Chief Financial Officer
DONALD R. NEUMEYER
Executive Vice President
Chief Operating Officer
SCOTT D. MARTIN
Executive Vice President
WESLEY M. SKELTON
Executive Vice President
Chief Administrative Officer
pictured above: Don Neumeyer, Bob Bondurant, Scott Martin, Ruben Martin
BOARD OF DIRECTORS
MARTIN MIDSTREAM GP LLC
––––––––––––––––––––––––––––
SCOTT D. MARTIN
Executive Vice President
Martin Midstream GP LLC
C. SCOTT MASSEY
CPA
C. Scott Massey, CPA LLC
Manager
Sandstone Ventures LLC
RUBEN S. MARTIN
President
Chief Executive Officer
Martin Midstream GP LLC
HOWARD R. HACKNEY
Director
Texas Bank & Trust
Federal Home Loan Bank of Dallas
JOHN P. GAYLORD
President
Jacintoport Terminal Company
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, 2006
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:
Securities Registered Pursuant to Section 12(g) of the Act:
NONE
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 ⌧
Yes ⌧
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, or a non-accelerated filer. See definition
of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer (cid:134) Accelerated filer ⌧ Non-accelerated filer (cid:134)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act).
DAL02:480617.6
Yes (cid:134)
No ⌧
As of June 30, 2006, 9,282,652 common units were outstanding. The aggregate market value of the common units
held by non-affiliates of the registrant as of such date approximated $245,347,657. There were 10,603,808 of the
registrant’s common units and 2,552,018 of the registrant’s subordinated units outstanding as of March 5, 2007.
DOCUMENTS INCORPORATED BY REFERENCE: None.
DAL02:480617.6
TABLE OF CONTENTS
Page
PART I .......................................................................................................................................................................... 1
Business .................................................................................................................................................. 1
Item 1.
Item 1A. Risk Factors .......................................................................................................................................... 26
Item 1B. Unresolved Staff Comments ................................................................................................................. 43
Properties .............................................................................................................................................. 43
Item 2.
Legal Proceedings ................................................................................................................................ 43
Item 3.
Submission of Matters to a Vote of Security Holders .......................................................................... 43
Item 4.
PART II ...................................................................................................................................................................... 43
Item 5. Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity
Securities .............................................................................................................................................. 43
Item 6.
Selected Financial Data ........................................................................................................................ 46
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ............... 47
Item 7A. Quantitative and Qualitative Disclosures about Market Risk ............................................................... 69
Financial Statements and Supplementary Data .................................................................................... 71
Item 8.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ............. 105
Item 9A. Controls and Procedures ..................................................................................................................... 105
Item 9B. Other Information ............................................................................................................................... 105
Item 10. Directors and Executive Officers of the Registrant ............................................................................ 105
Item 11. Executive Compensation .................................................................................................................... 110
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters ................................................................................................................................................ 115
Item 13. Certain Relationships and Related Transactions ................................................................................ 117
Principal Accounting Fees and Services ............................................................................................ 125
Item 14.
PART IV ................................................................................................................................................................... 126
Item 15. Exhibits, Financial Statements Schedules .......................................................................................... 126
DAL02:480617.6
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 five primary business lines include:
• Terminalling and storage services for petroleum products and by-products
• Natural gas services
• Marine transportation services for petroleum products and by-products
•
•
Sulfur gathering, processing and distribution
Fertilizer manufacturing and distribution
The petroleum products and by-products we collect, transport, store and market are produced primarily by
major and independent oil and gas companies who often turn to third parties, such as us, for the transportation and
disposition of these products. In addition to these major and independent oil and gas companies, our primary customers
include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of
these products. We operate primarily in the Gulf Coast region of the United States. This region is a major hub for
petroleum refining, natural gas gathering and processing and support services for the exploration and production
industry.
We were formed in 2002 by Martin Resource Management 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. Martin Resource Management
owns an approximate 38.6% 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.
Martin Resource Management operated our business segments for several years. Martin Resource
Management began operating our natural gas services business in the 1950s and our sulfur business in the 1960s. It
began our marine transportation business in the late 1980s. It entered into our fertilizer and terminalling and storage
businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base
through expansions and strategic acquisitions.
Primary Business Segments
Our primary business segments can be generally described as follows:
•
Terminalling and Storage. We own or operate 17 marine terminal facilities and four inland terminal
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. We also
provide land rental to oil and gas companies along with storage and handling services for lubricants
and fuel oil.
• Natural Gas Services. Through our acquisition of Prism Gas Systems I, L.P. (“Prism Gas”), we have
ownership interests in over 440 miles of natural gas gathering pipelines located in the natural gas
producing regions of Central and East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore
Texas and federal waters in the Gulf of Mexico as well as a 150 MMcfd capacity natural gas
processing plant located in East Texas which is currently being expanded to 250 MMcfd. In addition
to our newly acquired 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 resale to propane retailers, refineries and industrial NGL users in Texas and
DAL02:480617.6
- 1 -
the Southeastern United States. We own three NGL supply and storage facilities with an aggregate
above ground storage capacity of approximately 132,000 gallons and we lease approximately 72
million gallons of underground storage capacity for NGLs.
• Marine Transportation. We own a fleet of 37 inland marine tank barges, 16 inland push boats and four
offshore tug barge units that transport petroleum products and by-products primarily in the United
States Gulf Coast region. We provide these transportation services on a fee basis primarily under
annual contracts. In addition, our marine segment manages our sulfur segment’s marine assets.
•
Sulfur. We gather, process and distribute sulfur predominately produced by oil refineries primarily
located in the United States Gulf Coast region. We process molten sulfur into prilled, or pelletized,
sulfur under both fee-based volume contracts and buy/sell contracts at our facility in Port of Stockton,
California. In December 2005, we completed the construction of an additional sulfur priller at our
Neches terminal in Beaumont, Texas. In July 2005, we acquired the remaining interests in CF Martin
Sulphur L.P. (“CF Martin Sulphur”) not previously owned by us. CF Martin Sulphur gathered,
transported and stored molten sulfur supplied by oil refineries.
• Fertilizer. We own and operate six 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.
2006 Developments and Subsequent Events
Recent Acquisitions
Acquisition of the La Force Marine Vessel. In November 2006, we acquired the La Force, an offshore tug,
for $6.0 million from a third party. This vessel is a 5,100 horse power offshore tug that was rebuilt in 1999 with
new engines installed in 2005. The addition of the La Force to our fleet will eliminate the need for chartered
offshore horsepower.
Acquisition of Asphalt Terminals. In August 2006 and October 2006, respectively, we acquired the assets
of Gulf States Asphalt Company LP and Prime Materials and Supply Corporation (“Prime”), for $4.9 million.
These assets are located in Houston, Texas and Port Neches, Texas. In connection with these acquisitions, we
entered into an agreement with Martin Resource Management, whereby Martin Resource Management will operate
the acquired facilities through a terminalling service agreement based upon throughput rates and will assume all
additional expenses to operate the facilities.
Acquisition of the Corpus Christi Barge Terminal. In July 2006, we acquired a marine terminal located
near Corpus Christi, Texas and associated assets from Koch Pipeline Company, L.P. for $6.2 million, which was all
allocated to property, plant and equipment. The terminal is located on approximately 25 acres of land and includes
three tanks with a combined capacity of approximately 240,000 barrels, pump and piping infrastructure for truck
unloading and product delivery to two oil docks.
Acquisition of the Texan, Ponciana and M450. In January 2006, we acquired the Texan, an offshore tug, and
the Ponciana, an offshore NGL barge, for $5.9 million from Martin Resource Management. In February 2006, we
acquired the M450, an offshore barge, for $1.6 million from a third party.
Other Developments
Increased Quarterly Distribution. We declared a quarterly cash distribution for the fourth quarter of 2006 of
$0.62 per common and subordinated unit on January 22, 2007, reflecting an increase of $0.01 per unit over the
quarterly distribution paid in respect of the third quarter of 2006.
Issuance of Common Units. In December 2006, we issued 470,484 common units to Martin Product Sales
LLC, an affiliate of Martin Resource Management, for approximately $15.3 million, including a capital contribution of
approximately $0.3 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.
DAL02:480617.6
- 2 -
Conversion of Subordinated Units. On November 14, 2006, 850,672 of our 3,402,690 outstanding
subordinated units owned by Martin Resource Management and its subsidiaries converted into common units on a one-
for-one basis following our quarterly cash distribution on such date. Additional conversions of our outstanding
subordinated units may occur in the future provided that certain distribution thresholds contained in our partnership
agreement are met by us.
Public Offering. In January 2006, we completed a follow-on public offering of 3,450,000 common units,
resulting in proceeds of $95.4 million, after payment of underwriters’ discounts, commissions and offering expenses.
Our general partner contributed $2.1 million in cash to us in conjunction with the offering in order to maintain its 2%
general partner interest in us. Of the net proceeds, $62.0 million was used to pay then current balances under our
revolving credit facility and $7.5 million was used to fund a portion of the redemption price for our U.S. Government
Guaranteed Ship Financing Bonds. The remainder of the net proceeds has been or will be used to fund future organic
growth projects.
Business Strategy
The key components of our business strategy are to:
• 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 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.
• 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.
• 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.
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
DAL02:480617.6
- 3 -
•
•
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, distributions 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.
• 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 26 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 23 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.
•
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 Flexibility. We believe the borrowings available under our credit facility and our ability to
issue additional partnership units provide us with the financial flexibility necessary to enable us to
pursue expansion and acquisition opportunities.
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 1990’s, 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.
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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 Terminals. We own or operate 17 marine terminals along the Gulf Coast from Tampa, Florida to
Corpus Christi, Texas. Our terminal assets are located at strategic distribution points for the products we handle and
are in close proximity to our customers. Further, 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.
We are one of the largest operators of marine service 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. We also generate revenues through the distribution and marketing of lubricants.
Lubricants are used in the operation of offshore drilling rigs, offshore production and transmission platforms, and
various ships and equipment engaged in marine transportation. In addition, Martin Resource Management, through
contractual arrangements, pays us for terminalling and storage of fuel oil at these terminal facilities.
Our 17 marine terminals are divided generally into three classes of terminals: (i) full service terminals, (ii) fuel
and lubricant terminals and (iii) specialty petroleum terminals.
Full Service Terminals. We own or operate eight full service terminals. These terminal facilities provide
logistical support services, distribute and market lubricants and provide storage and handling services for fuel oil. 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 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.
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The following is a summary description of our eight full service terminals:
Terminal
Location
Acres
Tanks
Aggregate Capacity
Pelican Island ............ Galveston, Texas
Harbor Island(1) ....... Harbor Island, Texas
Freeport .................... Freeport, Texas
Port O’Connor(2) ...... Port O’Connor, Texas
Sabine Pass(3) .......... Sabine Pass, Texas
Cameron “East”(4) ... Cameron, Louisiana
Cameron “West”(5) .. Cameron, Louisiana
Venice (6) …………. Venice, Louisiana
51.3
25.5
17.8
22.8
23.1
34.3
16.9
2.8
14
10
1
8
11
7
5
2
57,200 Bbls.
37,400 Bbls.
8,300 Bbls.
7,000 Bbls.
18,100 Bbls.
33,000 Bbls.
19,000 Bbls.
15,000 Bbls.
_________
(1) A portion of this terminal is located on land owned by a third party and leased under a lease that expires in
January 2010 and can be extended by us through January 2015.
(2) This terminal is located on land owned by a third party and leased under a lease that expires in March 2009 and
can be extended by us through 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 2016 and can be renewed by us through 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 2008
and can be extended by us through February 2013.
(6) This terminal is located on land owned by a third party and leased under a sublease agreement that expires in
August 2009 and can be extended by us through August 2024.
Fuel and Lubricant Terminals. We own or operate four lubricant and fuel oil terminals located in the Gulf
Coast region that provide storage and handling service for lubricants and fuel oil. We also distribute and market
lubricants at these terminals.
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) ................ Fourchon, Louisiana
Intracoastal City, Louisiana
17
4
17
7
14,900 Bbls.
24,900 Bbls.
34,300 Bbls.
30,100 Bbls.
__________
(1) This terminal is located on land owned by third parties and leased under a lease that expires in September 2007
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 expires in November 2007.
(3) A portion of this terminal is located on land owned by third parties and leased under a lease that expires in April
2009 and can be extended by us through 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.
Specialty Petroleum Terminals. We own or operate five terminal facilities providing storage and handling
services for some or all of the following: anhydrous ammonia, asphalt, sulfur, sulfuric acid, fuel oil, crude oil and other
petroleum products and by-products. Our specialty terminals have an aggregate storage capacity of approximately 1.75
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. 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 expired on December 15,
2006. We are currently leasing this facility on a month-to-month basis and have received a proposal for a new lease
agreement that extends the term of the lease for 10 years with two five year options. Our Stanolind terminal is located
on approximately 11 acres of land owned by Martin Resource Management and us and 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.
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At our Tampa, Neches, Stanolind and Corpus Christi terminals, our customers are primarily large oil refining
and natural gas processing companies. We charge a fixed monthly 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. 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. 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
Tampa(1) ................. Tampa, Florida
Tanks(3)
7
Aggregate
Capacity
719,000 Bbls.
Products
Asphalt and fuel oil
Stanolind(2) ............ Beaumont, Texas
2
160,000 Bbls.
Asphalt and fuel oil
Neches ..................... Beaumont, Texas
7
500,400 Bbls.
Ammonia, asphalt, fuel
oil, sulfuric acid and
fertilizer
Ouachita County ..... Ouachita County,
2
77,500 Bbls.
Crude oil
Arkansas
Corpus Christi ......... Corpus Christi,
3
249,000Bbls.
Fuel oil and diesel
Texas
Description
Marine terminal,
loading/unloading
for vessels,
barges and trucks
Marine terminal,
loading/unloading
for vessels,
barges and trucks
Marine terminal,
loading/unloading
for vessels,
barges, railcars
and trucks
Marine terminal,
loading/unloading
for vessels, barges
and trucks
Marine Terminal,
loading/unloading
barges and vessels
and unloading
trucks
__________
(1) This terminal is located on land owned by the Tampa Port Authority that was leased to us under a lease that
expired in December 2006. We are currently leasing this facility on a month-to-month basis and have received a
proposal for a new lease agreement that extends the term for 10 years with two additional five year extension
options.
(2) A portion of this terminal is located on land owned by Martin Resource Management and on land we own. We
use marine terminal, loading and unloading, and other common use facilities owned by Martin Resource
Management under a perpetual use, ingress-egress and utility facilities easement.
(3) In addition to the tanks listed in the table we own one tank at our Tampa terminal and three tanks at the
Stanolind terminal in connection with our sulfur business. Martin Resource Management owns two tanks at the
Stanolind terminal.
Inland Terminals. We own or operate four inland terminals. At Mont Belvieu, Texas, we own a rail
unloading terminal where we unload and measure petroleum by-products and transport these products via a half-mile
pipeline to Enterprise Products Texas Operating L.P.’s NGL fractionator facility. Our fees for the use of this facility are
based on the number of gallons unloaded at the terminal. In Channelview, Texas, we operate an inland terminal used
for lubricant 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 Houston, 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 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.
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The following is a summary description our inland terminals:
Terminal
Location
Channelview(1) .. Houston, Texas
Aggregate Capacity
10,000 sq. ft.
warehouse
Products
Lubricants
Mont Belvieu .....
Mont Belvieu, Texas
20 rail car spaces
Propane-propylene
mix
South Houston
Asphalt ...............
Port Neches
Asphalt ...............
Houston, Texas
71,000 bbls
Asphalt
Port Neches, Texas
31,250 bbls
Asphalt
Description
Truck
loading/unloading
Rail car unloading
Asphalt Processing
and storage
Asphalt Processing
and storage
__________
(1) This terminal is located on land owned by a third party and leased to us under a lease that expires in May 2009
and can be extended by us to May 2014.
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 or sulfuric acid. As a result, our facilities typically command
higher terminal fees when compared to fees charged for terminalling and storage of other petroleum products.
The principal competitive factors affecting our terminals which provide lubricant distribution and
marketing as well as shore bases at certain terminals, are the locations of the facilities, availability of competing
logistical support services, and the experience of personnel and dependability of service. The distribution and
marketing of our lubricant products is brand sensitive, and we encounter brand loyalty competition. Shore base
rental contracts are generally long-term contracts and provide more protection from competition. Our primary
competitors for both lubricants and shore bases include several independent operations as well as major companies
that maintain their own similarly equipped marine terminals, shore bases and lubricant supply sources.
Natural Gas Services Segment
NGL Industry Overview. NGLs are produced through natural gas processing. They are also a by-product
of crude oil refining. NGL consists of hydrocarbons that are vapors at atmospheric temperatures and pressures but
change to liquid phase under pressure. NGLs include ethane, propane, normal butane, iso butane and natural
gasoline.
Ethane is almost entirely used as a petrochemical feedstock in the production of ethylene and propylene.
Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a fuel for heating, for
industrial applications, as motor fuel and as a refrigerant. Normal butane is used as a petrochemical feedstock, as a
blend stock for motor gasoline and as a component in aerosol propellants. Normal butane can also be made into iso
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butane through isomerization. Iso butane is used in the production of motor gasoline, petrochemical feedstock 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 major domestic oil refiners and natural gas processors.
We transport NGLs using Martin Resource Management’s land transportation fleet or by contracting with common
carriers, owner-operators and railroad tank cars. We typically enter into annual contracts with independent retail
propane distributors to deliver their estimated annual volume requirements based on prevailing market prices. We
believe dependable delivery is very important to these customers and in some cases may be more important than price.
We ensure adequate supply of NGLs through:
•
•
•
storage of NGLs purchased in off-peak months;
efficient use of the transportation fleet of vehicles owned by Martin Resource Management; and
product management expertise to obtain supplies when needed.
The following is a summary description of our owned and leased NGL facilities:
NGL Facility(1)
Location
Capacity
Description
Retail terminals .. Kilgore, Texas
Longview, Texas
Henderson, Texas
Arcadia, Louisiana(2)
Hattiesburg, Mississippi(3)
Mt. Belvieu, Texas(3)
90,000 gallons
30,000 gallons
12,000 gallons
65 million gallons
4.2 million gallons
2.8 million gallons
Retail propane distribution
Retail propane distribution
Retail propane distribution storage
Underground storage
Underground storage
Underground storage
__________
(1) In addition, under a throughput agreement, we are entitled to the sole access to and use of a truck loading and
unloading and pipeline distribution terminal owned by Martin Resource Management 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
330,000 gallons.
(2) 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.
(3) 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.
Our NGL customers that utilize these assets consist of retail propane distributors, industrial processors and
refiners. For the year ended December 31, 2006, we sold approximately 37% of our NGL volume to independent retail
propane distributors located in Texas and the southeastern United States and approximately 63% 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.
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Although the NGL industry is subject to seasonality factors, such factors generally do not affect our natural
gas services business because we do not consume NGLs. 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 Acquisition. On November 10, 2005 we acquired Prism Gas. Following this acquisition, 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 440 miles of natural gas 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 150 MMcfd natural gas processing plant
located in East Texas which is currently being expanded to 250 MMcfd. The underlying assets are in two operating
areas:
North Central Texas and East Texas
•
•
•
•
•
•
The North Central Texas and East Texas area assets consist of the Waskom Processing Plant, the
McLeod Gathering System, the Hallsville Gathering System, the Marshall Line, Bosque County
Pipeline and the East Texas Gathering System.
Waskom Processing Plant — The Waskom Processing Plant, located in Harrison County in East
Texas, currently has 150 MMcfd of processing capacity with full fractionation facilities. In
January 2007, the Waskom fractionator was expanded to a capacity of 12,500 barrels per day. In
addition, an increase in the processing capacity of the plant to 250 MMcfd is expected to be
completed by the end of the second quarter of 2007. For the year ended December 31, 2006, inlet
throughput and NGL fractionation averaged approximately 183 MMcfd and 7,677 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.
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 year ended December 31, 2006, the McLeod
Gathering System gathered approximately 6 MMcfd of natural gas. Prism Gas owns a
consolidated 100% interest in this system.
Hallsville Gathering System — The Hallsville Gathering System, which Prism Gas constructed in
2006, is 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. Prism Gas
owns a consolidated 100% interest in this system.
The Marshall Line — The Marshall Line is a 10” gathering line that Prism Gas began leasing from
Kinder Morgan Texas in 2006. It is located in Harrison County, Texas. The Marshall Line
gathers gas at intermediate pressure and feeds the Waskom Processing Plant. Prism Gas owns a
consolidated 100% interest in the lease.
Bosque County Pipeline — The Bosque County Pipeline, gathers gas in four North Central Texas
counties centered around Bosque County. Prism Gas owns an unconsolidated 20% non-operating
interest in a partnership that owns the lease rights to the assets of the Bosque County Pipeline,
with Panther Pipeline Ltd. owning a 42.5% operating interest and Star of Texas, et al owning the
remaining 37.5% interest.
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•
East Texas Gathering System — The East Texas Gathering System, located in Panola County,
Texas, is comprised of gathering systems built to gather gas produced in this area to market
outlets. Prism Gas owns a consolidated 100% interest in these systems.
The natural gas supply for the Waskom Processing Plant, the McLeod Gathering System, the Hallsville
Gathering System, the Marshall Line and the East Texas Gathering System is derived primarily from natural gas
wells located in the Cotton Valley formation 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 1,878 and 1,512 in calendar years 2006
and 2005, respectively. These annual permit numbers include 22 permits for horizontal wells in 2006 and 10
permits for horizontal wells in 2005. Improved technology, drilling applications and commodity prices have
enhanced the economics of drilling in the Cotton Valley formation. This increase in drilling activity has provided us
with access to newly developed natural gas supplies.
The natural gas supply for the Bosque County Pipeline is expected to be derived primarily from natural gas
wells in the Barnett Shale formation of North Central Texas. The Bosque County Pipeline is located in the southern
extension of the Barnett Shale formation.
Our primary suppliers of natural gas to the Waskom Processing Plant include BP America Production
Company, Centerpoint Energy Gas Transmission Company and Devon Energy Corporation, which collectively
represented approximately 62% of the 160 MMcfd of natural gas supplied in 2005 and approximately 61% of the
183 MMcfd of natural gas supplied for the year ended December 31, 2006. A substantial portion (approximately
35%) 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. The tightening of pipeline dew point
specifications and access to local markets with high NGL demand has resulted in increased trucked-in NGL volumes
at the Waskom Processing Plant. In October 2006, we began construction to expand the fractionator to 12,500 bpd.
to provide additional capacity for this increase in trucked-in NGL volumes. This expansion was completed in late
January 2007.
There are currently three competing processing plants, with another two under construction, that operate or
will operate within a 40-mile radius of our Waskom facility. Drilling activity in the Cotton Valley trend 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. Prior to the Prism Gas acquisition, we were one of the largest purchasers of NGLs at the Waskom
Processing Plant.
The Waskom Processing Plant’s processing contracts are predominately percent-of-liquids (POL) contracts,
in which we retain a portion of the NGLs recovered as a processing fee. The plant also operates under percent-of-
proceeds (POP) contracts in which we retain a portion of both the residue gas and the NGLs as payment for services.
There are currently only two minor contracts for processing on a keep-whole basis. We are not contractually
required to process these keep-whole volumes and, therefore, only process natural gas related to these contracts
under profitable conditions.
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
DAL02:480617.6
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predominately percent-of-proceeds (POP) contracts. Natural gas gathered in the region surrounding the McLeod
Gathering System has two primary outlets, including the Waskom Processing Plant.
Cotton Valley 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 percent-of-liquids (POL) contracts
with a small gathering fee. These contracts are typically lower margin, higher volume contracts. 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.
The Bosque County Pipeline is an approximate 67 mile pipeline located in the Barnett Shale extension.
The pipeline traverses four counties with the most concentrated drilling occurring in Bosque County. In this area
competition is limited due to a lack of existing infrastructure. The lack of infrastructure and the limited
development in the area allow it to generally capture new wells drilled in close proximity to its system.
The East Texas Gathering System was constructed in 2004 to tie producers into Gulf South Pipeline
Company’s gathering system in Panola County, Texas. These lines are sized to handle volumes that are expected to
increase as producers continue to develop Cotton Valley sands in areas that were traditionally marginal. The existing
East Texas Gathering System contracts are all fee-for-service contracts dependent on volumes gathered.
Gulf Coast
•
•
•
The Gulf Coast area assets consist of the Fishhook Gathering System and the Matagorda
Gathering System located offshore and onshore of the Texas Gulf Coast.
Fishhook Gathering System — The Fishhook Gathering System, located in Jefferson County,
Texas and offshore federal waters, gathers and transports gas in both offshore and onshore areas.
For the year ended December 31, 2006, the Fishhook Pipeline gathered and transported
approximately 32 MMcfd of natural gas. Prism Gas owns an unconsolidated 50% non-operating
interest in Panther Interstate Pipeline Energy, LLC, 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 the year ended December 31, 2006, the Matagorda Offshore Gathering System
gathered approximately 10 MMcfd of natural gas. 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 federal waters offshore from Beaumont, Texas and gathers
gas from producers. This area is characterized by strong drilling activity with traditionally high volume, high
decline wells. Typically, two to four of these traditional wells are drilled near the Fishhook Gathering System each
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year. Contracts on this system are 100% fee-for-service contracts with both the gathering fee and the maximum
transmission fee stated in Panther Interstate Pipeline Energy, LLC’s FERC Gas Tariff, on file with the Federal
Energy Regulatory Commission. There are currently two competing pipelines in the area which limit our ability to
increase margins on this system. However, we believe that our existing relationships with active producers will
enable us to capture additional volumes from new production in this area.
The Matagorda Offshore Gathering System gathers gas from producers. Contracts for the offshore portion
of the Matagorda Offshore Gathering System are a combination of fixed transportation fees plus a fixed margin. The
contracts for the onshore portion of the Matagorda Offshore Gathering System are under either a fixed margin or a
fixed 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.
Marine Transportation Segment
Industry Overview. The United States inland waterway system is a vast and heavily used transportation
system. This inland waterway system is composed of a network of interconnected rivers and canals that serve as water
highways and is used to transport vast quantities of products annually. This waterway system extends approximately
26,000 miles, of which 12,000 miles are generally considered significant for domestic commerce.
The Gulf Coast region is a major hub for petroleum refining. Approximately two-thirds of United States
refining capacity expansion in the 1990s occurred in this region. The hydrocarbon refining process generates products
and by-products that require transportation in large quantities from the refinery or processor. Convenient access to and
use of this waterway system by the petroleum and petrochemical industry is a major reason for the current location of
United States refineries and petrochemical facilities. Recent growth in refining and natural gas processing capacity has
increased the volume of petroleum products and by-products transported within the Gulf Coast region, which
consequently has increased the need for transportation, storage and distribution facilities.
The marine transportation industry uses push boats and tugboats as power sources and tank barges for freight
capacity. The combination of the power source and tank barge freight capacity is called a tow.
Marine Fleet. We own a fleet of inland and offshore tows that provide marine transportation of petroleum
products and by-products produced in oil refining and natural gas processing. Our marine transportation system
operates 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 .......
15
22
16
4
4
20,000 bbl and under
20,000 - 30,000 bbl
800 - 1,800
horsepower
40,000 bbl and 95,000
bbl
3,200 - 7,200
horsepower
Asphalt, crude oil, fuel oil,
gasoline and sulfur(1)
Asphalt, crude oil, fuel oil
and gasoline(1)
N/A
Asphalt, fuel oil and NGLs
N/A
__________
(1) One of our 15 inland tank barges with capacity of up to 20,000 bbl, and nine of our 22 inland tank barges with
capacity of 20,000 to 30,000 bbl, are specialized and equipped to transport asphalt.
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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
under spot contracts and under term contracts that typically range from one to 12 months in length.
In order to maintain a balance of pricing flexibility and stable cash flow, we strive to maintain an appropriate
mix of spot versus term contracts, based on current market conditions.
We are a party to a marine transportation agreement effective January 1, 2006 under which we provide marine
transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. This
agreement replaced a prior agreement between us and Martin Resource Management covering marine transportation
services which expired in November 2005. Effective each January 1, this agreement automatically renews for
consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at
least 60 days prior to the expiration of the then-applicable term. The fees we charge Martin Resource Management are
based on applicable market rates.
Competition. We compete primarily with other marine transportation companies. The marine barging
industry has experienced significant consolidation in the past few years. The total number of tank barges and push
boats that operate in the inland waters of the United States declined from approximately 4,200 in 1982 to
approximately 2,900 in 1993 and has reduced to approximately 2,800 since 1993. We believe the earlier decrease
primarily resulted from:
•
•
•
•
•
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.
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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.
Sulfur Segment
Industry Overview. Sulfur is a natural element and is required to produce a variety of industrial products. In
the United States, approximately 11 million tons of sulfur is 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 used in the manufacture of phosphate fertilizers. Approximately
53% of worldwide sulfur consumption is currently used for 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.
In addition to agricultural applications, sulfur (usually in the form of sulfuric acid) is essential for
manufacturing pharmaceuticals, paper, chemicals, paint, steel, petroleum and other products. Sulfuric acid is the most
commonly produced chemical in the world.
Our Operations and Products. Our sulfur segment was established in April 2005, as a result of the
acquisition of the Bay Sulfur assets and the beginning of construction of a sulfur priller at our Neches facility in
Beaumont, Texas. The sulfur prilling assets we acquired from Bay Sulfur 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. We also have completed
the construction of a sulfur priller at our Neches facility in Beaumont, Texas. This facility has the capacity to process
approximately 2,000 metric tons of molten sulfur per day. Our sulfur prilling facilities provide refiners with an
alternative market for the sale of their residual sulfur.
On July 15, 2005, we acquired the remaining partnership interests in CF Martin Sulphur in which we owned a
49.5% interest since November, 2000 from CF Industries, Inc. and certain affiliates of Martin Resource Management
for $18.9 million. Prior to the acquisition, CF Martin Sulphur was managed and operated by its general partner who
was equally owned and controlled by certain affiliates of Martin Resource Management and CF Industries. Subsequent
to the acquisition, the partnership controlled the management of CF Martin Sulphur and conducted its day to day
operations. CF Martin Sulphur, a wholly owned partnership, was included in our consolidated financial statements and
included in the financial presentation of our sulfur segment. As of March 30, 2006, CF Martin Sulphur merged into
Martin Operating Partnership L.P. and continues to be reported in our sulfur segment and operates doing business as
Martin Sulfur.
Martin Sulfur gathers 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 2006, Martin Sulfur handled approximately 1.7 million long tons of sulfur. 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
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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 term of our commercial contracts typically range from one to five years in length. The prices in such
contracts are usually tied to a published market indicator and fluctuate, typically quarterly, 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 that range
from three to five years in duration.
Our Sulfur Facilities. We lease approximately 180 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
M/V Martin Express ....
Inland push boat
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 tanks as part of our molten sulfur business:
Terminal
Location
Tanks
Total Aggregate Capacity
Products Stored
Tampa ...... Tampa, Florida
Stanolind .. Beaumont, Texas
1
3
16,000 long tons
46,500 long tons
Molten sulfur
Molten sulfur
We own the following sulfur prilling facilities as part of our sulfur business:
Terminal
Location
Daily Production Capacity
Products Stored
Stockton ... Stockton, California 1,000 metric tons per day Molten and prilled sulfur
2,000 metric tons per day Molten and prilled sulfur
Neches ...... Beaumont, Texas
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 Tampa, Florida and United States ports on the Gulf of
Mexico. 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.
Fertilizer Segment
Industry Overview. 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. The Fertilizer Institute has estimated that
the earth’s soil contains less than 20% of organic plant nutrients needed to meet worldwide food production needs. As a
result, we believe mineral fertilizer production will continue to be an important industrial market.
Industrial sulfur products 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. The largest consumers of industrial sulfur products are power plants, paper mills and rubber products
manufacturers.
Our Operations and Products. We entered the 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 at the companies, 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.
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Fertilizer and related sulfur products are a natural extension of our business because of our access to sulfur
and our distribution capabilities. This business allows us to leverage the sulfur segment of our business. Our annual
fertilizer and industrial sulfur products sales have grown from approximately 62,000 tons in 1997 to approximately
210,000 tons in 2006 as a result of acquisitions and internal growth.
We manufacture and market the following 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 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 Fertilizer Plants. The following is a summary description of our fertilizer plants:
Facility
Location
Capacity
Description
Two fertilizer plants ..................... Odessa, Texas
Fertilizer plant .............................. Seneca, Illinois
Fertilizer plant .............................. Plainview Texas
Fertilizer plant .............................. Salt Lake City, Utah
Industrial sulfur plant ................... Texarkana, Texas
Fertilizer plant .............................. Beaumont, Texas
70,000 tons/year
36,000 tons/year
180,000 tons/year
25,000 tons/year
18,000 tons/year
70,000 tons/year
Dry sulfur fertilizer production
Dry sulfur fertilizer production
Fertilizer production
Blending and packaging
Emulsified sulfur production
Liquid sulfur fertilizer
Production
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, as well as
to a small number of independent dealers 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 fertilizer products are sold in accordance with our price lists that vary from state to state. We update our
price lists periodically to make seasonal pricing adjustments. If necessary, we adjust our price lists more frequently to
maintain competitive pricing. These products are sold at negotiated prices, generally set on an annual basis. We
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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.
Competition. We compete with several other large fertilizer and sulfur products manufacturers. However, we
believe our close proximity to our customers is a competitive advantage for us. Because our manufacturing plants are
located close to our customer base, we are able to save on freight costs and respond quickly to customer requests, and
we also believe we have greater insight about local market conditions. Additionally, we believe the development of our
sulfur business affords us a secure and reliable source of sulfur materials.
Seasonality. Sales of our agricultural fertilizer are partly seasonal as a result of increased demand during the
growing season. Sales of our industrial sulfur-based products, however, are generally consistent throughout the year. In
2006, approximately 18% of our product sales volumes were to industrial users.
Our Relationship with Martin Resource Management
Martin Resource Management is engaged in the following principal business activities:
•
•
•
•
•
•
•
•
•
providing land transportation of various liquids using a fleet of trucks and road vehicles and road
trailers;
distributing fuel oil, asphalt, sulfuric acid, marine fuel and other liquids;
providing marine bunkering and other shore-based marine services in Alabama, Louisiana, Mississippi
and Texas;
operating a small crude oil gathering business in Stephens, Arkansas;
operating a lube oil processing facility in Smackover, Arkansas;
operating an underground NGL storage facility in Arcadia, 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, an NGL truck loading and unloading and pipeline distribution
terminal in Mont Belvieu, Texas.
We are and will continue to be closely affiliated with Martin Resource Management as a result of the
following relationships.
Ownership
Martin Resource Management owns an approximate 38.6% 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 employees are responsible for conducting our business and operating our
assets on our behalf.
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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 and indirect 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 $49.1 million of direct costs and expenses for the twelve months ended December 31, 2006
compared to $42.1 million for the twelve months ended December 31, 2005. There is no monetary limitation on the
amount we are required to reimburse Martin Resource Management for direct expenses. Under the omnibus
agreement, the reimbursement amount with respect to indirect general and administrative and corporate overhead
expenses was capped at $2.0 million for the period ending October 31, 2006. Subsequently, this amount may be
increased by no more than the percentage increase in the consumer price index. In addition, Martin Resource
Management and us can agree, subject to approval of the Conflicts Committee of our general partner, to adjust this
amount for expansions of our operations and acquisitions. We reimbursed Martin Resource Management for $1.5
million of indirect expenses for the twelve months ended December 31, 2006 compared to $1.3 million for the
twelve months ended December 31, 2005. 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 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 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. The agreements include, but are
not limited to, a motor carrier agreement, a terminal services agreement, a marine transportation agreement, a
product storage agreement, a product supply agreement, a throughput agreement, and a Purchaser Use Easement,
Ingress-Egress Easement and Utility Facilities Easement. Pursuant to the terms of the omnibus agreement, we are
prohibited from entering into certain material agreements with Martin Resource Management without the approval
of the conflicts committee of our general partner’s board of directors.
For a more comprehensive discussion concerning the omnibus agreement and the other agreements that we
have entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related
Transactions – 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 65 million gallons. 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, sulfuric acid and lube
oil product purchases and sulfur and fertilizer payroll reimbursements from Martin Resource Management
accounted for approximately 14%, 7% and 6% of our total cost of products sold during the years ended December
31, 2006, 2005 and 2004, 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 4%, 5% and 8% of our total revenues for the years ended
December 31, 2006, 2005 and 2004, respectively. In connection with the closing of the Tesoro Marine asset
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acquisition, we entered into certain agreements with Martin Resource Management pursuant to which we provide
terminalling and storage and marine transportation services to Midstream Fuel and Midstream Fuel provides
terminal services to us to handle lubricants, greases and drilling fluids.
For a more comprehensive discussion concerning these commercial agreements that we have entered into
with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions --
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.
Our Relationship with CF Martin Sulphur, L.P.
On July 15, 2005, we acquired all of the remaining limited partnership interests in CF Martin Sulphur from
CF Industries, Inc. and certain affiliates of Martin Resource Management. Prior to this transaction, our unconsolidated
non-controlling 49.5% limited partnership interest in CF Martin Sulphur, was accounted for using the equity method of
accounting. In addition, on July 15, 2005, we acquired all of the outstanding membership interests in CF Martin
Sulphur’s general partner. Subsequent to the acquisition, CF Martin Sulphur was a wholly owned partnership which is
included in the consolidated financial presentation of our sulfur segment. Effective March 30, 2006, CF Martin
Sulphur was merged into us.
Prior to July 15, 2005, we were both an important supplier to and customer of CF Martin Sulphur. We
chartered one of our offshore tug/barge tanker units to CF Martin Sulphur for a guaranteed daily rate, subject to certain
adjustments. This charter, which had an unlimited term, was terminated on November 18, 2005. CF Martin Sulphur
paid to have this tug/barge tanker unit reconfigured to carry molten sulfur. In the event CF Martin Sulphur had
terminated this charter agreement, we would have been obligated to reimburse CF Martin Sulphur for a portion of such
reconfiguration costs. As a result of the July 15, 2005 acquisition of all the outstanding interests in CF Martin Sulphur,
this contingent obligation was terminated.
Insurance
Loss of, or damage to, our vessels and cargo is insured through hull and cargo insurance policies. Vessel
operating liabilities such as collision, cargo, environmental and personal injury are insured primarily through our
participation in mutual insurance associations and other reinsurance arrangements, pursuant to which we are potentially
exposed to assessments in the event claims by us or other members exceed available funds and reinsurance. Protection
and indemnity, or 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, or the Pooling Agreement, through which approximately 95% of the world’s commercial shipping
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
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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.
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
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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 Mont Belvieu terminal we use is located in an EPA-designated ozone non-
attainment area, referred to as the Houston-Galveston 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 Houston-Galveston 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
Houston-Galveston 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.
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 or “SWPPPs”) as well as for the prevention and control of
oil spills (referred to as spill prevention, control and countermeasure or “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.
On August 7, 2000, a spill of molten sulfur occurred at our Stanolind terminal near Beaumont, Texas, which
at the time was owned and operated by Martin Gas Sales LLC, a wholly-owned subsidiary of Martin Resource
Management. Martin Gas Sales LLC has since changed its name to Martin Product Sales, LLC. The Texas Department
of Health and Texas Natural Resource Conservation Commission (the predecessor agency to the present-day Texas
Commission on Environmental Quality) investigated the spill and its clean-up. These agencies found that there was no
impact on public health, and that there was no reason to remove the solidified sulfur from the river bottom. However,
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the United States attorney in Beaumont, Texas, initiated an investigation under the criminal provisions of the Clean
Water Act. To avoid protracted litigation and possible criminal claims against employees, Martin Product Sales agreed
to plead guilty to a single felony violation of the federal Clean Water Act and was sentenced to pay a $50,000 fine. As
part of its plea agreement with the United States, Martin Product Sales also agreed to implement a remedial program at
our Stanolind terminal and our sulfur loading facility in Tampa, Florida. Martin Product Sales instituted the remedial
program as of March 1, 2002, and we believe that it has been substantially implemented, although it must remain in
effect for five years. Martin Product Sales does not have any contracts with the United States government that might be
affected by a debarment or listing proceeding, and the United States Attorney’s Office has agreed to inform any agency
initiating a debarment or listing proceeding of the implementation of the remedial program. A previous criminal
conviction, however, may result in increased fines and other sanctions if Martin Product Sales is subsequently
convicted or pleads guilty to a similar offense in the future. Martin Resource Management will indemnify us under the
omnibus agreement for any losses we suffer within five years from November 6, 2002, the date of our initial public
offering that relate to or result from, this event.
Oil Pollution Act
The Oil Pollution Act of 1990, as amended (“OPA”) imposes a variety of regulations on “responsible parties”
related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A
“responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which
an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of
public and private damages including natural resource damages. Under OPA, vessels and shore facilities handling,
storing, or transporting oil are required to develop and implement oil spill response plans, and vessels greater than 300
tons in weight must provide to the United States Coast Guard evidence of financial responsibility to cover the costs of
cleaning up oil spills from such vessels. The OPA also requires that all newly constructed tank barges engaged in oil
transportation in the United States be double hulled and all existing single hull tank barges be retrofitted with double
hulls or phased out by 2015. We believe we are in substantial compliance with all of these oil spill-related and financial
responsibility requirements.
Safety Regulation
The 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.
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
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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-flag vessels be manned by United States citizens. Foreign-flag seamen
generally receive lower wages and benefits than those received by United States citizen seamen. This requirement
significantly increases operating costs of United States-flag vessel operations compared to foreign-flag 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-flag vessel owners. The United States Coast Guard and
American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to
result in higher regulatory compliance costs for United States-flag 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 Panther Interstate Pipeline Energy, LLC. Panther Interstate Pipeline
Energy, LLC’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 (the “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 Panther Interstate Pipeline Energy, LLC may provide to its
customers; the construction of new facilities; the acquisition, extension, expansion or abandonment of services or
facilities; the maintenance and retention of accounts and records; and relationships of affiliated companies involved in
all aspects of the natural gas and energy business.
On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005 (the “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 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.
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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 396
individuals who provide direct support to our operations. None of these employees are represented by labor unions.
Financial Information about Segments
Information regarding our operating revenues and identifiable assets attributable to each of our segments is
presented in Note 19 to our consolidated financial statements included in this annual report on Form 10-K.
Access to Public Filings
We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports
on Form 8-K, and amendments to these reports filed with the Securities and Exchange Commission (“SEC”) under the
Securities and Exchange Act of 1934. These documents may be accessed free of charge on our website at the
following address: www.martinmidstream.com. These documents are provided as soon as is reasonably practicable
after their filing with the SEC. These documents may also be found at the SEC’s website at www.sec.gov. 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.
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Item 1A. Risk Factors
Limited partner interests are inherently different from the capital stock of a corporation, although many of
the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a
business similar to ours. If any of the following risks were actually to occur, our business, financial condition or
results of operations could be materially adversely affected. In this case, we might not be able to pay distributions
on our common units, the trading price of our common units could decline and unitholders could lose all or part of
their investment. These risk factors should be read in conjunction with the other detailed information concerning us
set forth herein.
Risks Relating to Our Business
Important factors that could cause actual results to differ materially from our expectations include, but are not
limited to, the risks set forth below. The risks described below should not be considered to be comprehensive and all-
inclusive. Additional risks that we do not yet know of or that we currently think are immaterial may also impair our
business operations, financial condition and results of operations. If any events occur that give rise to the following
risks, our business, financial condition, or results of operations could be materially and adversely affected, and as a
result, the trading price of our common units could be materially and adversely impacted. Many of such factors are
beyond our ability to control or predict. Unitholders are cautioned not to put undue reliance on forward-looking
statements.
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.
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
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months, and certain river conditions. Additionally, our terminalling and storage and marine transportation operations
and our assets in the Gulf of Mexico, including our barges, push boats, tugboats and terminals, can be adversely
impacted or damaged by hurricanes, tropical storms, tidal waves or other related events. Demand for our lubricants and
the diesel fuel we throughput in our terminalling and storage segment can be affected if offshore drilling operations are
disrupted by weather in the Gulf of Mexico.
National weather conditions have a substantial impact on the demand for our products. Unusually warm
weather during the winter months can cause a significant decrease in the demand for NGL products, fuel oil and
gasoline. Likewise, extreme weather conditions (either wet or dry) can decrease the demand for fertilizer. For example,
an unusually wet spring can delay planting of seeds, which can leave insufficient time to apply fertilizer at the planting
stage. Conversely, drought conditions can kill or severely stunt the growth of crops, thus eliminating the need to nurture
plants with fertilizer. Any of these or similar conditions could result in a decline in our net income and cash flow,
which would reduce our ability to make distributions to our unitholders.
If we incur material liabilities that are not fully covered by insurance, such as liabilities resulting from accidents
on rivers or at sea, spills, fires or explosions, our results of operations and ability to make distributions to our
unitholders could be adversely affected.
Our operations are subject to the operating hazards and risks incidental to terminalling and storage, marine
transportation and the distribution of petroleum products and by-products and other industrial products. These hazards
and risks, many of which are beyond our control, include:
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•
•
•
accidents on rivers or at sea and other hazards that could result in releases, spills and other
environmental damages, personal injuries, loss of life and suspension of operations;
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 and Rita, and their aftermath, may make some types of
insurance more difficult or expensive for us to obtain. As a result, we may be unable to secure the levels and types of
insurance we would otherwise have secured prior to such events. Moreover, the insurance that may be available to us
may be significantly more expensive than our existing insurance coverage.
The price volatility of petroleum products and by-products can reduce our results of operations and ability to
make distributions to our unitholders.
We purchase petroleum products and by-products such as molten sulfur, sulfur derivatives and NGLs, and sell
these products to wholesale and bulk customers and to other end users. Since the closing of the Tesoro Marine asset
acquisition, we and our affiliates also distribute and market lubricants. We also generate revenues through the
terminalling and storage of certain products for third parties. The price and market value of petroleum products and by-
products can be volatile. Our 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. Future price volatility could have an
adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.
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Increasing energy prices could adversely affect our results of operations.
Increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals
and other supplies are recorded in operating expenses. An increase in price of these products would increase our
operating expenses 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.
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 an event of
default or if the payment of a distribution would cause an event of default thereunder. Our leverage and various
limitations in our credit facility may reduce our ability to incur additional debt, engage in certain transactions and
capitalize on acquisition or other business opportunities that could increase cash flows and distributions to our
unitholders.
If we do not have sufficient capital resources for acquisitions or opportunities for expansion, our growth will be
limited.
We intend to explore acquisition opportunities in order to expand our operations and increase our profitability.
We may finance acquisitions through public and private financing, or we may use our limited partner interests for all or
a portion of the consideration to be paid in acquisitions. Distributions of cash with respect to these equity securities or
limited partner interests may reduce the amount of cash available for distribution to the common units. In addition, in
the event our limited partner interests do not maintain a sufficient valuation, or potential acquisition candidates are
unwilling to accept our limited partner interests as all or part of the consideration, we may be required to use our cash
resources, if available, or rely on other financing arrangements to pursue acquisitions. If we use funds from operations,
other cash resources or increased borrowings for an acquisition, the acquisition could adversely impact our ability to
make our minimum quarterly distributions to our unitholders. Additionally, if we do not have sufficient capital
resources or are not able to obtain financing on terms acceptable to us for acquisitions, our ability to implement our
growth strategies may be adversely impacted.
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, including Prism Gas, into
our existing operations or achieve the desired profitability from such acquisitions. These acquisitions may require
substantial capital expenditures and the incurrence of additional indebtedness. If we make acquisitions, our
capitalization and results of operations may change significantly. Further, any acquisition could result in:
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post-closing discovery of material undisclosed liabilities of the acquired business or assets;
the unexpected loss of key employees or customers from the acquired businesses;
difficulties resulting from our integration of the operations, systems and management of the acquired
business; and
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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.
Demand for our terminalling and storage services is substantially dependent on the level of offshore oil and gas
exploration, development and production activity.
The level of offshore oil and gas exploration, development and production activity historically has been
volatile and is likely to continue to be so in the future. The level of activity is subject to large fluctuations in response to
relatively minor changes in a variety of factors that are beyond our control, including:
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•
•
prevailing oil and natural gas prices and expectations about future prices and price volatility;
the cost of offshore exploration for, and production and transportation of, oil and natural gas;
• worldwide demand for oil and natural gas;
•
•
•
•
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.
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 fertilizer businesses are seasonal 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 fertilizer business experiences 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 business lines 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
of 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
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laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation
requirements could have a material adverse effect on our operations and financial position.
The loss or insufficient attention of key personnel could negatively impact our results of operations and ability to
make distributions to our unitholders. Additionally, if neither Ruben Martin nor Scott Martin is the chief
executive officer of our general partner, amounts we owe under our credit facility may become immediately due
and payable.
Our success is largely dependent upon the continued services of members of the senior management team of
Martin Resource Management. Those senior executive officers have significant experience in our businesses and have
developed strong relationships with a broad range of industry participants. The loss of any of these executives could
have a material adverse effect on our relationships with these industry participants, our results of operations and our
ability to make distributions to our unitholders. Additionally, if neither Ruben Martin nor Scott Martin is the chief
executive officer of our general partner, the lender under our credit facility could declare amounts outstanding
thereunder immediately due and payable. If such event occurs, our results of operations and our ability to make
distribution to our unitholders could be negatively impacted.
We do not have employees. We rely solely on officers and employees of Martin Resource Management to
operate and manage our business. Martin Resource Management operates businesses and conducts activities of its own
in which we have no economic interest. There could be competition for the time and effort of the officers and
employees who provide services to our general partner. If these officers and employees do not or cannot devote
sufficient attention to the management and operation of our business, our results of operation and ability to make
distributions to our unitholders may be reduced.
Our loss of significant commercial relationships with Martin Resource Management could adversely impact our
results of operations and ability to make distributions to our unitholders.
Martin Resource Management provides us with various services and products pursuant to various commercial
contracts. The loss of any of these services and products provided by Martin Resource Management could have a
material adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.
Additionally, we provide terminalling and storage 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.
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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 flag vessels. During the
past several years, certain interest groups have lobbied Congress to repeal the Jones Act to facilitate foreign flag
competition for trades and cargoes reserved for United States flagged vessels under the Jones Act and cargo preference
laws. If the Jones Act were to be modified to permit foreign competition that would not be subject to the same United
States government imposed costs, we may need to lower the prices we charge for our services in order to compete with
foreign competitors, which would adversely affect our cash flow and ability to make distributions to our unitholders.
Following Hurricane Katrina and again after Hurricane Rita, emergency suspensions of the Jones Act were effectuated
by the United States government. The last suspension ended on October 24, 2005. Future suspensions of the Jones Act
or other similar actions could result in similar consequences.
Our marine transportation business would be adversely affected if the United States Government purchases or
requisitions any of our vessels under the Merchant Marine Act.
We are subject to the Merchant Marine Act of 1936, which provides that, upon proclamation by the President
of the United States of a national emergency or a threat to the national security, the United States Secretary of
Transportation may requisition or purchase any vessel or other watercraft owned by United States citizens (including
us, provided that we are considered a United States citizen for this purpose). If one of our push boats, tugboats or tank
barges were purchased or requisitioned by the United States government under this law, we would be entitled to be
paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of
charter hire. However, if one of our push boats or tugboats is requisitioned or purchased and its associated tank barge is
left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barge. We
also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or
purchase of any of our push boats, tugboats or tank barges. If any of our vessels are purchased or requisitioned for an
extended period of time by the United States government, such transactions could have a material adverse affect on our
results of operations, cash flow and ability to make distributions to our unitholders.
Regulations affecting the domestic tank vessel industry may limit our ability to do business, increase our costs
and adversely impact our results of operations and ability to make distributions to our unitholders.
The U.S. Oil Pollution Act of 1990, or 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 90. Under OPA 90, substantially all tank vessels that do not have double hulls will be
phased out by 2015 and will not be permitted to enter U.S. ports or trade in U.S. waters. The phase out dates vary
based on the age of the vessel and other factors. All but one of our offshore tank barges are double-hull vessels which
have no phase out date. We have 13 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 90 may require us to make substantial
capital expenditures, which could adversely affect our operations and market position and reduce our cash available for
distribution.
Risks Relating to Our Acquisition of Prism Gas
A decline in the volume of natural gas and NGLs delivered to our facilities could adversely affect our results of
operations, cash flows and financial condition.
Our profitability could be materially impacted by a decline in the volume of natural gas and NGLs
transported, gathered or processed at our facilities. A material decrease in natural gas production, as a result of
depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a
decline in the volume of natural gas and NGLs handled by our facilities.
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The natural gas and NGLs available to our facilities will be derived from reserves produced from existing
wells. These reserves naturally decline over time. To offset this natural decline, our facilities will need access to
additional reserves.
Our profitability is dependent upon prices and market demand for natural gas and NGLs, which are beyond our
control and have been volatile.
We are subject to significant risks due to fluctuations in commodity prices. These risks relate primarily to: (1)
the purchase of certain volumes of natural gas at a price that is a percentage of a relevant index; and (2) certain
processing contracts for Prism Gas whereby we are exposed to natural gas and NGL commodity price risks.
The margins we realize from purchasing and selling a portion of the natural gas that we transport through our
pipeline systems decrease in periods of low natural gas prices because our gross margins are based on a percentage of
the index price. For the years ended December 31, 2006 and 2005, Prism Gas purchased approximately 40% and 54%,
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 2005, the spot price of Henry Hub natural gas ranged from a high of $15.39 per MMBtu to a
low of $5.50 per MMBtu. From January 1, 2006 through December 31, 2006, the same price ranged from $11.23 per
MMBtu to $4.75 per MMBtu. On December 29, 2006 the spot price was $6.30 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;
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 hedging activities may have a material adverse effect on our earnings, profitability, cash flows and financial
condition.
As of December 31, 2006, Prism Gas has hedged approximately 60%, 45% and 14% of its commodity risk by
volume for 2007, 2008 and 2009, respectively. These hedging arrangements are in the form of swaps for crude oil,
natural gas and ethane. We anticipate entering into additional hedges in 2007 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.
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We entered into these derivative transactions with an investment grade subsidiary of a major oil company and
investment grade banks. While we anticipate that future derivative transactions will be entered into with investment
grade counterparties, and that we will actively monitor the credit rating of such counterparties, it is nevertheless
possible that losses will result from counterparty credit risk in the future.
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.”
We typically do not obtain independent evaluations of natural gas reserves dedicated to our gathering and
pipeline systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate.
We make internal evaluations of natural gas reserves based on publicly available information. However, we
typically do not obtain independent evaluations of natural gas reserves connected to our systems due to the
unwillingness of producers to provide reserve information as well as the cost of such evaluations to verify publicly
available information. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or
the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering
systems are less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of
natural gas on our systems in the future could be less than we anticipate. A decline in the volumes of natural gas on our
systems could have a material adverse effect on our business, results of operations, financial condition and our ability
to make cash distributions to our unitholders.
We depend on certain natural gas producer customers for a significant portion of our supply of natural gas and
NGLs. The loss of any of these customers could result in a decline in our volumes, revenues and cash available
for distribution.
We rely on certain natural gas producer customers for a significant portion of our natural gas and NGL supply.
While some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or
replacements of these contracts on favorable terms, if at all. The loss of all or even a portion of the natural gas volumes
supplied by these customers, as a result of competition or otherwise, could have a material adverse effect on our
business, results of operations and financial condition, unless we were able to acquire comparable volumes from other
sources.
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We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to
commodity price risks.
We purchase from producers and other customers a significant amount of the natural gas that flows through
our natural gas gathering, processing and transportation systems for resale to third parties, including natural gas
marketers and end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could
fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than
contracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. While we attempt to
balance our purchases and sales, if our purchases and sales are unbalanced, we will face increased exposure to
commodity price risks and could have increased volatility in our operating income and cash flows.
If third-party pipelines and other facilities interconnected to our natural gas and NGL pipelines and facilities
become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for
distribution could be adversely affected.
We depend upon third party pipelines and other facilities that provide delivery options to and from our
pipelines and facilities for the benefit of our customers. Since we do not own or operate any of these pipelines or other
facilities, their continuing operation is not within our control. If any of these third-party pipelines and other facilities
become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for distribution
could be adversely affected.
The industry in which we operate is highly competitive, and increased competitive pressure could adversely affect
our business and operating results.
We compete with similar enterprises in our respective areas of operation. Some of our competitors are large
oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas
and NGLs than we do. Some of these competitors may expand or construct gathering, processing and transportation
systems that would create additional competition for the services we provide to our customers. In addition, our
customers who are significant producers of natural gas may develop their own gathering, processing and transportation
systems in lieu of using ours. Likewise, our customers who produce NGLs may develop their own systems to transport
NGLs in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to
maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our
customers. All of these competitive pressures could have a material adverse effect on our business, results of
operations, financial condition and ability to make cash distributions to our unitholders.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies
or a change in policy by those agencies may result in increased regulation of our assets, which may cause our
revenues to decline and operating expenses to increase.
We believe that our natural gas gathering operations meet the tests the Federal Energy Regulatory
Commission, or FERC, uses to establish a pipeline’s status as a gatherer exempt from FERC regulation under the
Natural Gas Act of 1938, or 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
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activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to
resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may
not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing
and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While
our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which
may give producers a stronger basis to challenge the rates, terms and conditions of a gathering line providing
transportation service.
Panther Interstate Pipeline Energy, LLC is also subject to regulation by FERC with respect to issues other than
ratemaking
Under the NGA, FERC has the authority to regulate natural gas companies, such as Panther Interstate Pipeline
Energy, LLC with respect to: rates, terms and conditions of service; the types of services Panther Interstate Pipeline
Energy, LLC may provide to its customers; the construction of new facilities; the acquisition, extension, expansion or
abandonment of services or facilities; the maintenance and retention of accounts and records; and relationships of
affiliated companies involved in all aspects of the natural gas and energy business. 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 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.
We currently estimate that we will incur costs of less than $1.0 million between 2006 and 2010 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 he
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.
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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 and its subsidiaries currently hold 2,552,018 subordinated units and 2,632,799
common units. All of the subordinated units will convert into common units at the end of the subordination period and
some may convert earlier.
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, after the subordination period, we may issue an unlimited number of
limited partner interests of any type without a vote of the unitholders. During the subordination period, our general
partner, without the approval of our unitholders, may cause us to issue up to 1,500,000 additional common units. Our
general partner may also cause us to issue an unlimited number of additional common units or other equity securities of
equal rank with the common units, without unitholder approval, in a number of circumstances such as:
•
•
•
•
the issuance of common units in additional public offerings or in connection with acquisitions that
increase cash flow from operations on a pro forma, per unit basis;
the conversion of subordinated units into common units;
the conversion of units of equal rank with the common units into common units under some
circumstances; or
the conversion of our general partner’s general partner interest in us and its incentive distribution rights
into common units as a result of the withdrawal of our general partner.
Our partnership agreement does not restrict our ability to issue equity securities ranking junior to the common
units at any time. Any issuance of additional common units or other equity securities would result in a corresponding
decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions
to and market price of, common units then outstanding.
Under our partnership agreement, our general partner and its affiliates have the right to cause us to register
under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the
terms and conditions of our partnership agreement, these registration rights allow the general partner and its affiliates or
their assignees holding any units to require registration of any of these units and to include any of these units in a
registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to
have these registration rights for two years following its withdrawal or removal as a general partner. In connection with
any registration of this kind, we will indemnify each unitholder participating in the registration and its officers,
directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state
securities laws arising from the registration statement or prospectus. Except as described below, the general partner and
its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws. Our
general partner and its affiliates, with our concurrence, have granted comparable registration rights to their bank group
to which their partnership units have been pledged.
The sale of any common or subordinated units could have an adverse impact on the price of the common units
or on any trading market that may develop.
Unitholders have less power to elect or remove management of our general partner than holders of common
stock in a corporation. Common unitholders will not have sufficient voting power to elect or remove our general
partner without the consent of Martin Resource Management.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters
affecting our business and therefore limited ability to influence 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
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directors on an annual or other continuing basis. Martin Resource Management elects the directors of our general
partner. Although our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and
our unitholders, the directors of our general partner also have a fiduciary duty to manage our general partner in a
manner beneficial to Martin Resource Management and its shareholders.
If unitholders are dissatisfied with the performance of our general partner, they will have a limited ability to
remove our general partner. Our general partner generally may not be removed except upon the vote of the holders of at
least 66 2/3% of the outstanding units voting together as a single class. Because our general partner and its affiliates,
including Martin Resource Management, control 39.4% of our outstanding limited partnership units, our general
partner initially cannot be removed without the consent of it and its affiliates.
If our general partner is removed without cause during the subordination period and units held by our general
partner and its affiliates are not voted in favor of removal, all remaining subordinated units will automatically be
converted into common units and any existing arrearages on the common units will be extinguished. A removal under
these circumstances would adversely affect the common units by prematurely eliminating their contractual right to
distributions and liquidation preference over the subordinated units, which preferences would otherwise have continued
until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of
competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud,
gross negligence or willful or wanton misconduct in its capacity as our general partner. Cause does not include most
cases of charges of poor management of our business, so the removal of our general partner because of the unitholders’
dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the
termination of the subordination period.
Unitholders’ voting rights are further restricted by our partnership agreement provision prohibiting any units
held by a person owning 20% or more of any class of units then outstanding, other than our general partner, its
affiliates, their transferees and persons who acquired such units with the prior approval of our general partner’s
directors, from voting on any matter. In addition, our partnership agreement contains provisions limiting the ability of
unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the
unitholders’ ability to influence the manner or direction of management.
As a result of these provisions, it will be more difficult for a third party to acquire our partnership without first
negotiating the acquisition with our general partner. Consequently, it is unlikely the trading price of our common units
will ever reflect a takeover premium.
Our general partner’s discretion in determining the level of our cash reserves may adversely affect our ability to
make cash distributions to our unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus cash reserves it
determines in its reasonable discretion to be necessary to fund our future operating expenditures. In addition, our
partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper
conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for
future distributions to partners. These cash reserves will affect the amount of cash available for distribution to our
unitholders.
Unitholders may not have limited liability if a court finds that we have not complied with applicable statutes or
that unitholder action constitutes control of our business.
The limitations on the liability of holders of limited partner interests for the obligations of a limited
partnership have not been clearly established in some states. The holder of one of our common units could be held
liable in some circumstances for our obligations to the same extent as a general partner if a court were to determine
that:
• we had been conducting business in any state without compliance with the applicable limited
partnership statute; or
•
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.
DAL02:480617.6
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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.
During the subordination period, our general partner, without the approval of our unitholders, may cause us to
issue up to 1,500,000 additional common units. Our general partner may also cause us to issue an unlimited number of
additional common units or other equity securities of equal rank with the common units, without unitholder approval,
in a number of circumstances such as:
•
•
•
•
the issuance of common units in additional public offerings or in connection with acquisitions that
increase cash flow from operations on a pro forma, per unit basis;
the conversion of subordinated units into common units;
the conversion of units of equal rank with the common units into common units under some
circumstances; or
the conversion of our general partner’s general partner interest in us and its incentive distribution rights
into common units as a result of the withdrawal of our general partner.
After the subordination period, 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.
On November 14, 2006, 850,672 of our 3,402,690 outstanding subordinated units owned by Martin Resource
Management and its subsidiaries converted into common units on a one for one basis following our distribution of
available cash on such date. Additional conversion of our outstanding subordinated units will occur following our
quarterly distributions of available cash provided that certain distribution thresholds are met by us.
DAL02:480617.6
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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 to 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 National Market 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 National Market. The price of our common units may, therefore, be volatile.
Failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley
Act could have a material adverse effect on our unit price.
In order to comply with Section 404 of the Sarbanes-Oxley Act, we periodically document and test our
internal control procedures. Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the
effectiveness of our internal controls over financial reporting and a report by our independent auditors 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
DAL02:480617.6
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addition, if we fail to maintain the adequacy of our internal controls, as such standards are modified, supplemented or
amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have
effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to
achieve and maintain an effective internal control environment could have a material adverse effect on the price of our
common units.
Risks Relating to Our Relationship with Martin Resource Management
Cash reimbursements due to Martin Resource Management may be substantial and will reduce our cash
available for distribution to our unitholders.
Under our omnibus agreement with Martin Resource Management, Martin Resource Management provides us
with corporate staff and support services on behalf of our general partner that are substantially identical in nature and
quality to the 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.
Martin Resource Management owns an approximate 38.6% 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 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.
DAL02:480617.6
- 40 -
• 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 a distribution on the
subordinated units, to make incentive distributions or to accelerate the expiration of the subordination
period.
• 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. Our general
partner may establish reserves for distribution on the subordinated units, but only if those reserves will
not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the
common units for the following four quarters.
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 — Agreements — Omnibus Agreement.” 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.
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. We have not requested, and do not plan to request, a ruling from the IRS
on this or any other matter affecting us.
If we were treated as a corporation for federal income tax purposes, we would pay tax on our income at
corporate rates, which is currently a maximum of 35%, and would likely pay state income tax at various rates.
Distributions to unitholders would generally be taxed again to them as corporate distributions, and no income, gains,
losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, the
cash available for distribution to unitholders would be substantially reduced. Treatment of us as a corporation would
result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore would
likely result in a substantial reduction in the value of the common units.
Current law may change so as to cause us to be taxable as a corporation for federal income tax purposes or
otherwise subject us to entity-level taxation. Our partnership agreement provides that if a law is enacted or existing law
is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-
level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the
target distribution amount will be adjusted to reflect the impact of that law on us.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our
common units and the costs of any contest will be borne by our unitholders and our general partner.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income
tax purposes or any other matter affecting us. 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
DAL02:480617.6
- 41 -
which they trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by all of our
unitholders 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 unit holders’ 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,
Texas and Utah. We may do business or own property in other states or foreign countries in the future. It is the
unitholder’s responsibility to file all federal, state, local and foreign tax returns. Our counsel has not rendered an
opinion on the state, local or foreign tax consequences of an investment in our common units.
DAL02:480617.6
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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.
Item 4.
Submission of Matters to a Vote of Security Holders
None.
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 National Market (“NASDAQ”) under the symbol “MMLP.”
As of March 1, 2007 there were approximately 33 holders of record and approximately 9,559 beneficial owners of our
common units. In addition, as of that date there were 2,552,018 subordinated units representing limited partner
interests outstanding. All of the subordinated units are held by Martin Resource Management and its subsidiaries.
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 2006:
Quarters Ended
March 31, 2006
June 30, 2006
September 30, 2006
December 31, 2006
Fiscal 2005:
Quarters Ended
March 31, 2005
June 30, 2005
September 30, 2005
December 31, 2005
DAL02:480617.6
Common Units
Distributions Declared per Unit
High
$31.95
$32.03
$33.85
$35.60
Low
$28.84
$30.13
$30.53
$30.10
Common
$0.610
$0.610
$0.610
$0.620
Subordinated
$0.610
$0.610
$0.610
$0.620
Common Units
Distributions Declared per Unit
High
$34.20
$33.99
$34.25
$33.04
Low
$29.03
$30.03
$30.19
$29.70
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Common
$0.535
$0.550
$0.570
$0.610
Subordinated
$0.535
$0.550
$0.570
$0.610
On March 2, 2007, the last reported sales price of our common units as reported on the NASDAQ was $36.50
per unit.
In connection with our formation in June 2002, we issued to our general partner a 2% general partner interest
in us in exchange for a capital contribution in the amount of $20 and issued to Martin Resources LLC a 98% limited
partner interest in the partnership in exchange for a capital contribution in the amount of $980 in an offering exempt
from registration under Section 4(2) of the Securities Act of 1933, as amended. On November 1, 2002, in offerings
exempt from registration under Section 4(2) of the Securities Act of 1933, as amended, we (i) issued 1,543,797
subordinated units representing limited partner interests in us (“Subordinated Units”) to Martin Product Sales LLC, in
connection with the contribution to us of Martin Gas Sales LLC’s limited partner interests in Martin Operating
Partnership L.P. (“Operating Partnership”) which holds our operating assets; (ii) issued 620,644 Subordinated Units to
Midstream Fuel Service LLC, in connection with the contribution to us of Midstream Fuel Service LLC’s limited
partner interests in the Operating Partnership; (iii) issued 2,088,921 Subordinated Units to Martin Gas Marine LLC in
connection with the contribution of Martin Gas Marine LLC’s limited partner interests in the Operating Partnership;
and (iv) converted a portion of the existing interest in us owned by Martin Midstream GP LLC into a portion of its 2%
general partner interest and the incentive distribution rights in us.
In connection with our public offering of 1,322,500 common units in February 2004, our general partner
contributed $0.8 million in cash to us in order to maintain its 2% general partner interest in us.
In connection with our acquisition of Prism Gas in November, 2005, 756,480 common units were issued to
certain members of the Prism Gas management team and Martin Resource Management. In addition our general
partner contributed $0.5 million in cash to us in order to maintain its 2% general partner interest in us.
In connection with our public offering of 3,450,000 common units in January, 2006, our general partner
contributed $2.1 million in cash to us in order to maintain its 2% general partner interest in us.
In December 2006, we issued 470,484 common units to Martin Product Sales LLC, an affiliate of Martin
Resource Management, for approximately $15.3 million, including a capital contribution of approximately $0.3 million
made by out general partner in order to maintain its 2% general partner interest in us. This transaction was exempt
from registration pursuant to either Regulation D or Section 4(2) of the Securities Act of 1933, as amended.
On November 14, 2005, 850,672 of our 4,253,362 outstanding subordinated units owned by Martin Resource
Management and its subsidiaries converted into common units on a one-for-one basis following our quarterly cash
distribution on such date. The common units into which the subordinated units were converted were issued in reliance
on Section 3(a)(9) of the Securities Act of 1933, as amended.
On November 14, 2006, 850,672 of our 3,402,690 outstanding subordinated units owned by Martin Resource
Management and its subsidiaries converted into common units on a one-for-one basis following our quarterly cash
distribution on such date. The common units into which the subordinated units were converted were issued in reliance
on Section 3(a)(9) of the Securities Act of 1933, as amended. Additional conversions of our outstanding subordinated
units may occur in the future provided that certain distribution thresholds provided in our partnership agreement are
met by us.
Within 45 days after the end of each quarter, we will distribute all of our available cash, as defined in our
partnership agreement, to unitholders of record on the applicable record date. During the subordination period (as
described below), the common units will have the right to receive distributions of available cash from operating surplus
in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of
the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash
from operating surplus may be made on the subordinated units. Our available cash consists generally of all cash on
hand at the end of the fiscal quarter, less reserves that our general partner determines are necessary to:
•
•
•
provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments, or other agreements; or
provide funds for distributions to our unitholders and to our general partner for any one or more of the
next four quarters;
plus all cash on hand for the quarter resulting from working capital borrowings made after the end of the quarter on
the date of determination of available cash.
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Our general partner has broad discretion to establish cash reserves that it determines are necessary or
appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance
expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce
debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations. Our distributions are
effectively made 98% to unitholders and 2% to our general partner, subject to the payment of incentive distributions to
our general partner if certain target cash distribution levels to common unitholders are achieved. Incentive 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 an event of default, or an event of default is existing, 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.”
The subordination period will extend until the first day of any quarter beginning after September 30, 2009 in
which each of the following tests are met:
•
•
distributions of available cash from operating surplus on each of the outstanding common units and
subordinated units equaled or exceeded the minimum quarterly distribution for each of the three
consecutive, non-overlapping four-quarter periods immediately preceding that date;
the “adjusted operating surplus” as defined in the partnership agreement generated during each of the
three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or
exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and
subordinated units during those periods on a fully diluted basis and the related distribution on the 2%
general partner interest during those periods; and
•
there are no arrearages in payment of the minimum quarterly distribution on the common units.
Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit
and will participate pro rata with the other common units in distributions of available cash.
The following table sets forth information regarding securities authorized for issuance under our equity
compensation plans as of December 31, 2006.
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
725,000
725,000
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 January 24, 2006, 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.
DAL02:480617.6
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Item 6.
Selected Financial Data
The following table sets forth selected financial data and other operating data of Martin Midstream Partners
L.P. and our predecessor. The financial data for the period from January 1, 2002 through November 5, 2002 are
derived from the audited combined financial statements of the assets and operations of Martin Resource Management
that were contributed to us in connection with our initial public offering in November 2002 (“Martin Midstream
Partners Predecessor”). The financial data for the period from November 6, 2002 through December 31, 2002, and for
the years ended December 31, 2003, 2004, 2005 and 2006 are 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.
Partnership
Year Ended
December 31,
2006
2005
2004
(Dollars in thousands)
2003
Period From
November 6,
2002
Through
December 31,
2002
Predecessor
Period From
January 1,
2002 Through
November 5,
2002
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 ......................................................
$ 576,384
$ 438,443
$ 294,144
$192,731
$33,746
$116,160
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
351,820
46,888
8,133
12,642
419,483
—
18,960
1,591
(6,909)
—
238
13,880
—
$ 13,880
229,976
34,475
6,198
8,766
279,415
—
14,729
912
(3,326)
—
11
12,326
—
$ 12,326
150,892
21,590
4,986
4,765
182,233
589
11,087
2,801
(2,001)
—
94
11,981
—
$ 11,981
26,504
3,189
656
747
31,096
—
2,650
599
(345)
—
5
2,909
—
$ 2,909
84,442
17,389
4,662
3,741
110,234
—
5,926
2,565
(3,283)
—
42
5,250
1,959
$ 3,291
Net income per limited partner unit ................
Weighted average limited partner units ..........
$1.69
12,602,000
$1.58
8,583,634
$1.45
8,349,551
$1.64
7,153,362
$.40
7,153,362
Balance Sheet Data (at Period End):
Total assets ......................................................
Due to affiliates ...............................................
Long-term debt ................................................
Partner’s capital (owner’s equity) ...................
$ 457,461
10,474
174,021
198,525
$ 389,044
3,492
192,200
95,565
$ 188,332
429
73,000
75,534
$139,685
560
67,000
45,892
$100,455
—
35,000
47,106
Cash Flow Data:
Net cash flow provided by (used in):
Operating activities .....................................
Investing activities ......................................
Financing activities .....................................
39,317
(95,098)
52,991
32,334
(138,742)
109,689
12,812
(34,322)
22,424
$10,273
(27,621)
17,884
$4,824
(2,116)
(6,287)
$ 316
(1,962)
6,897
Other Financial Data:
Maintenance capital expenditures ...................
Expansion capital expenditures .......................
Total capital expenditures ...............................
12,391
78,267
$ 90,658
5,100
74,110
$ 79,210
5,182
30,234
$ 35,416
2,773
29,159
$ 31,932
157
2,850
$ 3,007
394
1,909
$ 2,303
Cash dividends per common unit (in dollars) .
$ 0.620
$ 0.610
$ 0.535
$ 0.525
$ 0.308
—
DAL02:480617.6
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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 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 five primary business lines include:
• Terminalling and storage services for petroleum products and by-products
• Natural gas services
• Marine transportation services for petroleum products and by-products
•
•
Sulfur gathering, processing and distribution
Fertilizer manufacturing and distribution
The petroleum products and by-products we collect, transport, store and distribute are produced primarily by
major and independent oil and gas companies who often turn to third parties, such as us, for the transportation and
disposition of these products. In addition to these major and independent oil and gas companies, our primary customers
include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of
these products. We operate primarily in the Gulf Coast region of the United States. This region is a major hub for
petroleum refining, natural gas gathering and processing and support services to the exploration and production
industry.
DAL02:480617.6
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2006 Developments and Subsequent Events
Recent Acquisitions
Acquisition of the La Force Marine Vessel. In November 2006, we acquired the La Force, an offshore tug,
for $6.0 million from a third party. This vessel is a 5,100 horse power offshore tug that was rebuilt in 1999 with
new engines installed in 2005. The addition of the La Force to our fleet will eliminate the need for chartered
offshore horsepower.
Acquisition of Asphalt Terminals. In August 2006 and October 2006, respectively, we acquired the assets
of Gulf States Asphalt Company LP and Prime Materials and Supply Corporation for $4.9 million. These assets are
located in Houston, Texas and Port Neches, Texas. In connection with these acquisitions, we entered into an
agreement with Martin Resource Management, whereby Martin Resource Management will operate the acquired
facilities through a terminalling service agreement based upon throughput rates and will assume all additional
expenses to operate the facilities.
Acquisition of the Corpus Christi Barge Terminal. In July 2006, we acquired a marine terminal located
near Corpus Christi, Texas and associated assets from Koch Pipeline Company, LP for $6.2 million, which was all
allocated to property, plant and equipment. The terminal is located on approximately 25 acres of land and includes
three tanks with a combined shell capacity of approximately 240,000 barrels, pump and piping infrastructure for
truck unloading and product delivery to two oil docks.
Acquisition of the Texan, Ponciana and M450. In January 2006, we acquired the Texan, an offshore tug, and
the Ponciana, an offshore NGL barge, for $5.9 million from Martin Resource Management. In February 2006 we
acquired the M450, an offshore barge, for $1.6 million from a third party.
Other Developments
Increased Quarterly Distribution. We declared a quarterly cash distribution for the fourth quarter of 2006 of
$0.62 per common and subordinated unit on January 22, 2007, reflecting an increase of $0.01 per unit over the
quarterly distribution paid in respect of the third quarter of 2006.
Issuance of Common Units. In December 2006, we issued 470,484 common units to Martin Product Sales
LLC, an affiliate of Martin Resource Management, for approximately $15.3 million, including a capital contribution of
approximately $0.3 million made by our general partner to maintain its 2% general partner interest in us. These funds
were used to pay down our revolving line of credit.
Conversion of Subordinated Units. On November 14, 2006, 850,672 of our 3,402,690 outstanding
subordinated units owned by Martin Resource Management and its subsidiaries converted into common units on a one-
for-one basis following our quarterly cash distribution on such date. Additional conversions of our outstanding
subordinated units may occur in the future provided that certain distribution thresholds contained in our partnership
agreement are met by us.
Public Offering. In January 2006, we completed a follow-on public offering of 3,450,000 common units,
resulting in proceeds of $95.4 million, after payment of underwriters’ discounts, commissions and offering expenses.
Our general partner contributed $2.1 million in cash to us in conjunction with the offering in order to maintain its 2%
general partner interest in us. Of the net proceeds, $62.0 million was used to pay then current balances under our
revolving credit facility and $7.5 million was used to fund a portion of the redemption price for our U.S. Government
Guaranteed Ship Financing Bonds. The remainder of the net proceeds has been or will be used to fund future organic
growth projects.
Critical Accounting Policies
Our discussion and analysis of our financial condition and results of operations are based on the historical
consolidated financial statements included elsewhere herein. We prepared these financial statements in conformity
with 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
DAL02:480617.6
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results may differ from these estimates. Currently, we believe that our accounting policies do not require us to make
estimates using assumptions about matters that are highly uncertain. However, we have described below the critical
accounting policies that we believe could impact our consolidated 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 under the Financial Accounting Standards Board (FASB) Statement of Financial Accounting
Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets.”
Derivatives
In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), 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. In early 2006, we adopted a hedging policy that
allows us to use hedge accounting for financial transactions that are designated as hedges. 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, 2006, we had 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 equity.
Product Exchanges
We enter into product exchange agreements with third parties whereby we agree to exchange NGLs with third
parties. We record the balance of NGLs due to other companies under these agreements at quoted market product
prices and the balance of NGLs due from other companies at the lower of cost or market. Cost is determined using the
first-in, first-out method.
In September 2005, the FASB’s Emerging Issues Task Force (“EITF”) issued EITF No. 04-13, Accounting
for Purchases and Sales of Inventory with the Same Counterparty. This pronouncement provides additional
accounting guidance for situations involving inventory exchanges between parties to that contained in APB Opinion
No. 29, Accounting for Nonmonetary Transactions and SFAS 153, Exchanges of Nonmonetary Assets. The standard
is effective for new arrangements entered into in reporting periods beginning after March 15, 2006. The adoption
did not have a material impact on our financial statements.
Revenue Recognition
Revenue for our five 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. 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. LPG distribution revenue is recognized when product is delivered by truck to our LPG
customers, which occurs when the customer physically receives the product. When product is sold in storage, or by
pipeline, we recognize LPG distribution revenue when the customer receives the product from either the storage
facility or pipeline.
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.
Sulfur and Fertilizer – Revenue is recognized when the customer takes title to the product, either at our
plant or the customer facility.
DAL02:480617.6
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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.
Under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other
Intangible Assets, 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 Accounting Principles Board (“APB”)
Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. No portion of the net income
from these entities is included in our operating income.
Prior to July 15, 2005, we used the equity method of accounting for our unconsolidated non-controlling 49.5%
limited partner interest in CF Martin Sulphur. On July 15, 2005, we acquired the remaining interests in CF Martin
Sulphur not previously owned by us. Subsequent to the acquisition, CF Martin Sulphur is included in the consolidated
financial presentation of our sulfur segment
Following our acquisition of Prism Gas Systems I, L.P. (“Prism Gas”) in November 2005, we own an
unconsolidated 50% interest in Waskom Gas Processing Company (“Waskom”), the Matagorda Offshore Gathering
System (“Matagorda”), and Panther Interstate Pipeline Energy LLC (“PIPE”). As a result, these assets are accounted
for by the equity method and we do not include any portion of their net income in operating income.
On June 30, 2006, we, through our 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”). This interest is
accounted for by 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.
We have performed the annual impairment tests as of September 30, 2006, September 30, 2005 and
September 30, 2004, respectively. In performing such tests, we determined we had four “reporting units” which
contained goodwill. These reporting units were four of our reporting segments: natural gas services, marine
transportation, sulfur and fertilizer.
We determined fair value in each reporting unit based on a multiple of current annual cash flows. We
determined such multiple from our recent experience with actual acquisitions and dispositions and valuing potential
acquisitions and dispositions.
Environmental Liabilities
We have historically not 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.
Allowance for Doubtful Accounts
In evaluating the collectibility 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
DAL02:480617.6
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historical collection experience. Based on these assessments, we record both specific and general reserves for bad debts
to reduce the related receivable to the amount we ultimately expect to collect from customers.
Asset Retirement Obligation
In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), we
recognize and measure our asset retirement obligations and the associated asset retirement cost upon acquisition of the
related asset. Subsequent measurement and accounting provisions are in accordance with SFAS 143.
On March 31, 2005, the Financial Accounting Standards Board issued Interpretation No. 47, “Accounting for
Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143. FIN 47, which was effective
for fiscal years ending after December 15, 2005, clarifies that the recognition and measurement provisions of SFAS
143 apply to asset retirement obligations in which the timing or method of settlement may be conditional on a future
event that may or may not be within the control of the entity. We have recognized asset retirement obligations, where
appropriate.
Reclassifications
As previously reported in our Quarterly Report on Form 10-Q for the three months ended September 30,
2005, which was filed with the SEC on November 9, 2005, we converted to a new accounting system in August 2005.
In connection with the system conversion, we closely examined expense classifications under the new system. Upon
review, it was determined that certain payroll, property insurance and property tax expenses that were previously
categorized as selling, general and administrative expenses would be more appropriately classified as operating
expenses or costs of products sold. As a result, those expenses were set up in the new system with the new
classification. Accordingly, it is necessary for us to reclassify the related expense items for fiscal years 2002, 2003 and
2004. Since the reclassifications, as indicated in the tables set forth below, had no impact on the prior periods’
revenues, operating income, cash flows from operations or net income, we have determined that the reclassifications
are not material to our audited financial statements for the prior periods. Nonetheless, we are effecting the
reclassifications for prior periods in order to provide comparative clarity and consistency among the 2002-2004 annual
periods when compared to our financial reporting for our current 2006 fiscal year.
The following tables set forth the effects of the reclassifications on certain line items within our previously
reported consolidated statements of income for the years ended December 31, 2004, 2003, and 2002 (dollars in
thousands), which statements of income and certain relevant footnotes thereto as well as the relevant portions of
Management’s Discussion and Analysis of Financial Condition and Results of Operations for those periods have been
updated.
(In Thousands)
Year Ended December 31, 2004
Cost of products sold (as previously
reported) ..............................................
Cost of products sold (as
reclassified) ..........................................
Operating expenses (as previously
reported) ..............................................
Operating expenses (as reclassified) ......
Selling, general and administrative (as
previously reported) .............................
Selling, general and administrative (as
reclassified) ..........................................
Year Ended December 31, 2003
Cost of products sold (as previously
reported) ..............................................
Cost of products sold (as
reclassified) ..........................................
DAL02:480617.6
Terminalling
and Storage
NGL
Marine
Fertilizer
Sulfur
Total
$ 6,775
$
197,859 $
— $
25,207
$
—
$ 229,841
6,775
6,699
8,494
2,194
399
197,859
—
25,342
928
1,185
1,457
1,200
24,796
24,796
175
175
—
—
—
—
—
1,793
2,766
1,658
2,766
229,976
32,423
34,475
8,385
6,198
Terminalling
and Storage
NGL
Marine
Fertilizer
Sulfur
Total
$
107
$ 128,055 $
—
$ 22,605
$
—
$ 150,767
107
128,055
—
22,730
—
150,892
- 51 -
Operating expenses (as previously
reported) ..............................................
Operating expenses (as reclassified) ......
Selling, general and administrative (as
previously reported) .............................
Selling, general and administrative (as
reclassified) ..........................................
1,413
2,141
1,180
452
1,052
1,314
18,135
18,135
1,362
1,100
305
305
—
—
—
—
20,600
21,590
1,566
1,688
6,101
1,441
1,688
4,986
Year Ended December 31, 2002
Terminalling
and Storage
NGL
Marine
Fertilizer
Sulfur
Consolidating
Reclassification
Total
Cost of products sold (as
previously reported) .....................
Cost of products sold (as
reclassified) ..................................
Operating expenses (as
previously reported) .....................
Operating expenses (as
reclassified) ..................................
Selling, general and
administrative (as
previously reported) .....................
Selling, general and
administrative (as
reclassified) ..................................
$
—
—
1,181
1,724
$
87,189
$
—
$
23,324
$
—
$ (5)
$
110,508
87,189
—
23,762
1,307
17,201
1,632
17,201
—
—
—
—
—
21
21
(5)
110,946
1,266
1,365
524
2,474
1,011
(16)
723
1,040
524
2,036
1,011
(16)
19,710
20,578
6,624
5,318
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. Under the omnibus agreement, we are required to reimburse Martin
Resource Management for the provision of general and administrative services under our partnership agreement,
provided that the reimbursement amount with respect to indirect general and administrative and corporate overhead
expenses was capped at $2.0 million for the period ending October 31, 2006. Subsequently, this amount may be
increased by no more than the percentage increase in the consumer price index. In addition, Martin Resource
Management and us can agree, subject to approval of the Conflicts Committee of our general partner, to adjust this
amount for expansions of our operations and acquisitions. As of March 5, 2007, we have not increased this cap. This
limitation does not apply to the cost of any third party legal, accounting or advisory services received, or the direct
expenses of Martin Resource Management incurred, in connection with acquisition or business development
opportunities evaluated on our behalf. We are required to reimburse Martin Resource Management for all direct and
indirect 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 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. Additionally, we have exclusive access to and use of a truck loading and unloading terminal
and pipeline distribution system owned by Martin Resource Management at Mont Belvieu, Texas. 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 – Agreements.”
Our Relationship with CF Martin Sulphur, L.P.
On July 15, 2005, we acquired all of the remaining limited partnership interests in CF Martin Sulphur from
CF Industries, Inc. and certain affiliates of Martin Resource Management. Prior to this transaction, our unconsolidated
DAL02:480617.6
- 52 -
non-controlling 49.5% limited partnership interest in CF Martin Sulphur, was accounted for using the equity method of
accounting. In addition, on July 15, 2005, we acquired all of the outstanding membership interests in CF Martin
Sulphur’s general partner. Subsequent to the acquisition, CF Martin Sulphur was a wholly owned partnership which is
included in the consolidated financial presentation of our sulfur segment. Effective March 30, 2006, CF Martin
Sulphur was merged into us.
Prior to July 15, 2005, we were both an important supplier to and customer of CF Martin Sulphur. We
chartered one of our offshore tug/barge tanker units to CF Martin Sulphur for a guaranteed daily rate, subject to certain
adjustments. This charter, which had an unlimited term, was terminated on November 18, 2005. CF Martin Sulphur
paid to have this tug/barge tanker unit reconfigured to carry molten sulfur. In the event CF Martin Sulphur had
terminated this charter agreement, we would have been obligated to reimburse CF Martin Sulphur for a portion of such
reconfiguration costs. As a result of the July 15, 2005 acquisition of all the outstanding interests in CF Martin Sulphur,
this contingent obligation was terminated.
Results of Operations
The results of operations for the years ended December 31, 2006, 2005 and 2004 have been derived from the
consolidated financial statements of Martin Midstream Partners L.P.
2006
Year Ended December 31,
2005
(In thousands)
2004
Revenues:
Terminalling and storage .......................................................
Marine transportation ............................................................
$ 24,182
47,835
$ 23,081
35,451
$ 17,919
34,780
Product sales:
Natural gas services ........................................................
Sulfur ..............................................................................
Fertilizer .........................................................................
Terminalling and storage ................................................
Total revenues .........................................................
389,735
61,271
41,326
12,035
576,384
301,676
36,784
31,634
9,817
438,443
203,427
—
29,780
8,238
294,144
Costs and expenses:
Cost of products sold:
Natural gas services ........................................................
Sulfur ..............................................................................
Fertilizer .........................................................................
Terminalling and storage ................................................
Expenses:
Operating expenses ...............................................................
Selling, general and administrative .......................................
Depreciation and amortization ..............................................
Total costs and expenses ................................................
Other operating income ................................................................
Operating income ...........................................................
Other income (expense):
374,218
38,898
36,267
9,787
459,170
65,387
10,977
17,597
553,131
3,356
26,609
291,109
25,657
26,975
8,079
351,820
46,888
8,133
12,642
419,483
—
18,960
197,859
—
25,342
6,775
229,976
34,475
6,198
8,766
279,415
—
14,729
Equity in earnings of unconsolidated entities ........................
Interest expense .....................................................................
Debt prepayment premium ....................................................
Other, net ...............................................................................
Total other income (expense) .........................................
8,547
(12,466)
(1,160)
713
(4,366)
1,591
(6,909)
—
238
(5,080)
912
(3,326)
—
11
(2,403)
Net income ...................................................................................
$ 22,243
$ 13,880
$ 12,326
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
DAL02:480617.6
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expense from revenues. The following table sets forth our operating income by segment, and equity in earnings of
unconsolidated entities, for the years ended December 31, 2006, 2005, and 2004.
2006
Year Ended December 31,
2005
(In thousands)
2004
Operating income:
Terminalling and storage .........................................................
Natural gas services .................................................................
Marine transportation ...............................................................
Sulfur .......................................................................................
Fertilizer ...................................................................................
Indirect selling, general, and administrative expenses .............
$ 12,504
4,239
6,411
4,864
1,844
(3,253)
$ 9,314
6,003
2,384
2,937
1,785
(3,463)
$ 6,749
3,080
5,827
—
1,839
(2,766)
Operating income .................................................................
$ 26,609
$ 18,960
$ 14,729
Equity in earnings of unconsolidated entities...........................
$ 8,547
$ 1,591
$ 912
Our results of operations are discussed on a comparative basis below. We discuss items we do not allocate on
a segment basis, such as equity in earnings of unconsolidated entities, interest expense, and indirect selling, general and
administrative expenses, after the comparative discussion of our results within each segment.
Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005
Our total revenues were $576.4 million for the year ended December 31, 2006 compared to $438.4 million for
the year ended December 31, 2005, an increase of $138.0 million, or 31%. Our cost of products sold was $459.2
million for the year ended December 31, 2006 compared to $351.8 million for the year ended December 31, 2005, an
increase of $107.4 million, or 31%. Our total operating expenses were $65.4 million for the year ended December 31,
2006 compared to $46.9 million for the year ended December 31, 2005, an increase of $18.5 million, or 39%.
Our total selling, general and administrative expenses were $11.0 million for the year ended December 31,
2006 compared to $8.1 million for the year ended December 31, 2005, an increase of $2.9 million, or 36%. Total
depreciation and amortization was $17.6 million for the year ended December 31, 2006 compared to $12.6 million for
the year ended December 31, 2005, an increase of $5.0 million, or 40%. Our other operating income for the year ended
December 31, 2006 was $3.4 million compared to zero for the year ended December 31, 2005. Our total operating
income was $26.6 million for the year ended December 31, 2006 compared to $19.0 million for the year ended
December 31, 2005, an increase of $7.6 million, or 40%.
The results of operations are described in greater detail on a segment basis below.
Terminalling and Storage Segment
The following table summarizes our results of operations in our terminalling and storage segment.
Years Ended December 31,
2006
2005
(In thousands)
Revenues:
Services ..............................................................................................
Products ..............................................................................................
Total Revenues ................................................................................
Cost of products sold ..............................................................................
Operating expenses ................................................................................
Selling, general and administrative expenses .........................................
Depreciation and amortization ...............................................................
Other operating income ..........................................................................
Operating income ...............................................................................
$ 24,182
12,035
36,217
9,787
12,241
112
4,700
9,377
3,127
$ 12,504
$ 23,081
9,817
32,898
8,079
10,879
250
4,376
9,314
—
$ 9,314
DAL02:480617.6
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Revenues. Our terminalling and storage revenues increased $3.3 million, or 10%, for the year ended
December 31, 2006 compared to the year ended December 31, 2005. Service revenue accounted for $1.1 million of
this increase. The service revenue increase was primarily a result of acquisitions of our Corpus Christi terminal, and
two asphalt terminals. Product revenue increased $2.2 million due to an 18% increase in product cost that was passed
through to our customers, and a 5% increase in sales volume.
Cost of products sold. Our cost of products sold increased $1.7 million, or 21% for the year ended December
31, 2006 compared to the year ended December 31, 2005. This increase was primarily a result of a 18% increase in
product cost, and a 5% increase in sales volumes.
Operating expenses. Operating expenses increased $1.4 million, or 13%, for the year ended December 31,
2006 compared to the year ended December 31, 2005. The increase was result of our recent acquisitions made in
2006, and also a result of increased operating activities and an increase in costs of those activities at our terminals.
This accounted for $1.9 million of increased operating expenses, which was offset by a decrease in hurricane
expenses of $0.5 million.
Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.1
million, or 55%, for the year ended December 31, 2006 compared to the year ended December 31, 2005.
Depreciation and amortization. Depreciation and amortization increased $0.3 million, or 7%, for the year
ended December 31, 2006 compared to the year ended December 31, 2005. This increase was primarily a result of our
recent acquisitions.
Other operating income. Other operating income for the year ended December 31, 2006 consisted primarily
of a gain of $3.1 million related to an involuntary conversion of assets. This gain resulted from insurance proceeds
which were greater than the impairment of assets destroyed by hurricanes Katrina and Rita.
In summary, terminalling and storage operating income increased $3.2 million, or 34%, for the year ended
December 31, 2006 compared to the year ended December 31, 2005.
Natural Gas Services Segment
The following table summarizes our results of operations in our natural gas services segment.
Years Ended December 31,
2006
2005
(In thousands)
Revenues ............................................................................................. $ 389,735
Cost of products sold ...........................................................................
374,218
Operating expenses .............................................................................
5,240
4,373
Selling, general and administrative expenses ......................................
Depreciation and amortization ............................................................
1,667
4,237
Other operating income .......................................................................
2
Operating income ............................................................................ $ 4,239
$ 301,676
291,109
2,455
1,753
356
6,003
—
$ 6,003
Equity in Earnings of Unconsolidated Entities ................................... $ 8,547
$ 1,369
NGL Volumes (gallons) ....................................................................
322,904
270,524
Revenues. Our natural gas services revenues increased $88.1 million, or 29%, for the year ended December
31, 2006 compared to the year ended December 31, 2005. Of the increase, $21.2 million is related to sales in our
historical NGL distribution segment. The increase is primarily due from a 10% increase in our average sales price per
gallon in 2006 compared to 2005. This price increase was due to general increase in the prices of NGLs. Our sales
volume in this historical NGL distribution segment was approximately the same for both years.
DAL02:480617.6
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The remaining $66.9 million increase is related to our acquisition of Prism Gas, as we experienced a full year
of operations. These revenues are comprised of $54.2 million of NGL sales, $10.5 million of natural gas sales and $1.6
million of gathering and processing fees. Also, included in the revenue increase was $0.6 million of gains on derivative
contracts.
Costs of product sold. Our cost of products increased $83.1 million, or 29%, for the year ended December 31,
2006 compared to the year ended December 31, 2005. Of the increase, $21.9 million is related to costs in our historical
NGL distribution segment. This increase was higher than the increase in our historical NGL revenues, as our per
gallon margin decreased by 5%. In 2005, our historical NGL distribution segment benefited from extraordinary market
conditions due to Gulf Coast hurricanes. This change in market conditions resulted in a rapid increase in NGL prices
allowing us to surpass our historical NGL margins of approximately $0.025 per gallon and experience a margin of
approximately $0.04 per gallon. For 2006, in our historical NGL segment, we experienced margins of approximately
$.03 per gallon. The balance of the increase of $61.2 million relates to costs resulting from our Prism Gas acquisition,
as we experienced a full year of operations.
Operating expenses. Operating expenses increased $2.8 million, or 115%, for the year ended December 31,
2006 compared to the year ended December 31, 2005. An increase of $1.9 million resulted from the Prism Gas
acquisition, and $0.9 million was a result of additional operating expenses incurred from the East Texas Pipeline
acquisition. Both of these acquisitions occurred in 2005.
Selling, general and administrative expenses. Selling, general and administrative expenses increased $2.6
million, or 149%, for the year ended December 31, 2006 compared to the year ended December 31, 2005. An increase
of $2.3 million was a result of additional expenses incurred from the Prism Gas acquisition, as we experienced a full
year of operations. The remaining increase was a result of increased selling, general, and administrative expenses in
our historical NGL distribution segment.
Depreciation and amortization. Depreciation and amortization increased $1.3 million, or 368%, for the year
ended December 31, 2006 compared to the year ended December 31, 2005. This increase was primarily a result of the
Prism Gas acquisition.
Other operating income. Other operating income for the year ended December 31, 2006 consisted of gains
on the sale of property and equipment.
In summary, our natural gas services operating income decreased $1.8 million, or 29%, for the year ended
December 31, 2006 compared to the year ended December 31, 2005. This decrease is primarily related to an increase
in selling, general and administrative expenses related to the Prism Gas acquisition. Prism Gas, as operator of
Waskom, is required, per the partnership agreement, to perform certain services, including but not limited to accounting
and engineering, for the Waskom partnership. While Prism Gas does receive an operator’s fee based on a percentage
of Waskom’s operating costs, generally the expenses incurred are recovered in equity in earnings of unconsolidated
entities.
Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $8.5 million
for the year ended December 31, 2006 compared to $1.4 for the year ended December 31, 2005. In connection with the
Prism Gas acquisition on November 10, 2005, we acquired an unconsolidated 50% interest in Waskom Gas Processing
Company and the Matagorda Offshore Gathering System. We also acquired 50% interest in Panther Interstate Pipeline
Energy LLC, the owner of the Fishhook Gathering System. As a result, these interests are accounted for using the
equity method of accounting and we do not include any portion of their net income in our operating income.
Marine Transportation Segment
The following table summarizes our results of operations in our marine transportation segment.
DAL02:480617.6
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Years Ended December 31,
2006
2005
(In thousands)
Revenues ............................................................................................ $ 47,835
34,454
Operating expenses ............................................................................
Selling, general and administrative expenses .....................................
587
6,609
Depreciation and amortization ...........................................................
6,185
Other operating income ......................................................................
226
Operating income ........................................................................... $ 6,411
$ 35,451
27,768
357
4,942
2,384
—
$ 2,384
Revenues. Our marine transportation revenues increased $12.4 million, or 35%, for the year ended December
31, 2006 compared to the year ended December 31, 2005. Our offshore revenues increased $9.5 million primarily from
the acquisition of two integrated tug barge units. Our inland marine assets, coupled with leased inland marine assets,
had increased revenues of $3.0 million from increased utilization of our fleet as a result of a geographical redistribution
of our assets on the Gulf Coast. We also had increased contract rates, and operated an additional number of leased
vessels.
For the year ended December 31, 2006, inter-segment sales to our sulfur, terminalling and storage, and
fertilizer segments of $2.3 million were eliminated from our marine transportation segment reducing reported
marine transportation revenue by this amount. Inter-segment sales of $2.1 million were eliminated for the year
ended December 31, 2005.
Operating expenses. Operating expenses increased $6.7 million, or 24%, for the year ended December 31,
2006 compared to the year ended December 31, 2005. The increase was primarily a result of associated costs from our
offshore marine vessel acquisitions. We experienced increases in other operating costs including fuel, salaries and
wages, insurance premiums and repair and maintenance expenses from increased shipyard costs.
Selling, general and administrative expenses. Selling, general & administrative expenses increased $0.2
million, or 64%, for the year ended December 31, 2006 compared to the year ended December 31, 2005.
Depreciation and amortization. Depreciation and amortization increased $1.7 million, or 34%, for the year
ended December 31, 2006 compared to the year ended December 31, 2005. This increase was the result of capital
expenditures made in the last 12 months.
Other operating income. Other operating income for the year ended December 31, 2006 consisted of gains on
the sale of property and equipment.
In summary, our marine transportation operating income increased $4.0 million, or 169%, for the year
ended December 31, 2006 compared to the year ended December 31, 2005.
Sulfur Segment
The following table summarizes our results of operations in our sulfur segment.
Years Ended December 31,
2006
2005
(In thousands)
Revenues ................................................................................................
Cost of products sold ..............................................................................
Operating expenses ................................................................................
Selling, general and administrative expenses .........................................
Depreciation and amortization ...............................................................
Operating income ............................................................................
$61,271
38,898
13,452
1,060
2,997
$ 4,864
$36,784
25,657
5,786
614
1,790
$ 2,937
Equity in Earnings of Unconsolidated Entities ........................................
$ —
$ 222
Sulfur Volumes (long tons) ...................................................................
836.3
533.5
DAL02:480617.6
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Our sulfur operating segment began operations in April 2005 after acquiring a sulfur priller and related assets
located in Stockton, California in the Bay Sulfur acquisition. On January 2, 2006, we placed into service a newly
constructed sulfur priller at our Neches terminal in Beaumont, Texas. On July 15, 2005, we purchased the equity
interests of CF Martin Sulphur not owned by us. Since that date, the results of CF Martin Sulfur have been added to
the results reported in the above table. Prior to July 15, 2005, we owned an unconsolidated noncontrolling 49.5%
limited partnership interest in CF Martin Sulphur, which was accounted for using the equity method of accounting. On
July 15, 2005, CF Martin Sulphur became a wholly-owned subsidiary of the Partnership and all intercompany
transactions were eliminated in consolidation. As of March 30, 2006, CF Martin Sulphur merged into Martin
Operating Partnership L.P. and continues to be reported in our sulfur segment and operates the business as Martin
Sulfur.
The results of operation for the twelve month period ending December 31, 2005, represents operations at the
Stockton, California priller facility from April 2005 through December 2005 and CF Martin Sulphur from July 15,
2005 through December 2005.
Equity in earnings of unconsolidated entities. For the year ended December 31, 2005, equity in earnings of
unconsolidated entities relates to our unconsolidated non-controlling 49.5% limited partner interest in CF Martin
Sulphur prior to July 15, 2005.
Fertilizer Segment
The following table summarizes our results of operations in our fertilizer segment.
Years Ended December 31,
2006
2005
(In thousands)
$ 41,326
Revenues .................................................................................................
36,267
Cost of products sold ...............................................................................
1,591
Selling, general and administrative expenses ..........................................
1,624
Depreciation and amortization ................................................................
Operating income ................................................................................ $ 1,844
$ 31,634
26,975
1,696
1,178
$ 1,785
Fertilizer Volumes (tons) ........................................................................
211.6
138.1
Revenues. Our fertilizer revenues increased $9.7 million, or 31%, for the year ended December 31, 2006
compared to the year ended December 31, 2005. Our sales volume increased 53% due to increased demand from our
customers and new volume sales as a result of our A & A Fertilizer acquisition, which closed in late December 2005.
Offsetting this volume increase was a decrease in our average sales price per ton of 15%. This decrease in of our sales
price per ton was a result of the A & A Fertilizer acquisition. Liquid sulfur product sales from this acquisition are at a
lower sales price per ton than our historical dry sulfur product sales.
Costs of products sold. Our cost of products sold increased $9.3 million, or 34%, for the year ended
December 31, 2006 compared to the year ended December 31, 2005. Although this increase was less than our increase
in sales, we experienced a decreased gross margin per ton. This was a result of competitive pricing pressure and
increased freight costs that we were unable to pass through to our customers.
Selling, general and administrative expenses. Selling, general & administrative expenses decreased $0.1
million, or 6%, for the year ended December 31, 2006 compared to the year ended December 31, 2005.
Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 38%, for the year
ended December 31, 2006 compared to the year ended December 31, 2005 as a result of the A & A Fertilizer
acquisition.
Other operating income Other operating income for the year ended December 31, 2005 consisted of losses on
the sale of property and equipment.
In summary, our fertilizer operating income increased $0.1 million, or 3%, for the year ended December 31,
2006 compared to the year ended December 31, 2005.
Statement of Operations Items as a Percentage of Revenues
DAL02:480617.6
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In the aggregate, our cost of products sold, operating expenses, selling, general and administrative expenses,
and depreciation and amortization have remained relatively constant as a percentage of revenues for the years ended
December 31, 2006 and December 31, 2005. The following table summarizes, on a comparative basis, these items of
our statement of operations as a percentage of our revenues.
Years Ended December 31,
2006
2005
(In thousands)
Revenues .................................................................................................
Cost of products sold ...............................................................................
Operating expenses .................................................................................
Selling, general and administrative expenses ..........................................
Depreciation and amortization ................................................................
100%
80%
11%
2%
3%
100%
80%
11%
2%
3%
Equity in Earnings of Unconsolidated Entities
For the years ended December 31, 2006 and 2005, equity in earnings of unconsolidated entities relates to our
unconsolidated non-controlling 49.5% limited partner interest in CF Martin Sulphur prior to July 15, 2005, the
unconsolidated interest in Bosque County Pipeline subsequent to its acquisition on June 30, 2006 and the
unconsolidated interests in Waskom Gas Processing Company, the Matagorda Offshore Gathering System and Panther
Interstate Pipeline Energy, L.L.C. owned by Prism Gas since its acquisition on November 10, 2005.
Interest Expense
Our interest expense for all operations was $13.6 million for 2006 compared to $6.9 million for 2005, an
increase of $6.7 million, or 97%. This increase was primarily due to an increase in average debt outstanding, an
increase in interest rates throughout 2006 compared to 2005 and a debt prepayment premium of $1.2 million paid in
2006.
Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses were $3.3 million for 2006 compared to $3.5 million for
2005, a decrease of $0.2 million or 6%. This was primarily due to a of $0.5 million in costs relating to compliance with
the requirements of the Sarbanes-Oxley Act of 2002. This decrease was offset by an increase in overhead allocation of
$0.3 million from Martin Resource Management.
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 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. Under the omnibus agreement, the reimbursement amount with respect to indirect
general and administrative and corporate overhead expenses was capped at $2.0 million for the period ending October
31, 2006. Subsequently, this amount may be increased by no more than the percentage increase in the consumer price
index. In addition, Martin Resource Management and us can agree, subject to approval of the Conflicts Committee of
our general partner, to adjust this amount for expansions of our operations and acquisitions. Martin Resource
Management allocated indirect selling, general and administrative expenses of $1.5 million for the year ended
December 31, 2006 compared to $1.3 million for the year ended December 31, 2005.
Year Ended December 31, 2005 Compared to the Year Ended December 31, 2004
Our total revenues were $438.4 million for the year ended December 31, 2005 compared to $294.1 million for
the year ended December 31, 2004, an increase of $144.3 million, or 49%. Our cost of products sold was $351.8
million for the year ended December 31, 2005 compared to $230.0 million for the year ended December 31, 2004, an
DAL02:480617.6
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increase of $121.8 million, or 53%. Our total operating expenses were $46.9 million for the year ended December 31,
2005 compared to $34.5 million for the year ended December 31, 2004, an increase of $12.4 million, or 36%.
Our total selling, general and administrative expenses were $8.1 million for the year ended December 31,
2005 compared to $6.2 million for the year ended December 31, 2004, an increase of $1.9 million, or 31%. Total
depreciation and amortization was $12.6 million for the year ended December 31, 2005 compared to $8.8 million for
the year ended December 31, 2004, an increase of $3.8 million, or 43%. Our operating income was $19.0 million for
the year ended December 31, 2005 compared to $14.7 million for the year ended December 31, 2004, an increase of
$4.3 million, or 29%.
The results of operations are described in greater detail on a segment basis below.
Terminalling and Storage Segment
The following table summarizes our results of operations in our terminalling and storage segment.
Years Ended December 31,
2005
2004
(In thousands)
Revenues:
Services .............................................................................................. $ 23,081
9,817
Products ..............................................................................................
32,898
Total Revenues ................................................................................
8,079
Cost of products sold ..............................................................................
10,879
Operating expenses ................................................................................
250
Selling, general and administrative expenses .........................................
4,376
Depreciation and amortization ...............................................................
$ 9,314
Operating income ...............................................................................
$ 17,919
8,238
26,157
6,775
8,494
399
3,740
$ 6,749
Revenues. Our terminalling and storage revenues increased $6.7 million, or 26%, for the year ended
December 31, 2005 compared to the year ended December 31, 2004. Service revenue accounted for $5.2 million of
this increase. The service revenue increase was primarily a result of owning the Neches and Freeport OOS terminals
for the full year of 2005. This accounted for $3.2 million of the service revenue increase. The balance of the service
revenue increase was a result of increased volumes and terminalling and storage rates at our Gulf Coast shore based
terminals. Product revenue increased $1.6 million due to a 16% increase in product cost that was passed through to our
customers, and a 1% increase in sales volume.
Cost of products sold. Our cost of products sold increased $1.3 million, or 19%, for the year ended December
31, 2005 compared to the year ended December 31, 2004. This increase was primarily a result of a 16% increase in
product cost, and a 1% increase in sales volumes.
Operating expenses. Operating expenses increased $2.4 million, or 28%, for the year ended December 31,
2005 compared to the year ended December 31, 2004. This increase was primarily a result of additional operating
expenses of $1.1 million from the Neches terminal acquisition. These additional expenses were the result of owning
this facility for the full year of 2005. Hurricane expenses accounted for an additional $0.7 million and we also
experienced an increase in natural gas utilities cost of $0.4 million.
Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.1
million, or 37%, for the year ended December 31, 2005 compared to the year ended December 31, 2004. This decrease
was primarily a result of a collection of a previously written off bad debt.
Depreciation and amortization. Depreciation and amortization increased $0.6 million, or 17%, for the year
ended December 31, 2005 compared to the year ended December 31, 2004. This increase was a result of the Neches
terminal acquisition.
In summary, terminalling and storage operating income increased $2.6 million, or 38%, for the year ended
December 31, 2005 compared to the year ended December 31, 2004.
DAL02:480617.6
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Natural Gas Services Segment
The following table summarizes our results of operations in our natural gas services segment.
Years Ended December 31,
2005
2004
(In thousands)
Revenues ................................................................................................. $ 301,676
291,109
Cost of products sold ...............................................................................
2,455
Operating expenses .................................................................................
1,753
Selling, general and administrative expenses ..........................................
356
Depreciation and amortization ................................................................
$ 6,003
Operating income ................................................................................
$ 203,427
197,859
1,185
1,200
103
$ 3,080
Equity in Earnings of Unconsolidated Entities .......................................
$ 1,369
$ —
NGL Volumes (gallons) ..........................................................................
270,524
226,565
Revenues. Our natural gas services revenues increased $98.3 million, or 48%, for the year ended December
31, 2005 compared to the year ended December 31, 2004. Of the increase, $85.5 million is related to our historical
NGL distribution segment. Our average sales price per gallon from our historical NGL distribution segment was 23%
higher in 2005 compared to 2004. Also, our sales volume from our historical NGL distribution segment increased 15%
as a result of increased demand from our retail propane customers as well as increased demand from our industrial
customers.
The remaining $12.8 million increase is related to our acquisition of Prism Gas on November 10, 2005. These
revenues are comprised of $8.8 million of NGL sales, $3.3 million of natural gas sales and $0.2 million of gathering
and processing fees. Also, included in revenue was $0.5 million of gains on derivative contracts.
Costs of product sold. Our cost of products increased $93.3 million, or 47%, for the year ended December 31,
2005 compared to the year ended December 31, 2004. Of the increase, $81.8 million is related to our historical NGL
distribution segment. This increase was less than the corresponding increase in NGL revenues as we were able to
increase our per gallon margins. Much of this margin increase was the result of rapid NGL price increases that occurred
in the third quarter of 2005. These rapid price increases were the result of Hurricanes Katrina and Rita. The balance of
the increase of $11.5 million is a result of the Prism Gas acquisition.
Operating expenses. Operating expenses increased $1.3 million, or 107%, for the year ended December 31,
2005 compared to the year ended December 31, 2004. An increase of $0.8 million was a result of additional operating
expenses incurred from the East Texas Pipeline acquisition, and $0.2 million resulted from the Prism Gas acquisition.
The remaining increase was a result of increased operating costs in our historical NGL distribution segment.
Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.6
million, or 46%, for the year ended December 31, 2005 compared to the year ended December 31, 2004. This increase
was primarily a result of the East Texas Pipeline and Prism Gas acquisitions made in 2005.
Depreciation and amortization. Depreciation and amortization increased $0.3 million, or 246%, for the year
ended December 31, 2005 compared to the year ended December 31, 2004. This increase was primarily a result of the
East Texas Pipeline and Prism Gas acquisitions made in 2005.
In summary, our natural gas services operating income increased $2.9 million, or 95%, for the year ended
December 31, 2005 compared to the year ended December 31, 2004.
Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $1.4 million
for the year ended December 31, 2005. In connection with the Prism Gas acquisition on November 10, 2005, we
acquired an unconsolidated 50% interest in Waskom Gas Processing Company and the Matagorda Offshore Gathering
System. We also acquired 50% interest in Panther Interstate Pipeline Energy LLC, the owner of the Fishhook
Gathering System. As a result, these interests are accounted for using the equity method of accounting and we do not
include any portion of their net income in our operating income.
DAL02:480617.6
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Marine Transportation Segment
The following table summarizes our results of operations in our marine transportation segment.
Years Ended December 31,
2005
2004
(In thousands)
Revenues .................................................................................................
Operating expenses .................................................................................
Selling, general and administrative expenses ..........................................
Depreciation and amortization ................................................................
Operating income ................................................................................
$ 35,451
27,768
357
4,942
$ 2,384
$ 34,780
24,796
175
3,982
$ 5,827
Revenues. Our marine transportation revenues increased $0.7 million, or 2%, for the year ended December
31, 2005 compared to the year ended December 31, 2004. Our inland marine assets, coupled with leased inland marine
assets generated an additional $3.7 million in revenue due to stronger customer demand, higher equipment utilization,
and charging our inland customers the increase in our fuel costs. Partially offsetting these increases in inland revenue
was a decrease of $0.9 million in offshore revenues as a result of decreased utilization and downtime as upgrades were
performed to prepare to handle petroleum products. Because the majority of our inland equipment is on time charter,
the impact of Hurricanes Katrina and Rita was minor.
Intersegment sales of $2.1 million from our marine transportation segment to our sulfur segment were
eliminated, reducing reported marine transportation revenue by this amount. Our sulfur segment accounted for this cost
in operating expense. This intersegment charge has been eliminated from our sulfur segment’s operating expenses.
Prior to July 15, 2005, we owned an unconsolidated, non-controlling 49.5% limited partnership interest in CF Martin
Sulphur, which was accounted for using the equity method of accounting. As of July 15, 2005, CF Martin is now one
of our wholly-owned subsidiaries. As a result, all intercompany transactions are eliminated in consolidation.
Operating expenses. Operating expenses increased $3.0 million, or 12%, for the year ended December 31,
2005 compared to the year ended December 31, 2004. The increase was a result of increased operating costs, including
leased operating equipment, outside towing, fuel expenses, and wage costs.
Selling, general and administrative expenses. Selling, general & administrative expenses increased $0.2
million, or 104%, for the year ended December 31, 2005 compared to the year ended December 31, 2004.
Depreciation and amortization. Depreciation and amortization increased $1.0 million, or 24%, for the year
ended December 31, 2005 compared to the year ended December 31, 2004. This increase was due primarily to
maintenance capital expenditures made in the last 12 months.
In summary, our marine transportation operating income decreased $3.4 million, or 59%, for the year ended
December 31, 2005 compared to the year ended December 31, 2004. Without the new intersegment revenue
eliminations resulting from the establishment of our sulfur segment, operating income would have only decreased $1.3
million, or 23%, for the year ended December 31, 2005 compared to the year ended December 31, 2004.
Sulfur Segment
The following table summarizes our results of operations in our sulfur segment.
Years Ended December 31,
2005
2004
(In thousands)
Revenues ................................................................................................
Cost of products sold ..............................................................................
Operating expenses ................................................................................
Selling, general and administrative expenses .........................................
Depreciation and amortization ...............................................................
Operating income ............................................................................
$36,784
25,657
5,786
614
1,790
$ 2,937
$ —
—
—
—
—
$ —
Equity in Earnings of Unconsolidated Entities ........................................
$ 222
$ 912
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Years Ended December 31,
2005
2004
(In thousands)
Sulfur Volumes (long tons) ...................................................................
533.5
—
Our sulfur operating segment was established in April 2005, as a result of the acquisition of the Bay Sulfur
assets and the beginning of construction of a sulfur priller at our Neches terminal. On July 15, 2005, we purchased the
equity interests of CF Martin Sulphur not owned by us. Since that date, the results of CF Martin Sulfur have been
added to the results reported in the above table. Prior to July 15, 2005, we owned an unconsolidated noncontrolling
49.5% limited partnership interest in CF Martin Sulphur, which was accounted for using the equity method of
accounting. CF Martin Sulphur is now a wholly-owned subsidiary of the Partnership. As a result, subsequent to July
15, 2005 all intercompany transactions were eliminated in consolidation.
Intersegment expense of $2.1 million, which is the charge from our marine transportation segment to our
sulfur segment for the charter of one offshore tug/barge tanker unit and certain inland equipment which was eliminated
from our sulfur segment’s operating expenses.
Equity in earnings of unconsolidated entities. For the years ended December 31, 2005 and 2004, equity in
earnings of unconsolidated entities relates to our unconsolidated non-controlling 49.5% limited partner interest in CF
Martin Sulphur prior to July 15, 2005. Equity in earnings of our unconsolidated interest in CF Martin Sulphur for the
period January 1, 2005 through July 15, 2005 was $0.2 million compared to $0.9 for the year ended December 31,
2004.
Fertilizer Segment
The following table summarizes our results of operations in our fertilizer segment.
Years Ended December 31,
2005
2004
(In thousands)
Revenues ................................................................................................. $ 31,634
26,975
Cost of products sold ...............................................................................
1,696
Selling, general and administrative expenses ..........................................
Depreciation and amortization ................................................................
1,178
Operating income ................................................................................ $ 1,785
$ 29,780
25,342
1,658
941
$ 1,839
Fertilizer Volumes (tons) ........................................................................
138.1
146.2
Revenues. Our fertilizer revenues increased $1.9 million, or 6%, for the year ended December 31, 2005
compared to the year ended December 31, 2004. We experienced a 12% increase in our average sales prices, as we
passed through increased raw materials costs to our customers. Our sales volume decreased by 6% as a result of an
abnormally dry year in certain of our market areas. We also experienced a decrease in sales volume on some of our
specialty products. Unfavorable weather conditions in some of our marked areas contributed to this volume decrease.
Costs of products sold. Our cost of products sold increased $1.6 million, or 6%, for the year ended December
31, 2005 compared to the year ended December 31, 2004. An increase of 9% in our cost per ton of fertilizer products
sold was a result of increased costs of raw materials. Our sales volume decreased 6%, somewhat offsetting the increase
in our cost per ton.
Selling, general and administrative expenses. Selling, general & administrative expenses were approximately
the same for both years.
Depreciation and amortization. Depreciation and amortization increased $0.2 million, or 25%, for the year
ended December 31, 2005 compared to the year ended December 31, 2004.
In summary, our fertilizer operating income was approximately the same for both years.
Statement of Operations Items as a Percentage of Revenues
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In the aggregate, our cost of products sold, operating expenses, selling, general and administrative expenses,
and depreciation and amortization have remained relatively constant as a percentage of revenues for the years ended
December 31, 2005 and December 31, 2004. The following table summarizes, on a comparative basis, these items of
our statement of operations as a percentage of our revenues.
Years Ended December 31,
2005
2004
(In thousands)
Revenues .................................................................................................
Cost of products sold ...............................................................................
Operating expenses .................................................................................
Selling, general and administrative expenses ..........................................
Depreciation and amortization ................................................................
100%
80%
11%
2%
3%
100%
78%
12%
2%
3%
Equity in Earnings of Unconsolidated Entities
For the years ended December 31, 2005 and 2004, equity in earnings of unconsolidated entities relates to our
unconsolidated non-controlling 49.5% limited partner interest in CF Martin Sulphur prior to July 15, 2005 and the
unconsolidated interests in Waskom Gas Processing Company, the Matagorda Offshore Gathering System and Panther
Interstate Pipeline Energy, L.L.C. owned by Prism Gas since its acquisition on November 10, 2005.
Interest Expense
Our interest expense for all operations was $6.9 million for 2005 compared to $3.3 million for 2004, an
increase of $3.6 million, or 109%. This increase was primarily due to an increase in average debt outstanding and an
increase in interest rates in 2005 compared to 2004. Additionally, interest expense was offset by a decrease in
amortization of deferred debt costs of $0.3 million for 2005 compared to 2004.
Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses were $3.5 million for 2005 compared to $2.8 million for
2004, an increase of $0.7 million or 25%. This increase was due to increased overhead allocation of $0.2 million from
Martin Resource Management, increased costs related to complying with the requirements of the Sarbanes-Oxley Act
of 2002 of $0.2 million, and increased costs for legal, audit, consulting and professional fees of $0.3 million.
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 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. Under the omnibus agreement, the reimbursement amount with respect to indirect
general and administrative and corporate overhead expenses was capped at $2.0 million for the period ending October
31, 2006. Subsequently, this amount may be increased by no more than the percentage increase in the consumer price
index. In addition, Martin Resource Management and us can agree, subject to approval of the Conflicts Committee of
our general partner, to adjust this amount for expansions of our operations and acquisitions. Martin Resource
Management allocated indirect selling, general and administrative expenses of $1.3 million for the year ended
December 31, 2005 compared to $1.1 million for the year ended December 31, 2004.
Liquidity and Capital Resources
Cash Flows and Capital Expenditures
In 2006, cash decreased $2.8 million as a result of $39.3 million provided by operating activities, $95.1
million used in investing activities and $53.0 million provided by financing activities. In 2005, cash increased $3.3
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million as a result of $32.3 million provided by operating activities, $138.7 million used in investing activities and
$109.7 million provided by financing activities. In 2004, cash increased $0.9 million as a result of $12.8 million
provided by operating activities, $34.3 million used in investing activities and $22.4 million provided by financing
activities.
For the periods presented, our investing activities consisted primarily of acquisitions, investments in
unconsolidated entities and capital expenditures. Generally, our capital expenditure requirements have consisted, and
we expect that our capital requirements will continue to consist, of:
• maintenance capital expenditures, which are capital expenditures made to replace assets to maintain
our existing operations and to extend the useful lives of our assets; and
•
expansion capital expenditures, which are capital expenditures made to grow our business, to expand
and upgrade our existing marine transportation, terminalling, storage and manufacturing facilities, and
to construct new plants, storage facilities, terminalling facilities and new marine transportation assets.
In 2006, our investing activities consisted primarily of payments for acquisitions of $24.3 million, payments
for property plant and equipment of $66.4 million, investments in partnerships of $11.5 million and receipt of insurance
proceeds on involuntary conversion of property, plant and equipment of $4.8 million.
In 2005, our investing activities consisted primarily of payments for acquisitions of $114.2 million and
payments for property plant and equipment of $24.8 million, investments in partnerships of $0.8 million, cash
distributions received from partnerships of $0.7 million and proceeds from sale of property, plant and equipment of
$0.1 million.
In 2004, our investing activities consisted primarily of cash paid for acquisitions of $31.2 million and
payments for property, plant and equipment of $5.2 million.
For 2006, 2005 and 2004 our capital expenditures for property and equipment were $90.7 million, $79.2
million and $35.4 million, respectively.
As to each period:
•
•
•
In 2006, we spent $78.3 million for expansion and $12.4 million for maintenance. Our expansion
capital expenditures were made in connection with our marine vessel purchases, acquiring assets
relating to the South Houston and Prime Asphalt terminal acquisitions, the Corpus Christi barge
terminal, the sulfur priller construction project at our Neches facility in Beaumont, Texas, and the
sulfuric acid plant construction project at our facility in Plainview, Texas. Our maintenance capital
expenditures were primarily made in our marine transportation segment for routine dry dockings of our
vessels pursuant to the United States Coast Guard requirements and in our terminal segment for
terminal facilities where $4.7 million in maintenance capital expenditures was spent in connection with
restoration of assets destroyed in Hurricanes Rita and Katrina.
In 2005, we spent $74.1 million for expansion and $5.1 million for maintenance. Our expansion
capital expenditures were primarily made in connection with the Prism Gas and CF Martin
acquisitions, the Bay sulfur priller acquisition in Stockton, California, and the sulfur priller
construction project at our Neches facility in Beaumont, Texas. Also, we are constructing a sulfuric
acid plant at our facility in Plainview, Texas and we acquired A & A Fertilizer located in Beaumont,
Texas. Our maintenance capital expenditures were primarily made in our marine transportation
segment for routine dockings of our vessels pursuant to the United States Coast Guard requirements
and in our terminal segment for terminal facilities.
In 2004, we spent $30.2 million for expansion and $5.2 million for maintenance. Our expansion
capital expenditures were primarily made in connection with the Neches and Freeport terminal
acquisitions. Our maintenance capital expenditures were primarily made in our marine transportation
business for routine dockings of our vessels pursuant to United States Coast Guard requirements and
terminal and fertilizer facilities.
In 2006, our financing activities consisted of cash distributions paid to common and subordinated unitholders
of $32.1 million, net proceeds from a follow-on public equity offering of $95.4 million, net proceeds from the issuance
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of common units of $15.0 million, contributions of $2.4 million from our general partner to maintain its 2% general
partner interest, payments of long-term debt under our current and predecessor credit facilities of $163.0 million and
borrowings of long-term debt under our current and predecessor credit facilities of $135.8 million and payments of debt
issuance costs of $0.4 million.
In 2005, our financing activities consisted of cash distributions paid to common and subordinated unitholders
of $19.0 million, payments of long-term debt under our current and predecessor credit facilities of $134.1 million and
borrowings of long-term debt under our current and predecessor credit facilities of $250.9 million and payments of debt
issuance costs of $3.7 million. In November, 2005, we issued 756,480 common units in connection with acquisition of
Prism Gas. Our general partner contributed $0.5 million in cash to us in conjunction with the issuance in order to
maintain its 2% general partner interest in us.
In 2004, our financing activities consisted of net proceeds from a public offering and related transactions of
$34.8 million, cash distributions paid to common and subordinated unitholders of $17.5 million, payments of long-term
debt under our credit facility of $43.2 million, borrowings of long-term debt under our predecessor credit facility of
$49.2 million and payments of debt issuance costs of $0.9 million. In February 2004, we issued 1,322,500 common
units in a public offering, resulting in proceeds of $34.0 million, net of underwriters’ discounts, commissions and
offering expenses. Our general partner contributed $0.8 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.
Capital Resources
Historically, we have generally satisfied our working capital requirements and funded our capital expenditures
with cash generated from operations and borrowings. We expect our primary sources of funds for short-term liquidity
needs will be cash flows from operations and borrowings under our credit facility.
As of December 31, 2006, we had $174.1 million of outstanding indebtedness, consisting of outstanding
borrowings of $44.0 million under our revolving credit facility and $130.0 million under our term loan facility and $0.1
of other secured debt.
In November 2005, we borrowed approximately $63.1 million under our credit facility to pay a portion of the
purchase price for the Prism Gas acquisition. The remainder of the purchase price was funded by $5.0 million
previously escrowed by us, $15.5 million of new equity capital provided by Martin Resource Management in exchange
for newly issued common units, approximately $9.6 million of newly issued common units issued to a certain number
of the sellers and approximately $0.8 million in capital provided by Martin Resource Management for acquisition costs
and to maintain its 2% general partnership interest in us. The common units were priced at $32.54 per common unit,
based on the average closing price of our common units on the NASDAQ during the ten trading days immediately
preceding and immediately following the date of the execution of the definitive purchase agreement.
In January 2006, we completed a follow-on public offering of 3,450,000 common units, resulting in proceeds
of $95.4 million, after payment of underwriters’ discounts, commissions and offering expenses. Our general partner
contributed $2.1 million in cash to us in conjunction with the offering in order to maintain its 2% general partner
interest in us. Of the net proceeds, $62.0 million was used to pay then current balances under our revolving credit
facility and $7.5 million was used to fund a portion of the redemption price for our U.S. Government Guaranteed Ship
Financing Bonds. The remainder of the net proceeds has been or will be used to fund future organic growth projects.
Under our prior acquisition subfacility, we borrowed $3.5 million in connection with the acquisition of the
East Texas Pipeline in January 2005, $5.0 million in connection with the acquisition of the operating assets of Bay
Sulfur Company in April 2005, and $19.4 million in connection with the acquisition of the partnership interests in CF
Martin Sulphur not owned by us in July 2005. In connection with the CF Martin Sulphur acquisition, we assumed
$11.5 million of indebtedness owed by CF Martin Sulphur and promptly repaid $2.4 million of such indebtedness. The
remaining indebtedness relates to certain financing of CF Martin Sulphur under its U.S. Government Guaranteed Ship
Financing Bonds. These bonds were paid on March 6, 2006 with available cash and borrowings from our revolving
credit facility. At such time, we also paid the related $1.2 million pre-payment premium.
In December 2006, we issued 470,484 common units to Martin Product Sales LLC, an affiliate of Martin
Resource Management, for approximately $15.3 million, including a capital contribution of approximately $0.3 million
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made by our general partner in order to maintain its 2% general partner interest in us. These funds were used to reduce
the revolving line of credit.
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 capital expenditures and scheduled debt payments in
2007. However, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to
satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks.
Please read “Item 1A. Risk Factors ─ Risks Related to Our Business” for a discussion of such risks.
Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31,
2006 is as follows: (dollars in thousands):
Type of Obligation
Total
Obligation
Payment due by period
1-3
Years
3-5
Years
Less than
One Year
Due
Thereafter
Long-Term Debt ...........................................
Revolving credit facility ............................
Term loan facility ......................................
Other ..........................................................
Non-competition agreements ........................
Operating leases ...........................................
Interest expense(1)........................................
Revolving Credit Facility ..........................
Term loan facility ......................................
Other ..........................................................
$ 44,000
130,000
95
1,000
14,988
$ —
—
74
250
2,488
$ —
—
21
500
5,097
$ 44,000
130,000
—
100
3,211
$ —
—
—
150
4,192
11,988
36,929
5
3,098
9,544
5
6,196
19,088
—
2,694
8,297
—
—
—
—
Total contractual cash obligations ................
$239,005
$15,459
$30,902
$188,302
$4,342
(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, 2006, we had an outstanding irrevocable letter of credit in the amount of
$0.1 million which was issued under our revolving credit facility. This letter of credit was issued to the Texas
Commission on Environmental Quality to provide financial assurance for our used oil handling program.
Off Balance Sheet Arrangements. We do not have any off-balance sheet financing arrangements.
Description of Our Credit Facility
On November 10, 2005, we entered into a new $225.0 million multi-bank credit facility comprised of a
$130.0 million term loan facility and a $95.0 million revolving credit facility, which includes a $20.0 million letter of
credit sub-limit. Our credit facility also includes procedures for additional financial institutions to become revolving
lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100.0
million for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006,
we increased our revolving credit facility $25.0 million resulting in a committed $120.0 million 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. Under the amended and restated credit facility,
as of December 31, 2006, we had $44.0 million outstanding under the revolving credit facility and $130.0 million
outstanding under the term loan facility. As of December 31, 2006, we had $75.9 million available under our revolving
credit facility.
On July 14, 2005, we issued a $0.1 million irrevocable letter of credit to the Texas Commission on
Environmental Quality to provide financial assurance for its used oil handling program.
Draws made under our credit facility are normally made to fund acquisitions and for working capital
requirements. During the current fiscal year, draws on our credit facilities have ranged from a low of $130.0 million to
a high of $197.7 million.
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Our obligations under the credit facility are secured by substantially all of our assets, including, without
limitation, inventory, accounts receivable, marine vessels, equipment, fixed assets and the interests in our operating
subsidiaries and equity method investees. We may prepay all amounts outstanding under this facility at any time
without penalty.
Indebtedness under the credit facility bears interest at either 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
1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to
2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable
margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing
borrowings is 2.00%. As a result of our leverage ratio test, effective January 1, 2007, the applicable margin for existing
borrowings will increase to 2.50%. Effective April 1, 2007, the applicable margin for existing borrowings will
decrease to 2.00%. We incur a commitment fee on the unused portions of the credit facility.
Effective April 13, 2006, we entered into a cash flow hedge that swaps $75.0 million of floating rate to fixed
rate. The fixed rate cost is 5.25% plus our applicable LIBOR borrowing spread. The cash flow hedge matures in
November, 2010.
Effective December 13, 2006, we entered into a cash flow hedge that swaps $40.0 million of floating rate to
fixed rate. The fixed rate cost is 4.82% plus our applicable LIBOR borrowing spread. The cash flow hedge matures in
December, 2009.
Effective December 13, 2006, we entered into an interest rate swap that swaps $30.0 million of floating rate to
fixed rate. The fixed rate cost is 4.765% plus our applicable LIBOR borrowing spread. This interest rate swap, which
matures in March, 2010, is not accounted for as a cash flow hedge.
In addition, the credit facility contains various covenants, which, among other things, limit our ability to: (i)
incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless we are the survivor; (iv) sell all or
substantially all of our 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) our joint ventures to incur
indebtedness or grant certain liens.
The credit facility also contains covenants, which, among other things, require us to maintain specified ratios
of: (i) minimum net worth (as defined in the credit facility) of $75.0 million plus 50% of net proceeds from equity
issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than
3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than (x) 5.5 to 1.0 for the
fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through
September 30, 2006, and (z) 4.75 to 1.00 for each fiscal quarter thereafter; and (iv) total secured funded debt to
EBITDA of not more than (x) 5.50 to 1.00 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the
fiscal quarters ending December 31, 2005 through September 20, 2006, and (z) 4.00 to 1.00 for each fiscal quarter
thereafter. We were in compliance with the debt covenants contained in the credit facility for the years ended
December 31, 2006 and 2005.
On November 10 of each year, commencing with November 10, 2006, we must prepay the term loans under
the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt
to EBITDA is less than 3.00 to 1.00. No prepayments under the term loan were required to be made in 2006. If we
receive greater than $15.0 million from the incurrence of indebtedness other than under the credit facility, we must
prepay indebtedness under the credit facility with all such proceeds in excess of $15.0 million. Any such prepayments
are first applied to the term loans under the credit facility. We must prepay revolving loans under the credit facility with
the net cash proceeds from any issuance of its equity. We 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
November 10, 2010. 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.
As of March 2, 2007, our outstanding indebtedness includes $194 million under our credit facility.
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Seasonality
A substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and
fertilizers, which fluctuate in part based on winter and spring weather conditions. The demand for NGLs is strongest
during the winter heating season. 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 Katrina and Rita in the third quarter of 2005 adversely impacted our operating expenses and the
four hurricanes that impacted the Gulf of Mexico and Florida in the third quarter of 2004 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 2006, 2005 and 2004. However, inflation remains a factor in the United States economy and
could increase our cost to acquire or replace property, plant and equipment as well as our labor and supply costs. We
cannot assure our unitholders that we will be able to pass along increased costs to our customers.
Increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals
and other supplies are recorded in operating expenses. An increase in price of these products would increase our
operating expenses which could adversely affect net income. We cannot assure our unitholders that we will be able to
pass along increased operating expenses to our customers.
Environmental Matters
Our operations are subject to environmental laws and regulations adopted by various governmental authorities
in the jurisdictions in which these operations are conducted. We incurred no significant environmental costs, liabilities
or expenditures to mitigate or eliminate environmental contamination during 2002, 2003, 2004, 2005 or 2006. Under
the omnibus agreement, Martin Resource Management will indemnify us for five years after the closing of our initial
public offering, which closed on November 6, 2002, against:
•
•
certain potential environmental liabilities associated with the assets it contributed to us relating to
events or conditions that occurred or existed before the closing of our initial public offering, and
any payments we are required to make, as a successor in interest to affiliates of Martin Resource
Management, under environmental indemnity provisions contained in the contribution agreement
associated with the contribution of assets by Martin Resource Management to CF Martin Sulphur,
L.P. in November 2000.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to
market risks associated with commodity prices, counterparty credit and interest rates. Historically, we have not
engaged in commodity contract trading or hedging activities. However, in connection with our acquisition of Prism
Gas, we have established a hedging policy. For the period ended December 31, 2006, changes in the fair value of our
derivative contracts were recorded both in earnings and comprehensive income since we have designated a portion of
our derivative instruments as hedges as of December 31, 2006.
Commodity Price Risk
We are exposed to market risks associated with commodity prices, counterparty credit and interest rates.
Historically, we have not engaged in commodity contract trading or hedging activities. 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.
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We use derivatives to manage the risk of commodity price fluctuations. Our counterparties to the
commodity derivative contracts include Coral Energy Holding LP, Morgan Stanley Capital Group Inc. and
Wachovia Bank.
On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial
condition prior to entering into an agreement, and have established a maximum credit limit threshold pursuant to our
hedging policy and monitor the appropriateness of these limits on an ongoing basis.
As a result of the Prism Gas acquisition, 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. Prism Gas 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 (POL) and percent-of-proceeds
(POP) basis. Prism Gas has entered into hedging transactions through 2009 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
ethane.
Based on estimated volumes, as of December 31, 2006, Prism Gas had hedged approximately 60%, 45%,
and 14% of its commodity risk by volume for 2007, 2008, and 2009, respectively. As of December 31, 2006,
commodity derivative assets of $882 were included in other current assets and $221 were included in non-current
assets on the balance sheet. Commodity derivative liabilities of $74 were included in long-term liabilities on the
balance sheet. We estimate entering into additional commodity derivatives on an ongoing basis to manage risk
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 the Partnership’s existing hedging arrangements. In addition, we will consider
derivative arrangements that include the specific NGL products as well as natural gas and crude oil.
Hedging Arrangements in Place
Commodity Hedged
Year
2007 Condensate & Natural Gasoline
2007 Natural Gas
2007 Natural Gas
Type of Derivative
Volume
5,000 BBL/Month
Crude Oil Swap ($65.95)
20,000 MMBTU/Month Natural Gas Swap ($9.14)
20,000 MMBTU/Month Natural Gas Basis Swap (-$0.60) Henry Hub to
Basis Reference
NYMEX
Henry Hub
Condensate & Natural Gasoline
2007 EEthane
2008
2008 Natural Gas
2009 Condensate & Natural Gasoline
8,000 BBL/Month
5,000 BBL/Month
30,000 MMBTU/Month Natural Gas Swap ($8.12)
Crude Oil Swap ($69.08)
3,000 BBL/Month
Ethane Swap ($28.04)
Crude Oil Swap ($66.20)
Centerpoint East
Mt. Belvieu
NYMEX
Houston Ship Channel
NYMEX
Our principal customers with respect to Prism Gas’ natural gas gathering and processing services 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
continuance of deliveries to the buyer after the buyer provides security for payment in a form satisfactory to us. For
additional information regarding our hedging activities, please see “Note 15 – Commodity Cash Flow Hedges” in
our “Notes to Consolidated Financial Statements” contained herein.
Interest Rate Risk
We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average
interest rate of 7.26% as of December 31, 2006. We had a total of $174.1 million of indebtedness outstanding under our
credit facility as of the date hereof of which $29.0 million was unhedged floating rate debt. Based on the amount of
unhedged floating rate debt owed by us on December 31, 2006, the impact of a 1% increase in interest rates on this
amount of debt would result in an increase in interest expense and a corresponding decrease in net income of
approximately $0.3 million annually.
As of March 2, 2007, we had a total of $194 million of indebtedness outstanding under our credit facility. The
impact of a 1% increase in interest rates on this amount of unhedged floating rate debt would result in an increase in
interest expense, and a corresponding decrease in net income of approximately $0.5 million annually.
DAL02:480617.6
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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 ........................................................................................ 73
Report of Independent Registered Public Accounting Firm ........................................................................................ 74
Consolidated Balance Sheets as of December 31, 2006 and 2005 .............................................................................. 75
Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004 .............................. 76
Consolidated Statements of Changes in Capital for the years ended December 31, 2006, 2005 and 2004 ................. 77
Consolidated Statements of Comprehensive Income for the years ended December 31, 2006 and 2005 ................... 78
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004 ............................. 79
Notes to the Consolidated Financial Statements .......................................................................................................... 80
DAL02:480617.6
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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, 2006 and 2005, 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, 2006.
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 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 financial statements referred to above present fairly, in all material respects, the
consolidated financial position of Martin Midstream Partners L.P. and subsidiaries and the results of their operations
and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with
accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Accounting Oversight Board (United
States), the effectiveness of Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting
as of December 31, 2006, 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 5, 2007
expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over
financial reporting.
KPMG LLP
/s/ KPMG LLP
Shreveport, Louisiana
March 5, 2007
DAL02:480617.6
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Report of Independent Registered Public Accounting Firm
The Board of Directors
Martin Midstream GP LLC:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over
Financial Reporting, that Martin Midstream Partners L.P. and subsidiaries maintained effective internal control over financial
reporting as of December 31, 2006, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of
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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness
of internal control, and 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 U.S. 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 U.S. 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, management’s assessment that Martin Midstream Partners L.P. and subsidiaries maintained effective
internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria
established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). Also, in our opinion, Martin Midstream Partners L.P. and subsidiaries maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
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, 2006 and 2005, and
the related consolidated statements of operations, capital/equity, and cash flows for each of the three years ended December 31, 2006
and our report dated March 5, 2007 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
KPMG LLP
Shreveport, Louisiana
March 5, 2007
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
Assets
Cash ....................................................................................................................
Accounts and other receivables, less allowance for doubtful accounts of $394
and $140 ......................................................................................................
Product exchange receivables .............................................................................
Inventories ..........................................................................................................
Due from affiliates ..............................................................................................
Other current assets ............................................................................................
Total current assets ......................................................................................
Property, plant, and equipment, at cost ...............................................................
Accumulated depreciation ..................................................................................
Property, plant and equipment, net ..............................................................
Goodwill .............................................................................................................
Investment in unconsolidated entities .................................................................
Other assets, net ..................................................................................................
Liabilities and Capital
Current installments of long-term debt ...............................................................
Trade and other accounts payable .......................................................................
Product exchange payables .................................................................................
Due to affiliates ..................................................................................................
Income taxes payable ..........................................................................................
Other accrued liabilities ......................................................................................
Total current liabilities ................................................................................
Long-term debt ...................................................................................................
Other long-term obligations ................................................................................
Total liabilities .............................................................................................
Partners’ capital ..................................................................................................
Accumulated other comprehensive income ........................................................
Total partners’ capital ..................................................................................
Commitments and contingencies ........................................................................
See accompanying notes to consolidated financial statements.
December 31,
2006
2005
(Dollars in thousands)
$ 3,675
$ 6,465
56,712
7,076
33,019
1,330
2,041
103,853
323,967
(76,122)
247,845
27,600
70,651
7,512
$ 457,461
$ 74
53,450
14,737
10,474
86
3,876
82,697
174,021
2,218
258,936
198,403
122
198,525
72,162
2,141
33,909
1,475
1,420
117,572
235,218
(59,505)
175,713
27,600
59,879
8,280
$ 389,044
$ 9,104
67,387
9,624
3,492
6,345
3,617
99,569
192,200
1,710
293,479
95,565
—
95,565
$ 457,461
$ 389,044
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
2005
(Dollars in thousands, except per unit amounts)
2006
2004
Revenues:
Terminalling and storage ...........................................................
Marine transportation ................................................................
$ 24,182
47,835
$ 23,081
35,451
$ 17,919
34,780
Product sales:
Natural gas services ............................................................
Sulfur ..................................................................................
Fertilizer .............................................................................
Terminalling and storage ...................................................
Total revenues .............................................................
Costs and expenses:
Cost of products sold:
Natural gas services ............................................................
Sulfur ..................................................................................
Fertilizer .............................................................................
Terminalling and storage ....................................................
Expenses:
Operating expenses ....................................................................
Selling, general and administrative ...........................................
Depreciation and amortization ...................................................
Total costs and expenses ....................................................
Other operating income ....................................................................
Operating income ...............................................................
389,735
61,271
41,326
12,035
504,367
576,384
374,218
38,898
36,267
9,787
459,170
65,387
10,977
17,597
553,131
3,356
26,609
301,676
36,784
31,634
9,817
379,911
438,443
291,109
25,657
26,975
8,079
351,820
46,888
8,133
12,642
419,483
—
18,960
203,427
—
29,780
8,238
241,445
294,144
197,859
—
25,342
6,775
229,976
34,475
6,198
8,766
279,415
—
14,729
Other income (expense):
Equity in earnings of unconsolidated entities ............................
Interest expense .........................................................................
Debt prepayment premium ........................................................
Other, net ...................................................................................
Total other income (expense) .............................................
8,547
(12,466)
(1,160)
713
(4,366)
1,591
(6,909)
—
238
(5,080)
912
(3,326)
—
11
(2,403)
Net income ........................................................................................
$ 22,243
$ 13,880
$ 12,326
General partner’s interest in net income ...........................................
Limited partners’ interest in net income ...........................................
Net income per limited partner unit — basic and diluted ..............
$ 1,001
$ 21,242
$ 1.69
$ 278
$ 13,602
$ 1.58
$ 247
$ 12,079
$ 1.45
Weighted average limited partner units — basic ..............................
Weighted average limited partner units — diluted ...........................
12,602,000
12,604,425
8,583,634
8,583,634
8,349,551
8,349,551
See accompanying notes to consolidated financial statements.
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL
For the years ended December 31, 2006, 2005 and 2004
Partners’ Capital
Limited Partners
Common
Units
Amount
Subordinated
Amount
Units
(Dollars in thousands)
General
Partner
Amount
Accumulated
Comprehensive
Income
Amount
Total
Balances – December 31, 2003 ......................................
2,900,000
$ 47,914
4,253,362
$ (1,996)
$ (26)
—
$ 45,892
Net income .....................................................................
—
5,923
—
6,156
247
Follow-on public offering ..............................................
1,322,500
34,016
—
—
—
General partner contribution ..........................................
—
—
—
—
754
—
—
—
12,326
34,016
754
Cash distributions ($2.10 per unit) ................................
—
(8,173)
—
(8,932)
(349)
—
(17,454)
Balances – December 31, 2004 ......................................
4,222,500
79,680
4,253,362
(4,772)
626
Net income .....................................................................
—
6,756
—
6,846
278
Units issued in connection with Prism Gas
acquisition ......................................................................
756,480
24,616
—
—
—
Conversion of subordinated units to common units ......
850,672
(1,599)
(850,672)
1,599
—
General partner contribution ..........................................
—
—
—
—
502
—
—
—
—
—
75,534
13,880
24,616
—
502
Cash distributions ($2.19 per unit) ................................
—
(9,247)
—
(9,315)
(405)
—
(18,967)
Balances – December 31, 2005 ......................................
5,829,652
100,206
3,402,690
(5,642)
1,001
Net income .....................................................................
—
16,030
—
5,212
1,001
Follow-on public offering ..............................................
3,450,000
95,272
—
—
—
Issuance of common units .............................................
470,484
15,000
—
—
—
General partner contribution ..........................................
—
—
—
—
2,358
Conversion of subordinated units to common units ......
850,672
(2,495)
(850,672)
2,495
—
Unit-based compensation ...............................................
3,000
24
—
—
—
Cash distributions ($2.44 per unit) ................................
—
(22,650)
—
(8,302)
(1,107)
Commodity hedging gains reclassified to earnings .......
—
—
—
—
—
—
—
—
—
—
—
—
—
2
95,565
22,243
95,272
15,000
2,358
—
24
(32,059)
2
Adjustment in fair value of derivatives ..........................
—
—
—
—
—
120
120
Balances – December 31, 2006 ......................................
10,603,808
$ 201,387
2,552,018
$ (6,237)
$ 3,253
$ 122
$ 198,525
See accompanying notes to consolidated financial statements.
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
Year Ended December 31,
2005
2004
2006
(Dollars in thousands)
Net income ..........................................................................
Changes in fair values of commodity cash flow hedges ......
Commodity hedging gains reclassified to earnings .............
Changes in fair value of interest rate cash flow hedges .......
$ 22,243
370
2
(250)
$ 13,880
—
—
—
$ 12,326
—
—
—
Comprehensive income ................................................
$ 22,365
$ 13,880
$ 12,326
See accompanying notes to consolidated financial statements.
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
2006
2005
(Dollars in thousands)
2004
$ 22,243
$ 13,880
$ 12,326
17,597
1,040
(231)
(3,125)
(8,547)
541
8,311
(389)
24
13,763
(4,935)
890
145
115
(13,937)
5,113
6,982
(5,912)
(371)
39,317
(66,352)
(24,306)
1,825
4,812
433
(11,510)
(95,098)
(163,010)
95,272
2,358
135,801
(371)
(32,059)
15,000
52,991
(2,790)
6,465
$ 3,675
12,642
600
(37)
—
(1,591)
231
1,115
(555)
—
(10,565)
(1,974)
(4,474)
417
36
27,669
(8,238)
3,063
(496)
611
32,334
(24,814)
(114,167)
95
—
466
(322)
(138,742)
(134,091)
—
502
250,900
(3,655)
(18,967)
15,000
109,689
3,281
3,184
$ 6,465
8,766
886
48
—
(912)
—
—
—
—
(16,499)
1,733
(3,502)
(1,730)
32
9,171
1,859
(131)
765
—
12,812
(5,182)
(31,234)
114
—
1,980
—
(34,322)
(43,215)
34,016
754
49,215
(892)
(17,454)
—
22,424
914
2,270
$ 3,184
$ —
$ —
$ 690
$ 9,616
$ 398
$ —
Cash flows from operating activities:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization ................................................................................
Amortization of deferred debt issue costs ..............................................................
(Gain) loss on disposition or sale of property, plant, and equipment .....................
(Gain) loss on involuntary conversion of property, plant, and equipment .............
Equity in earnings of unconsolidated entities .........................................................
Distributions from unconsolidated entities ..........................................................
Distribution in-kind from equity investments ........................................................
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 ...............................................................................................
Other accrued liabilities ..................................................................................
Change in other non-current assets and liabilities, net ...........................................
Net cash provided by operating activities .................................................
Cash flows from investing activities:
Payments for property, plant, and equipment ...............................................................
Acquisitions, net of cash acquired ................................................................................
Proceeds from sale of property, plant, and equipment .................................................
Insurance proceeds from involuntary conversion of property, plant and
equipment ................................................................................................................
Return of investments from unconsolidated entities ....................................................
Investments in unconsolidated entities .........................................................................
Net cash used in investing activities.......................................................
Cash flows from financing activities:
Payments of long-term debt ..........................................................................................
Net proceeds from follow on public offering ...............................................................
General partner contribution .........................................................................................
Proceeds from long-term debt .....................................................................................
Payments of debt issuance costs ...................................................................................
Cash distributions paid ..................................................................................................
Proceeds from issuance of common units ....................................................................
Net cash provided by financing activities ..............................................
Net increase (decrease) in cash...............................................
Cash at beginning of period ...................................................................................
Cash at end of period .............................................................................................
Non-cash:
Financed portion of non-compete agreement ................................................
Common units issued for acquisitions ..........................................................
See accompanying notes to consolidated financial statements.
DAL02:480617.6
- 78 -
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 which provides
terminalling and storage services for petroleum products and by-products, natural gas gathering, processing and
NGL distribution, marine transportation services for petroleum products and by-products, sulfur gathering,
processing and distribution and fertilizer manufacturing and marketing.
On November 10, 2005, the Partnership acquired 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. Through the acquisition of Prism Gas, the Partnership also acquired 50% ownership
interest in Waskom Gas Processing Company (“Waskom”), the Matagorda Offshore Gathering System
(“Matagorda”), and the Panther Interstate Pipeline Energy LLC (“PIPE”) each accounted for under the equity
method of accounting.
In April 2005, the Partnership began another primary line of business for sulfur marketing and distribution
through the acquisition of the operating assets of Bay Sulfur Company, including a sulfur priller in Stockton,
California. In January, 2006, an additional sulfur priller began production at the Partnership’s Neches facility in
Beaumont, Texas. On July 15, 2005 the Partnership acquired all of the outstanding partnership interests of CF
Martin Sulphur, L.P. (“CF Martin Sulfur”) not owned by the Partnership. As a result, CF Martin Sulphur has been
consolidated in the Partnership’s consolidated financial statements and in the Partnership’s sulfur segment. Prior to
the acquisition, the Partnership owned an unconsolidated non-controlling 49.5% limited partnership interest in CF
Martin Sulphur. The sulfur segment will include the marketing, transportation, terminalling and storage, processing
and distribution of molten and pelletized sulfur.
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 exploration and production industry.
(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 as defined by FASB Interpretation No 46(R)
Consolidation of Variable Interest Entities (“FIN 46R”) 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 FIN 46(R). No such variable interest entities exist as of
December 31, 2006 or 2005.
(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 NGLs due to other
companies under these agreements at quoted market product prices and the balance of NGLs and sulfur due from
other companies at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”) method.
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(c)
Inventories
Inventories are stated at the lower of cost or market. Cost is determined by using the FIFO method for all
inventories.
(d)
Revenue Recognition
Terminalling and storage – Revenue is recognized for storage contracts based on the contracted monthly
tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through the
Partnership’s terminals at the contracted rate. 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 the
Partnership’s NGL customers, which occurs when the customer physically receives the product. When product is
sold in storage, or by pipeline, the Partnership recognizes NGL distribution revenue when the customer receives the
product from either the storage facility or pipeline.
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.
Sulfur and Fertilizer – Revenue is recognized when the customer takes title to the product, either at the
Partnership’s plant or the customer facility.
(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 the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 142,
Goodwill and Other Intangible Assets, 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 Accounting Principles
Board (“APB”) Opinion No. 18, 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.
Prior to July 15, 2005, the Partnership used the equity method of accounting for its unconsolidated non-
controlling 49.5% limited partner interest in CF Martin Sulphur. On July 15, 2005, the Partnership acquired the
remaining interests in CF Martin Sulphur not previously owned by it. Subsequent to the acquisition, CF Martin
Sulphur is included in the consolidated financial presentation of the Partnership’s sulfur segment
Following the Partnership’s acquisition of Prism Gas Systems I, L.P. (“Prism Gas”) in November 2005, the
Partnership owns an unconsolidated 50% interest in Waskom Gas Processing Company (“Waskom”), the Matagorda
Offshore Gathering System (“Matagorda”), and Panther Interstate Pipeline Energy LLC (“PIPE”). As a result, these
assets are accounted for by the equity method and the Partnership does not include any portion of their net income in
operating income.
On June 30, 2006, the Partnership, through 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”).
This interest is accounted for by the equity method of accounting.
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(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.
Routine maintenance and repairs are charged to operating expense while costs of betterments and renewals are
capitalized. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the
accounts and the difference between net book value of the asset and proceeds from disposition is recognized as gain or
loss.
(g)
Goodwill and Other Intangible Assets
Goodwill 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 the provisions of SFAS No. 142,
Goodwill and Other Intangible Assets. Intangible assets with estimated useful lives are amortized over their respective
estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with FASB
Statement No. 144 (“SFAS No. 144”), Accounting for Impairment or Disposal of Long-Lived Assets. Other intangible
assets primarily consists of covenants not-to-compete obtained through business combinations and are being amortized
over the life of the respective agreements.
(h)
Debt Issuance Costs
In connection with the Partnership’s multi-bank credit facility, on November 10, 2005, it incurred debt
issuance costs of $3,258. In connection with the amendment and expansion of the Partnership’s multi-bank credit
facility on June 30, 2006, it incurred debt issuance costs of $372. 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 60 month term of the new debt arrangement.
Amortization of debt issuance cost, which are included in interest expense for the years ended December 31,
2006, 2005 and 2004, totaled $1,040, $600, and $886, respectively, and accumulated amortization amounted to $3,091
and $2,050 at December 31, 2006 and 2005, respectively. The unamortized balance of debt issuance costs, classified as
other assets amounted to $4,169 and $4,838 at December 31, 2006 and 2005, respectively.
(i)
Impairment of Long-Lived Assets
In accordance with SFAS No. 144, 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. Goodwill is tested annually for impairment, and is
tested for impairment more frequently if events and circumstances indicate that the asset might be impaired. An
impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value. This determination
is made at the reporting unit level and consists of two steps. First, the Partnership determines the fair value of a
reporting unit and compares it to its carrying amount. Second, if the carrying amount of a reporting unit exceeds its fair
value, an impairment loss is recognized for any excess of the carrying amount of the reporting unit’s goodwill over the
implied fair value of that goodwill. The implied fair value of goodwill is determined by allocating the fair value of the
reporting unit in a manner similar to a purchase price allocation, in accordance with FASB Statement No. 141, Business
Combinations. The residual fair value after this allocation is the implied fair value of the reporting unit goodwill.
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
The Partnership performed its annual tests in the third quarters of 2004, 2005 and 2006, with no indication of
impairment.
(j)
Asset Retirement Obligation
Under SFAS No. 143, Accounting for Asset Retirement Obligations (“Statement No. 143) which provides
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.
On March 31, 2005, the Financial Accounting Standards Board issued Interpretation No. 47, “Accounting
for Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143. FIN 47, which was
effective for fiscal years ending after December 15, 2005, clarifies that the recognition and measurement provisions
of SFAS 143 apply to asset retirement obligations in which the timing or method of settlement may be conditional
on a future event that may or may not be within the control of the entity. The Partnership’s fixed assets include
land, buildings, transportation equipment, storage equipment, marine vessels and operating equipment.
The transportation equipment includes pipelines system. The Partnership transports NGLs through the
pipeline system and gathering system. The Partnership also gathers natural gas from wells owned by producers and
deliver 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 Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), 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. In early 2006, the Partnership adopted a hedging
policy that allows it to use hedge accounting for financial transactions that are designated as hedges.
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, 2006, 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 other comprehensive income as a component of equity.
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(l)
Comprehensive Income
Comprehensive income includes net income and other comprehensive income. Other comprehensive income
for the partnership includes unrealized gains and losses on derivative financial instruments. In accordance with SFAS
No. 133, 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 January 2006, the Partnership issued 1,000 restricted units to each of its three independent, non-
employee directors under its long-term incentive plan. These units vest in 25% increments on the anniversary of the
grant date each year and will be fully vested in January 2010. The Partnership accounts for the transaction under
Emerging Issues Task Force 96-18 “Accounting for Equity Instruments That are Issued to other than Employees
For Acquiring, or in Conjunction with Selling, Goods or Services.” The cost resulting from the share-based
payment transactions was $24 for the year ended December 31, 2006. The Partnership’s general partner contributed
$2 in cash to the Partnership in conjunction with the issuance of these restricted units in order to maintain its 2%
general partner interest in the Partnership.
(n)
Incentive Distribution Rights
The 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, 2006, 2005 and 2004, the general partner received $537, $0 and $0 in incentive
distributions.
(o)
Net Income per Unit
Except as discussed in the following paragraph, basic and diluted net income per limited partner unit is
determined by dividing net income after deducting the amount allocated to the general partner interest (including its
incentive distribution in excess of its 2% interest) by the weighted average number of outstanding limited partner
units during the period. Subject to applicability of Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06’’),
“Participating Securities and the Two-Class Method under FASB Statement No. 128,’’ as discussed below,
Partnership income is first allocated to the general partner based on the amount of incentive distributions. The
remainder is then allocated between the limited partners and general partner based on percentage ownership in the
Partnership.
EITF 03-06 addresses the computation of earnings per share by entities that have issued securities other
than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when,
and if, it declares dividends on its common stock. Essentially, EITF 03-06 provides that in any accounting period
where the Partnership’s aggregate net income exceeds the Partnership’s aggregate distribution for such period, the
Partnership is required to present earnings per unit as if all of the earnings for the periods were distributed,
regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during
a particular period from an economic or practical perspective. EITF 03-06 does not impact the Partnership’s overall
net income or other financial results; however, for periods in which aggregate net income exceeds the Partnership’s
aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit.
This result occurs as a larger portion of the Partnership’s aggregate earnings is allocated to the incentive distribution
rights held by the Partnership’s general partner, as if distributed, even though the Partnership makes cash
distributions on the basis of cash available for distributions, not earnings, in any given accounting period. In
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
accounting periods where aggregate net income does not exceed the Partnership’s aggregate distributions for such
period, EITF 03-06 does not have any impact on the Partnership’s earnings per unit calculation.
The weighted average units outstanding for basic net income per unit were 12,602,000, 8,583,634 and
8,349,551 for years ended December 31, 2006, 2005 and 2004, respectively. For diluted net income per unit, the
weighted average units outstanding were increased by 2,425 for the year ended December 31, 2006 due to the
dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.
(p)
Reclassifications
The Partnership converted to a new accounting system in August 2005. In connection with its system
conversion, the Partnership closely examined expense classifications for the new system. Upon review, it was
determined that certain payroll, property insurance and property tax expenses that were previously categorized as
selling, general and administrative expenses would be more appropriately classified as operating expenses. As a result,
those expenses were set up in the new system with the new classification. Accordingly, it was necessary for the
Partnership to reclassify the prior period to conform to the current presentation.
These reclassifications, as detailed below, had no impact on the prior year’s operating income or net income.
The following table sets forth the effects of the reclassification on certain line items within the Partnership’s previously
reported consolidated statements of income for year ended December 31, 2004.
Year Ended December 31, 2004
Cost of products sold (as previously
reported) ........................................................
Cost of products sold (as
Reclassified) ..................................................
Operating expenses (as previously
reported) ........................................................
Operating expenses (as reclassified) ................
Selling, general and administrative (as
previously reported) .......................................
Selling, general and administrative (as
Reclassified) ..................................................
Terminalling
and Storage
NGL
Marine
Fertilizer
SG&A
Total
$ 6,775
$ 197,859 $
— $ 25,207
$
— $ 229,841
6,775
6,699
8,494
2,194
399
197,859
—
25,342
928
1,185
1,457
1,200
24,796
24,796
175
175
—
—
—
—
—
1,793
2,766
1,658
2,766
229,976
32,423
34,475
8,385
6,198
(q)
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
provide such centralized services. Subsequent to November 1, 2002, under an omnibus agreement between the
Partnership and Martin Resource Management, the amount the Partnership is required to reimburse Martin Resource
Management for indirect general and administrative expenses and corporate overhead allocated to the Partnership was
capped at $1,000 during the first year of the agreement. For the year ending October 31, 2004, the cap was increased to
$2,000. Subsequently, the capped amount may be increased by no more than the percentage increase in the consumer
price index for the applicable year. In addition, the Partnership’s general partner has the right to agree to further
increases in connection with expansions of the Partnership’s operations through the acquisition or construction of new
assets or businesses.
(r)
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 from environmental remediation
obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
adjusted as further information develops or circumstances change. Costs of future expenditures for environmental
remediation obligations are not discounted to their present value.
(s)
Allowance for Doubtful Accounts.
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for
doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing
accounts receivable.
(t)
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.
(u)
Income Taxes
The operations of the Partnership are not subject to income taxes, except for the Texas margin tax as described
in the following paragraph, and as a result, the Partnership’s income is taxed directly to its owners. As a result of its
acquisition of Prism Gas, the Partnership assumed a current tax liability of $6.3 million as a result of a tax event
triggered by the transfer of the ownership of the assets of Prism Gas in 2005 from a corporate to a partnership structure
through the partial liquidation of the corporation. This liability was paid in 2006.
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 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 provisions of SFAS 109 regarding
the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the effect on deferred
tax assets of a change in tax law should be included in tax expense attributable to continuing operations in the period
that includes the enactment date. Therefore, the Partnership has calculated its deferred tax assets and liabilities for
Texas based on the new margin tax. The cumulative effect of the change was immaterial. The impact of the change
in deferred tax assets does not have a material impact on tax expense. There was no income tax expense recorded
for the year ended December 31, 2006. Beginning 2007, the Partnership anticipates it will incur tax expense related
to this new Texas margin tax.
(3)
IMPACT OF RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In September 2006, the FASB issued FAS 157, which will become effective for the Partnership on January
1, 2008. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures
about fair value measurements. The Statement does not require any new fair value measurements but would apply
to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact, if
any, to the Partnership from the adoption of FAS 157 in 2008 will depend on the Partnership’s assets and liabilities
at that time that are required to be measured at fair value.
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108,
“Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial
Statements”, (SAB 108). SAB 108 addresses how the effects of prior year uncorrected misstatements should be
considered when quantifying misstatements in current year financial statements. SAB 108 requires companies to
quantify misstatements using a balance sheet approach and income statement approach and to evaluate whether
either approach results in quantifying an error that is material in light of the relevant quantitative and qualitative
factors. SAB 108 is effective for fiscal years ending on or after November 15, 2006. SAB 108 did not have an
effect on the Partnership’s consolidated financial statements.
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
In September 2005, the FASB’s Emerging Issues Task Force (“EITF”) issued EITF No. 04-13, Accounting
for Purchases and Sales of Inventory with the Same Counterparty. This pronouncement provides additional
accounting guidance for situations involving inventory exchanges between parties to that contained in APB Opinion
no. 29, Accounting for Nonmonetary Transactions and SFAS 153, Exchanges of Nonmonetary Assets. The standard
is effective for new arrangements entered into in reporting periods beginning after March 15, 2006. The adoption
did not have a material impact on the Partnership’s consolidated financial statements.
In May 2005, the FASB, as part of an effort to conform to international accounting standards, issued SFAS
No. 154, “Accounting Changes and Error Corrections,” or SFAS No. 154, which was effective for the Partnership
beginning on January 1, 2006. SFAS No. 154 requires that all voluntary changes in accounting principles be
retrospectively applied to prior financial statements as if that principle had always been used, unless it is
impracticable to do so. When it is impracticable to calculate the effects on all prior periods, SFAS No. 154 requires
that the new principle be applied to the earliest period practicable. The adoption of SFAS No. 154 did not have a
material effect on the Partnership’s consolidated financial statements.
(4)
ACQUISITIONS
(a)
Asphalt Terminals. In August 2006 and October 2006, respectively, the Partnership acquired the
assets of Gulf States Asphalt Company LP and Prime Materials and Supply Corporation (“Prime”), for $4,842 of
which $4,679 was allocated to property, plant and equipment and $163 to a non-compete agreements. The assets are
located in Houston, Texas and Port Neches, Texas. The Partnership entered into an agreement with Martin
Resource Management, which Martin Resource Management will operate the facilities through a terminalling
service agreement based upon throughput rates and will assume all additional expenses to operate the facility.
(b)
Corpus Christi Barge Terminal. In July 2006, the Partnership acquired a marine terminal located
near Corpus Christi, Texas and associated assets from Koch Pipeline Company, LP for $6,200 which was all
allocated to property, plant and equipment. The terminal is located on approximately 25 acres of land, and includes
three tanks with a combined shell capacity of approximately 240,000 barrels, pump and piping infrastructure for
truck unloading and product delivery to two oil docks, and there are several pumps, controls, and an office building
on site for administrative use.
(c)
Marine Vessels. In November 2006, the Partnership acquired the La Force, an offshore tug, for
$6,001 from a third party. This vessel is a 5,100 horse power offshore tug that was rebuilt in 1999 with new engines
installed in 2005.
In January 2006, the Partnership acquired the Texan, an offshore tug, and the Ponciana, an offshore NGL
barge, for $5,850 from Martin Resource Management. The acquisition price was based on a third-party appraisal.
In March 2006, these vessels went into service under a long term charter with a third party. In February 2006, the
Partnership acquired the M450, an offshore barge, for $1,551 from a third party. In March 2006, this vessel went
into service under a one-year charter with an affiliate of Martin Resource Management.
(d)
A & A Fertilizer, Ltd. In December 2005, the Partnership completed the purchase of the net
operating assets of A & A Fertilizer for $5,667. A & A Fertilizer is a manufacturer and distributor of liquid sulfur
based fertilizer products to the continental United States. The A & A Fertilizer manufacturing facility is located at
the Partnership’s Port Neches deep-water marine terminal near Beaumont, Texas. This acquisition is reported in the
Partnership’s fertilizer segment.
DAL02:480617.6
- 86 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
The purchase price of $5,667, including non-competition agreements in other assets of $691, was allocated
as follows:
Current assets .......................................................................................................
Property, plant and equipment, net ......................................................................
Other assets ..........................................................................................................
Current liabilities .................................................................................................
Other liabilities ....................................................................................................
$ 955
5,448
691
(891)
(536)
Total .....................................................................................................
$ 5,667
(e)
Prism Gas Acquisition. In November 2005 the Partnership acquired Prism Gas. As of November
2005, Prism Gas had ownership interests in over 330 miles of natural gas gathering pipelines located in the natural
gas producing regions of East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal
waters in the Gulf of Mexico as well as a 150 MMcfd capacity natural gas processing plant located in East Texas.
The fair market value of the assets acquired were appraised at $93,938. The excess of the fair value over the
carrying value of the assets was allocated to all identifiable assets. After recording all identifiable assets at their fair
values, the remaining $20,145 was recorded as goodwill. The goodwill was a result of Prism Gas’ strategically
located assets combined with the Partnership’s access to capital and existing infrastructure. This will enhance the
Partnership’s ability to offer additional gathering and processing services to customers through internal growth
projects including natural gas processing, fractionation and pipeline expansions as well as new pipeline construction.
In accordance with FAS 142, the goodwill will not be amortized but tested for impairment.
The selling parties in this transaction were Natural Gas Partners V, L.P. and certain members of the Prism Gas
management team. The final purchase price was $93,938. The purchase price was funded by $63,052 in borrowings
under the Partnership’s credit facility, $5,000 in a previously funded escrow account, $15,502 in new equity capital
provided by Martin Resource Management, $9,616 in seller financing, and $768 in capital provided by Martin
Resource Management for acquisition costs and to maintain its 2% general partner interest in the Partnership.
The purchase price of $93,938, including two-year non-competition agreements included in other assets of
$600, was allocated as follows:
Current assets .......................................................................................................
Other current assets ..............................................................................................
Property, plant and equipment, net ......................................................................
Investment in unconsolidated entities ..................................................................
Other assets ..........................................................................................................
Goodwill ..............................................................................................................
Current liabilities .................................................................................................
Other liabilities ....................................................................................................
Total .....................................................................................................
$ 4,449
10,772
17,810
60,000
942
20,145
(19,901)
(279)
$ 93,938
The following table presents unaudited pro forma financial information incorporating the historical (pre-
acquisition) financial results of Prism Gas. This information has been prepared as if the acquisition of Prism Gas had
been completed on January 1 of the respective periods presented as opposed to the actual date that the acquisition
occurred. The pro forma information is based upon data currently available and certain estimates and assumptions
made by management. As a result, this information is not necessarily indicative of the financial results had the
transactions actually occurred on these dates. Likewise, the unaudited pro forma information is not necessarily
indicative of future financial results.
DAL02:480617.6
- 87 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
2005
2004
Total revenues ........................................................................... $512,970 $356,393
Cost of products sold ................................................................
288,973
Operating expenses ...................................................................
36,333
Selling, general and administrative ...........................................
9,022
Depreciation and amortization ..................................................
10,334
Operating income ......................................................................
11,731
Net income before taxes ...........................................................
14,821
Net income ................................................................................
14,821
Net income per limited partner unit ..........................................
$1.32
422,624
48,218
13,953
13,843
14,332
13,615
13,615
$1.22
The operations related to the Prism Gas acquisition have been included in the Partnership’s results of
operations only since the date of acquisition.
In connection with the purchase of Prism Gas, a portion of the purchase price was funded by the issuance of
460,971 common units of the Partnership to Martin Resource Management, the owner of the Partnership’s general
partner, which provided $15,000 of new equity capital. Martin Midstream GP LLC contributed $502 to maintain its 2%
general partner interest in the partnership. In addition, 295,509 common units of the Partnership, representing
approximately $9,616 of the purchase price, was issued to the sellers.
(f)
CF Martin Sulfur. In July 2005, the Partnership acquired all of the outstanding partnership interests
in CF Martin Sulphur not owned by the Partnership from CF Industries, Inc. and certain subsidiaries of Martin
Resource Management for $18,900. In connection with the acquisition the Partnership also assumed the indebtedness
described below. Prior to this transaction, the Partnership owned an unconsolidated non-controlling 49.5% limited
partnership interest in CF Martin Sulphur, which was accounted for using the equity method of accounting.
Subsequent to the acquisition, CF Martin Sulphur is a wholly-owned subsidiary included in the Partnership’s
consolidated financial statements and in the Partnership’s sulfur segment.
In connection with the acquisition, the Partnership assumed $11,500 of indebtedness owed by CF Martin
Sulphur and promptly repaid $2,400 of such indebtedness. The Partnership also pledged its equity interests in CF
Martin Sulphur to the Partnership’s lenders under its credit facility. As part of this transaction, CF Industries, Inc.
entered into a five-year sulfur supply contract with the Partnership that is based on Tampa market pricing.
The purchase price paid to CF Industries, Inc. and certain subsidiaries of Martin Resource Management was
allocated as follows:
Current assets .......................................................................................................
Property, plant and equipment, net ......................................................................
Other assets ..........................................................................................................
Current liabilities .................................................................................................
Debt .....................................................................................................................
$ 11,283
26,735
921
(8,573)
(11,495)
Total use of proceeds .............................................................................
$ 18,871
(g)
Bay Sulfur Asset Acquisition. In April 2005, the Partnership completed the acquisition of the
operating assets and sulfur inventories of Bay Sulfur Company located at the Port of Stockton, California for $5,900
which includes $4,000 allocated to goodwill. Goodwill was recognized as a result of the total price paid for the
business, and is supported by its historical cash flows. The remaining $1,900 was allocated to property, plant and
equipment ($1,400), a covenant not to compete ($100) and inventory and other current assets ($400). The assets
acquired are used to process molten sulfur into pellets. This acquisition is reported in the Partnership’s new “sulfur”
segment. The acquisition was financed through the Partnership’s credit facility (see Note 11).
(h)
Natural Gas Liquids Pipeline Purchase. In January 2005, the Partnership acquired a natural gas
liquids (“NGL”) pipeline located in East Texas from an unrelated third party for $3,800. The purchase price included
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
the value of the natural gas liquids in the pipeline which is considered pipeline fill. The pipeline, which is used by the
Partnership to transport NGL for third parties as well as its own account, spans approximately 200 miles, running from
Kilgore to Beaumont in Texas. The acquisition was financed through the Partnership’s credit facility (see Note 11).
(i)
Freeport Terminal Acquisition. In September 2004, the Partnership completed the acquisition of a
marine terminal located near Freeport, Texas and associated assets from Offshore Oil Services, Inc. (“OOS”) for
$2,400. The terminal is located on approximately 18 acres of land and includes two warehouses and an office building.
The terminal is a full-service terminal used to distribute and market lubricants and provide shore bases for companies
that are operating in the offshore exploration and production industry.
(j)
Neches Industrial Park, Inc. Acquisition. In June 2004, the Partnership completed the acquisition
of a deep water marine terminal located near Beaumont, Texas from Neches Industrial Park, Inc. for $26,500 (which
includes an initial $1,000 payable under a related non-competition agreement). The remaining $25,500 was allocated
to property, plant and equipment. The terminal is located on 50 acres of land on the Neches River and includes two
dock structures, nine storage tanks with a total capacity of approximately 480,000 barrels, four rail spurs with service
provided by three major rail companies, a bulk warehouse and associated pipelines, pipe racks, compressors and related
equipment. The terminal provides handling and storage for ammonia, sulfuric acid, asphalt, fuel oil and fertilizer
through fee based contracts.
(5)
PUBLIC OFFERINGS
In January 2006, the Partnership completed a public offering of 3,450,000 common units at a price of $29.12
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 61.6% limited partnership interest
in the Partnership. Total proceeds from the sale of the 3,450,000 common units, net of underwriters’ discounts,
commissions and offering expenses were $95,272. The Partnership’s general partner contributed $2,050 in cash to the
Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. The
net proceeds were used to pay down revolving debt under the Partnership’s credit facility and provide working capital.
A summary of the proceeds received from these transactions and the use of the proceeds received therefrom is
as follows (all amounts are in thousands):
Proceeds received:
Sale of common units ...........................................................................................
General partner contribution .................................................................................
$100,464
2,050
Total proceeds received .................................................................................
$102,514
Use of Proceeds:
Underwriter’s fees ................................................................................................
Professional fees and other costs ..........................................................................
Repayment of debt under revolving credit facility ...............................................
Working capital ....................................................................................................
$ 4,521
671
62,000
35,322
Total use of proceeds ..............................................................................
$102,514
In February 2004, the Partnership completed a public offering of 1,322,500 common units at a price of $27.94
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 47.8% limited partnership interest
in the Partnership. Total proceeds from the sale of the 1,322,500 common units, net of underwriters’ discounts,
commissions and offering expenses were $34,016. The Partnership’s general partner contributed $754 in cash to the
Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. The
net proceeds were used to pay down revolving debt under the Partnership’s credit facility.
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
A summary of the proceeds received from these transactions and the use of the proceeds received therefrom is
as follows (all amounts are in thousands):
Proceeds received:
Sale of common units ...........................................................................................
General partner contribution .................................................................................
$36,951
754
Total proceeds received .................................................................................
$37,705
Use of Proceeds:
Underwriter’s fees ................................................................................................
Professional fees and other costs ..........................................................................
Repayment of debt under revolving credit facility ...............................................
Working capital ....................................................................................................
$ 1,940
995
30,000
4,770
Total use of proceeds ..............................................................................
$37,705
(6)
INVENTORIES
Components of inventories at December 31, 2006 and 2005 were as follows:
Natural gas liquids ........................................................................................
Sulfur ............................................................................................................
Fertilizer -- raw materials and packaging......................................................
Fertilizer -- finished goods ............................................................................
Lubricants .....................................................................................................
Other .............................................................................................................
2006
$17,061
4,397
2,412
4,807
2,592
1,750
$33,019
2005
$18,405
3,485
2,617
5,803
2,035
1,564
$33,909
(7)
PROPERTY, PLANT AND EQUIPMENT
At December 31, 2006 and 2005, property, plant, and equipment consisted of the following:
Depreciable Lives
2006
2005
Land .................................................................
Improvements to land and buildings ................
Transportation equipment ................................
Storage equipment ...........................................
Marine vessels .................................................
Operating equipment .......................................
Furniture, fixtures and other equipment ...........
Construction in progress ..................................
—
10-39 years
3- 7 years
5-20 years
4-30 years
3-30 years
3-20 years
$ 12,559
26,868
531
22,343
124,323
103,929
1,450
31,964
$323,967
$ 9,163
17,596
432
16,759
94,051
76,517
1,116
19,584
$235,218
Depreciation expense for the year ended December 31, 2006, 2005 and 2004 was $16,932, $12,062 and $8,626,
respectively.
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(8) GOODWILL AND OTHER INTANGIBLE ASSETS
The following information relates to goodwill balances as of the periods presented:
Carrying amount of goodwill:
Marine transportation .......................................................................
Natural gas services .........................................................................
Sulfur ...............................................................................................
Fertilizer ...........................................................................................
December 31, December 31,
2006
2005
$ 2,026
20,225
4,533
816
$27,600
$ 2,026
20,225
4,533
816
$27,600
The following information relates to covenants not-to-compete as of the periods presented:
Covenants not-to-compete:
Terminalling and storage .....................................................................
Natural gas services .............................................................................
Sulfur ...................................................................................................
Fertilizer ...............................................................................................
Less accumulated amortization ............................................................
December 31, December 31,
2006
2005
$ 1,561
600
100
690
2,951
877
$ 2,074
$ 1,398
600
100
690
2,788
235
$ 2,553
The covenants not-to-compete are in the consolidated balance sheets as other assets, net. Aggregate amortization
expense for amortizing intangible assets was $642, $153 and $82 for the years ended December 31, 2006, 2005, and
2004, respectively. Estimated amortization expenses for the years subsequent to December 31, 2006 are as follows:
2007 - $665; 2008 - $365; 2009 - $365; 2010 - $179; 2011 - $163; subsequent years -$338.
(9)
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.
The future minimum lease payments under non-cancelable operating leases for years subsequent to
December 31, 2006 are as follows: 2007 - $2,488; 2008 - $1,950; 2009 - $1,648; 2010 - $1,505; 2011 - $1,455 -
subsequent years -$5,949.
Rent expense for operating leases for the years ended December 31, 2006, 2005 and 2004 was $8,407,
$6,993 and $4,340, respectively.
(10)
INVESTMENT IN UNCONSOLIDATED ENTITIES AND JOINT VENTURES
In July 2005, the Partnership acquired all of the outstanding partnership interests in CF Martin Sulphur not
owned by the Partnership from CF Industries, Inc. and certain subsidiaries of Martin Resource Management. Prior
to this transaction, the Partnership owned an unconsolidated non-controlling 49.5% limited partnership interest in
CF Martin Sulphur, which was accounted for using the equity method of accounting. Equity in earnings of CF
Martin Sulphur were $222 and $912 in 2005 and 2004, respectively. Subsequent to the acquisition, CF Martin
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Sulphur was a wholly-owned subsidiary included in the Partnership’s consolidated financial statements and in the
Partnership’s sulfur segment. Effective March 30, 2006, CF Martin Sulphur was merged into the Partnership.
On November 10, 2005, the Partnership acquired Prism Gas which is engaged in the gathering, processing and
marketing of natural gas and natural gas liquids, predominantly in Texas and northwest Louisiana. Through the
acquisition of Prism Gas, the Partnership also acquired 50% ownership interests in Waskom, Matagorda and PIPE.
Each of the interests referenced above are accounted for under the equity method of accounting.
On June 30, 2006, the Partnership, through its Prism Gas subsidiary, acquired a 20% ownership interest in a
partnership for approximately $196, which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”).
BCP is an approximate 67 mile pipeline located in the Barnett Shale extension. The pipeline traverses four counties
with the most concentrated drilling occurring in Bosque County. BCP is operated by Panther Pipeline Ltd. who is the
42.5% interest owner. This interest is accounted for under the equity method of accounting.
In accounting for the acquisition of the interests in Waskom, Matagorda and Fishhook, the carrying amount
of these investments exceeded the underlying net assets by approximately $46,176. The difference was attributable
to property and equipment of $11,872 and equity method goodwill of $34,304. The excess investment relating to
property and equipment is being amortized over an average life of 20 years, which approximates the useful life of
the underlying assets. Such amortization amounted to $594 for the year ended December 31, 2006 and 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 $11,279 at December 31, 2006. The equity-
method goodwill is not amortized in accordance with SFAS 142; however, it is analyzed for impairment annually.
No impairment was recognized in 2005 or 2006.
As a partner in Waskom, the Partnership receives distributions in kind of natural gas liquids that are
retained according to Waskom’s contracts with certain producers. The natural gas liquids 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:
Waskom
PIPE
Matagorda
BCP
Total
Investment in unconsolidated entities, December 31, 2004
$ —
$ — $ — $ — $ —
Acquisition of interests ........................................................
Distributions in kind .............................................................
Cash contributions ................................................................
Cash distributions .................................................................
Equity in earnings:
Equity in earnings from operations .................................
Amortization of excess investment .................................
54,100
(1,115)
322
(495)
1,700
—
—
—
4,200
—
—
(202)
—
—
—
—
60,000
(1,115)
322
(697)
1,275
—
23
—
71
—
—
—
1,369
—
Investment in unconsolidated entities, December 31, 2005
54,087
1,723
4,069
—
59,879
Acquisition of interests ........................................................
Distributions in kind .............................................................
Cash contributions ................................................................
Cash distributions .................................................................
Equity in earnings:
Equity in earnings from operations .................................
Amortization of excess investment .................................
—
(8,311)
11,238
(150)
—
—
—
(214)
—
—
—
(610)
196
—
76
—
196
(8,311)
11,314
(974)
8,623
(550)
224
(15)
356
(29)
(62)
—
9,141
(594)
Investment in unconsolidated entities, December 31, 2006
$ 64,937
$ 1,718
$ 3,786
$ 210
$ 70,651
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Select financial information for significant unconsolidated equity method investees is as follows:
Total
Assets
Long-
Term Debt
Partner’s
Capital
Revenues
Net Income
(Loss)
2006
Waskom ...................................................................................
$ 53,260
$ —
$ 45,450
$ 65,600
$ 17,246
2005
Waskom (November 10 – December 31) ...............................
CF Martin (January 1 – July 15) .............................................
2004
$ 28,369
—
$ 28,369
$ —
—
$ 22,650
$ 9,165
$ 2,559
—
33,900
(120)
$ —
$ 22,650
$ 43,065
$ 2,439
CF Martin ................................................................................
$ 48,921
$ 10,179
$ 26,769
$ 64,719
$ 783
As of December 31, 2006, the Partnership’s interest in cash of the unconsolidated equity method investees
is $767.
(11)
LONG-TERM DEBT
At December 31, 2006 and December 31, 2005, long-term debt consisted of the following:
*$120,000 Revolving loan facility at variable interest rate (7.04%* weighted average
at December 31, 2006), due November 2010 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 .......................................................................................................
**$130,000 Term loan facility at variable interest rate (7.34%* at December 31,
2006), due November 2010, 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 .............
***United States Government Guaranteed Ship Financing Bonds .........................
Other secured debt maturing in 2008, 7.25% ..........................................................
Total long-term debt ................................................................................................
Less current installments .........................................................................................
Long-term debt, net of current installments .............................................................
December 31,
2006
December 31,
2005
$44,000
$62,200
130,000
130,000
—
____ 95
174,095
74
$174,021
9,104
—
201,304
9,104
$192,200
*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 either LIBOR
plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin is based on a
debt leverage ratio requirement which changes quarterly. The applicable margin for revolving loans that are LIBOR
loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans
ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to
3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The
applicable margin for existing borrowings through December 31, 2006 was 2.00%. Effective January 1, 2007, the
applicable margin for existing borrowings increased to 2.5%. Effective April 1, 2007, the applicable margin for
existing borrowings will decrease to 2.0%. The Partnership incurs a commitment fee on the unused portions of the
credit facility.
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
*Effective December 13, 2006, the Partnership entered into a cash flow hedge that swaps $40,000 of floating rate to
fixed rate. The fixed rate cost is 4.82% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow
hedge matures in December, 2009.
* Effective December 13, 2006, the Partnership entered into an interest rate swap that swaps $30,000 of floating rate to
fixed rate. The fixed rate cost is 4.765% plus the Partnership’s applicable LIBOR borrowing spread. This interest rate
swap, which matures in March, 2010, is not accounted for as a cash flow hedge.
**Effective April 13, 2006, the Partnership entered into a cash flow hedge that swaps $75,000 of floating rate to
fixed rate. The fixed rate cost is 5.25% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow
hedge matures in November, 2010.
*** The Partnership’s credit facility required it to redeem the U.S. Government Guaranteed Ship Financing Bonds
by March 31, 2006. The Partnership redeemed these bonds on March 6, 2006 with available cash and borrowings
from its credit facility.
On August 18, 2006, the Partnership purchased certain terminalling asphalt assets in Houston, Texas from
Gulf States Asphalt Company LP and assumed associated long term debt of $113 with a fixed interest rate of 7.25%.
On November 10, 2005, the Partnership entered into a new $225,000 multi-bank credit facility comprised
of a $130,000 term loan facility and a $95,000 revolving credit facility, which includes a $20,000 letter of credit
sub-limit. This credit facility also includes procedures for additional financial institutions to become revolving
lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of
$100,000 for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30,
2006, the Partnership increased its revolving credit facility $25,000 resulting in a committed $120,000 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. Under the amended and
restated credit facility, as of December 31, 2006, the Partnership had $44,000 outstanding under the revolving credit
facility and $130,000 outstanding under the term loan facility. As of December 31, 2006, the Partnership had
$75,900 available under the revolving credit facility.
On July 14, 2005, the Partnership issued a $120 irrevocable letter of credit to the Texas Commission on
Environmental Quality to provide financial assurance for its used oil handling program.
Indebtedness under the credit facility bears interest at either 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
1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to
2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable
margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing
borrowings is 2.00%. As a result of the Partnership’s leverage ratio test, effective January 1, 2007, the applicable
margin for existing borrowings will increase to 2.50%. Effective April 1, 2007, the applicable margin for existing
borrowings will decrease to 2.00%. The Partnership incurs a commitment fee on the unused portions of the credit
facility.
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. 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
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
business; and (xii) its joint ventures to incur indebtedness or grant certain liens.
The credit facility also contains covenants, which, among other things, require the Partnership to maintain
specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75,000 plus 50% of net proceeds
from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of
not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than (x) 5.5 to
1.0 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31,
2005 through September 30, 2006, and (z) 4.75 to 1.00 for each fiscal quarter thereafter; and (iv) total secured
funded debt to EBITDA of not more than (x) 5.50 to 1.00 for the fiscal quarter ended September 30, 2005, (y) 5.25
to 1.00 for the fiscal quarters ending December 31, 2005 through September 20, 2006, and (z) 4.00 to 1.00 for each
fiscal quarter thereafter. The Partnership was in compliance with the debt covenants contained in credit facility for
the years ended December 31, 2006 and 2005.
On November 10 of each year, commencing with November 10, 2006, the Partnership must prepay the
term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio
of total funded debt to EBITDA is less than 3.00 to 1.00. This ratio was below 3.00 for all periods in 2006 and no
prepayments were required under the term loan in 2006. 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. Any such prepayments are first applied to the term loans under the
credit facility. 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
November 10, 2010. 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.
Draws made under the Partnership’s credit facility are normally made to fund acquisitions and for working
capital requirements. During the current fiscal year, draws on the Partnership’s credit facility have ranged from a
low of $130,000 to a high of $197,700. As of December 31, 2006, the Partnership had $75,900 available for working
capital, internal expansion and acquisition activities under the Partnership’s credit facility.
On July 15, 2005, the Partnership assumed $9,400 of U.S. Government Guaranteed Ship Financing Bonds,
maturing in 2021, relating to the acquisition of CF Martin Sulphur. The outstanding balance as of December 31,
2005 was $9,104. These bonds are payable in equal semi-annual installments of $291, and are secured by certain
marine vessels owned by CF Martin Sulphur. Pursuant to the terms of an amendment to the Partnership’s credit
facility that it entered into in connection with the acquisition of CF Martin Sulphur, the Partnership was obligated to
repay these bonds by March 31, 2006. The Partnership redeemed these bonds on March 6, 2006 with available cash
and borrowings from its credit facility. In addition, a pre-payment premium was paid in the amount of $1,160.
The Partnership paid cash interest in the amount of $12,426, $5,278 and $2,018 for the years ended
December 31, 2006, 2005, 2004 respectively. Capitalized interest related primarily to the construction of the sulfur
priller in Beaumont, Texas and the sulfuric acid plant in Plainview, Texas for the years ended December 31, 2006,
2005, 2004 was $1,546, $237 and $0, respectively.
(12)
INTEREST RATE CASH FLOW HEDGES
In April, 2006, the Partnership entered into a cash flow hedge agreement with a notional amount of $75,000
to hedge its exposure to increases in the benchmark interest rate underlying its variable rate term loan credit facility.
This interest rate swap matures in November 2010. The Partnership designated this swap agreement as a cash flow
hedge. Under the swap agreement, the Partnership pays a fixed rate of interest of 5.25% and receive a floating rate
based on a three-month U.S. Dollar LIBOR rate. Because this is designated as a cash flow hedge, the changes in fair
value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest
costs are recognized in earnings. At the inception of the hedge, the swap was identical to the hypothetical swap as
DAL02:480617.6
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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt
and the swap remain equal. This condition results in a 100% effective swap.
In December 2006, the Partnership entered into a cash flow hedge agreement with a notional amount of
$40,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit
facility. This interest rate swap matures in December 2009. The Partnership designated this swap agreement as a
cash flow hedge. Under the swap agreement, the Partnership pays a fixed rate of interest of 4.82% and receives a
floating rate based on a three-month U.S. Dollar LIBOR rate. Because this is designated as a cash flow hedge, the
changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the
hedged interest costs are recognized in earnings. At the inception of the hedge, the swap was identical to the
hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate
resetting dates for the debt and the swap remain equal. This condition results in a 100% effective swap.
In December 2006, the Partnership entered into an interest rate swap that swaps $30,000 of floating rate to
fixed rate. The fixed rate cost is 4.765% plus the Partnership’s applicable LIBOR borrowing spread. This interest
rate swap matures in March 2010. The underlying debt related to this swap was paid prior to December 31, 2006,
therefore; therefore, hedge accounting was not utilized. The swap has been recorded at fair value at December 31,
2006 with an offset to current operations.
During the year ended December 31, 2006, the Partnership recognized increases in interest expense of less
than $100 related to the difference between the fixed rate and the floating rate of interest on the interest rate swaps.
The total fair value of the interest rate swaps agreement was a liability of approximately $83 at December 31, 2006.
The fair value of derivative assets and liabilities are as follows:
Fair value of derivative assets — current .............................................
Fair value of derivative assets — long-term .........................................
Fair value of derivative liabilities — long term ...................................
Net fair value of derivatives .................................................................
(13) RELATED PARTY TRANSACTIONS
December 31,
2006
$ 377
112
(572)
$ (83)
Included in the consolidated financial statements are various related party transactions and balances
primarily with 1) Martin Resource Management and affiliates, 2) CF Martin Sulphur (through July 15, 2005) and 3)
Waskom since November 10, 2005.
Related party transactions include sales and purchases of products and services between the Partnership and
these related entities as well as payroll and associated costs and allocation of overhead.
The impact of these related party transactions is reflected in the consolidated financial statement as follows:
2006
2005
2004
Revenues:
Terminalling and storage ...........................................................
Marine transportation ................................................................
$ 8,926
15,319
$ 8,938
11,606
Product sales:
Natural gas services ............................................................
Sulfur ..................................................................................
Fertilizer .............................................................................
Terminalling and storage ...................................................
1,303
—
24
59
1,386
$ 25,631
44
—
229
5
278
$ 20,822
$ 5,739
14,326
345
—
1,654
124
2,123
$ 22,188
Costs and expenses:
DAL02:480617.6
- 96 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Cost of products sold:
Natural gas services ............................................................
Sulfur ..................................................................................
Fertilizer .............................................................................
Terminalling and storage ....................................................
Expenses:
Operating expenses
Marine Transportation ........................................................
Natural gas services ............................................................
Sulfur ..................................................................................
Fertilizer .............................................................................
Terminalling and storage ....................................................
Selling, general and administrative:
Marine Transportation ........................................................
Natural gas services ............................................................
Sulfur ..................................................................................
Fertilizer .............................................................................
Terminalling and storage ....................................................
Indirect overhead allocation, net of reimbursement ...........
$ 52,030
5,253
6,660
1
$ 63,944
$ 20,051
1,560
800
128
3,931
$ 26,470
$ —
773
494
1,220
74
1,305
$ 3,866
$ 15,827
2,110
7,733
31
$ 25,701
$ 15,746
1,236
263
32
3,485
$ 20,762
$ —
833
212
1,232
76
1,120
$ 3,473
$ 7,101
—
6,378
—
$ 13,479
$ 11,733
917
—
—
$ 2,825
$ 15,475
$ —
748
—
1,104
76
736
$ 2,664
The Partnership is a party to an omnibus agreement with Martin Resource Management. The omnibus
agreement requires the Partnership to reimburse Martin Resource Management for all direct and indirect expenses it
incurs or payments it makes on the Partnership’s behalf or in connection with the operation of the Partnership’s
business. The Partnership reimbursed Martin Resource Management direct costs and expenses of $49,093,
$42,068, and $31,386 for the years ended December 31, 2006, 2005, and 2004, respectively. There is no monetary
limitation on the amount the Partnership is required to reimburse Martin Resource Management for direct expenses.
Under the omnibus agreement, the reimbursement amount with respect to indirect general and administrative and
corporate overhead expenses was capped at $2,000 for the twelve month period ending October 31, 2004.
Subsequently, this amount may be increased by no more than the percentage increase in the consumer price index
and is also subject to adjustment for expansions of the Partnership’s operations and acquisitions. The Partnership
reimbursed Martin Resource Management indirect cost and expenses of $1,493, $1,348, and $1,058 for the years
ended December 31, 2006, 2005, and 2004, respectively. These indirect expenses cover all of the centralized
corporate functions Martin Resource Management provides for the Partnership, 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 omnibus agreement also contains significant non-compete provisions and indemnity obligations.
(14)
FINANCIAL INSTRUMENTS
Statement of Financial Accounting Standards No. 107, 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.
DAL02:480617.6
- 97 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(15) COMMODITY CASH FLOW HEDGES
The Partnership is exposed to market risks associated with commodity prices, counterparty credit and
interest rates. Historically, the Partnership has not engaged in commodity contract trading or hedging activities.
However, in connection with the acquisition of Prism Gas, the Partnership has established a hedging policy and
monitors and manages the commodity market risk associated with the commodity risk exposure of the Prism Gas
acquisition. In addition, the Partnership is focusing on utilizing counterparties for these transactions whose financial
condition is appropriate for the credit risk involved in each specific transaction.
The Partnership uses derivatives to manage the risk of commodity price fluctuations. Additionally, the
Partnership manages interest rate exposure by targeting a ratio of fixed and floating interest rates it deems prudent
and using hedges to attain that ratio.
In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), Accounting for
Derivative Instruments and Hedging Activities, 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 other
comprehensive income until such time as the hedged item is recognized in earnings. In early 2006, the Partnership
adopted a hedging policy that allows it to use hedge accounting for financial transactions that are designated as hedges.
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, 2006, 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 other comprehensive income as a component of equity.
The components of gain/loss on derivatives qualifying for hedge accounting and those that do not are
included in the revenue of the hedged item in the Consolidated Statements of Operations and for the year ended
December 31, 2006 they are as follows:
December 31,
2005
2006
Change in fair value of derivatives that do not qualify for hedge accounting ..............
Ineffective portion of derivatives qualifying for hedge accounting ...............................
Change in fair value of derivatives in the Consolidated Statement of Operations .......
$ 1,117
(2)
$ 1,115
$ 512
—
$ 512
The fair value of derivative assets and liabilities are as follows:
Fair value of derivative assets — current........................................
Fair value of derivative assets — long term ...................................
Fair value of derivative liabilities — current ..................................
Fair value of derivative liabilities — long term ..............................
Net fair value of derivatives ............................................................
December 31,
2006
2005
$ 882
221
—
(74)
$1,029
$ 523
—
(88)
—
$ 435
Set forth below is the summarized notional amount and terms of all instruments held for price risk
management purposes at December 31, 2006 (all gas quantities are expressed in British Thermal Units, crude oil and
natural gas liquids are expressed in barrels). As of December 31, 2006, the remaining term of the contracts extend
no later than December 2009, with no single contract longer than one year. The Partnership’s counterparties to the
derivative contracts include Coral Energy Holding LP, Morgan Stanley Capital Group Inc. and Wachovia Bank. For
the period ended December 31, 2006, changes in the fair value of the Partnership’s derivative contracts were
recorded in both earnings and in other comprehensive income as a component of equity since the Partnership has
DAL02:480617.6
- 98 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
designated a portion of its derivative instruments as hedges as of December 31, 2006.
Transaction Type
Total
Volume
Per Month
Mark to Market Derivatives::
December 31, 2006
Pricing Terms
Remaining Terms
of Contracts
Fair Value
Crude Oil swap
5,000 BBL Fixed price of $65.95 settled against WTI
NYMEX average monthly closings
Natural Gas swap
and Natural Gas
basis swap
20,000
MMBTU
Combined fixed price of $8.54 settled
against IF Centerpoint Energy Gas
Transmission Co.
January 2007 to
December 2007
January 2007 to
December 2007
Total swaps not designated as cash flow hedges
Cash Flow
Hedges:
Ethane Swap
8,000 BBL Fixed price of $28.04 settled against Mt.
Belvieu Purity Ethane average monthly
postings
January 2007 to
December 2007
Crude Oil Swap
5,000 BBL Fixed price of $66.20 settled against WTI
NYMEX average monthly closings
Natural Gas swap
30,000
MMBTU
Fixed price of $8.12 settled against IF
Houston Ship Channel first of the month
Crude Oil Swap
3,000 BBL Fixed price of $69.08 settled against WTI
NYMEX average monthly closings
Total swaps designated as cash flow hedges
Total net fair value of derivatives
January 2008 to
December 2008
January 2008 to
December 2008
January 2009 to
December 2009
103
556
$ 659
223
(74)
155
66
$ 370
$ 1,029
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, and has established a maximum credit limit
threshold pursuant to its hedging policy, and monitors the appropriateness of these limits on an ongoing basis. The
Partnership has incurred no losses associated with the counterparty non-performance on derivative contracts.
As a result of the Prism Gas acquisition, the Partnership is exposed to the impact of market fluctuations in
the prices of natural gas, natural gas liquids (“NGLs”) and condensate as a result of gathering, processing and sales
activities. Prism Gas 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
(POL) and percent-of-proceeds (POP) basis. Prism Gas has entered into hedging transactions through 2009 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 ethane.
Based on estimated volumes, as of December 31, 2006, Prism Gas had hedged approximately 60%, 45%,
and 14% of its commodity risk by volume for 2007, 2008, and 2009, 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
DAL02:480617.6
- 99 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
will be similar to the Partnership’s existing hedging arrangements. In addition, the Partnership will consider
derivative arrangements that include the specific NGL products as well as natural gas and crude oil.
Hedging Arrangements in Place
Year
Commodity Hedged
Volume
Type of Derivative
Basis Reference
2007 Condensate & Natural Gasoline
2007 Natural Gas
2007 Natural Gas
5,000 BBL/Month
Crude Oil Swap ($65.95)
20,000 MMBTU/Month Natural Gas Swap ($9.14)
20,000 MMBTU/Month Natural Gas Basis Swap (-$0.60) Henry Hub to
NYMEX
Henry Hub
Condensate & Natural Gasoline
2007 EEthane
2008
2008 Natural Gas
2009 Condensate & Natural Gasoline
8,000 BBL/Month
5,000 BBL/Month
30,000 MMBTU/Month Natural Gas Swap ($8.12)
Crude Oil Swap ($69.08)
3,000 BBL/Month
Ethane Swap ($28.04)
Crude Oil Swap ($66.20)
Centerpoint East
Mt. Belvieu
NYMEX
Houston Ship Channel
NYMEX
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 continuance of deliveries to the buyer unless the buyer provides security for payment
in a form satisfactory to the Partnership.
Impact of Cash Flow Hedges
Crude Oil
For the years ended December 31, 2006 and 2005, net gains and losses on swap hedge contracts increased
crude revenue by $76 and decreased crude revenue by $38, respectively. As of December 31, 2006 an unrealized
derivative fair value loss of $8, related to cash flow hedges of crude oil price risk, was recorded in other
comprehensive income (loss). A fair value loss of $74 is expected to be reclassified into earnings in 2008. A fair
value gain of $66 is expected to be reclassified into earnings in 2009. 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 amount is not reflected above.
Natural Gas
For the years ended December 31, 2006 and 2005, net gains on swap hedge contracts increased gas revenue
by $1,097 and $369, respectively. As of December 31, 2006, an unrealized derivative fair value gain of $155 related
to cash flow hedges of natural gas price risk was recorded in other comprehensive income. This fair value gain is
expected to be reclassified to earnings in 2008. 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 amount is not reflected above.
Natural Gas Liquids
For the years ended December 31, 2006 and 2005, net gains and losses on swap hedge contracts decreased
and increased liquids revenue by $58 and $181, respectively. As of December 31, 2006, an unrealized derivative
fair value gain of $223 related to cash flow hedges of ethane price risk was recorded in other comprehensive income
(loss). This fair value gain is expected to be reclassified into earnings in 2007. 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 amount is not reflected above.
(16) PARTNERS’ CAPITAL
As of December 31, 2006, partners’ capital consists of 10,603,808 common limited partner units,
DAL02:480617.6
- 100 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
representing a 79.0% limited partnership interest, 2,552,018 subordinated limited partner units, representing a 19.0%
partnership interest and a 2% general partner interest. Martin Resource Management and its subsidiaries, in the
aggregate, owned an approximate 38.6% limited partnership interest consisting of 2,632,799 common limited
partner units and 2,552,018 subordinated limited partner units and a 2% general partner interest.
The Partnership Agreement contains specific provisions for the allocation of net income and losses to each
of the partners for purposes of maintaining their respective partner capital accounts
Distributions of Available Cash
The Partnership distributes all of its Available Cash (as defined in the Partnership Agreement) within 45
days after the end of each quarter to unitholders of record and to the general partner. Available Cash is generally
defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less the amount of cash
reserves its general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the
proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other
agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the
next four quarters, plus all cash on the date of determination of available cash for the quarter resulting from working
capital borrowings made after the end of the quarter.
Subordination Period
During the subordination period (defined in the Partnership Agreement), the common units have the right
to receive distributions of available cash in an amount equal to the minimum quarterly distribution of $0.50 per
quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior
quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.
The subordination period ends on the first day of any quarter beginning after September 30, 2009, when
certain financial tests (defined in the Partnership Agreement) are met. Additionally, a portion of the subordinated
units may convert earlier into common units on a one-for-one basis if additional financial tests (defined in the
Partnership Agreement) are met.
The partnership agreement provides that before the end of the subordination period, a portion of the
subordinated units may convert into common units on a one-for-one basis immediately after the distribution of
available cash to the partners in respect of any quarter ending on or after:
• September 30, 2005 with respect to 20% of the subordinated units;
• September 30, 2006 with respect to 20% of the subordinated units;
• September 30, 2007 with respect to 20% of the subordinated units;
• September 30, 2008 with respect to 20% of the subordinated units;
As a result of achieving the defined financial test, 850,672 subordinated units representing 20% of the total
originally issued subordinated units were converted into common units on both November 10, 2006 and 2005. A
total of 1,701,244 subordinated units representing 40% of the total originally issued subordinated units have been
converted into common units as of December 31, 2006. When the subordination period ends, any remaining
subordinated units will convert into common units on a one-for-one basis and the common units will no longer be
entitled to arrearages.
(17)
GAIN ON INVOLUNTARY CONVERSION OF ASSETS
During the third quarter of 2005, several of the Partnership’s facilities in the Gulf of Mexico were in the path
of two major storms, Hurricane Katrina and Hurricane Rita. 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 $100 for
flood damage and the greater of $100 or 2% of total insured value at each location for wind damage. The Partnership’s
total flood coverage is $5,000 and total wind coverage is $40,000.
DAL02:480617.6
- 101 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
The most significant damage to the Partnership’s assets was sustained at the Cameron East location. Property
damage also occurred at the Partnership’s Sabine Pass, Venice, Intracoastal City, Port Fourchon, Galveston, Cameron
West, Neches and Stanolind locations. Based on an analysis of the damage as performed by the Partnership and its
insurance underwriters, the Partnership had estimated its non-cash impairment charge as $1,200 for all the 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.
The Partnership recognized a $700 estimated loss during the last half of 2005, which approximates the
Partnership’s hurricane deductibles under its applicable insurance policies, incurred as a result of Hurricanes Katrina
and Rita. The loss is included in “operating expenses” in the consolidated statement of operations for the year ended
December 31, 2005.
Insurance proceeds received as a result of the aforementioned claims exceeded net book value of the
Partnership’s assets determined to be impaired. During 2006, the Partnership received insurance proceeds of $4,812
for this involuntary conversion of assets, which resulted in a gain of $3,125 which is reported in other operating
income.
(18)
COMMITMENTS AND CONTINGENCIES
From time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course
of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse
effect on the Partnership.
(19)
BUSINESS SEGMENTS
The Partnership has five reportable segments: terminalling and storage, natural gas services, marine
transportation, sulfur which was added in 2005, and fertilizer. The Partnership’s reportable segments are strategic
business units that offer different products and services. The operating income of these segments is reviewed by the
chief operating decision maker to assess performance and make business decisions.
The accounting policies of the operating segments are the same as those described in Note 2 of the notes to
consolidated financial statements. The Partnership evaluates the performance of its reportable segments based on
operating income. There is no allocation of administrative expenses or interest expense.
Operating
Revenues
Intersegment
Eliminations
Operating
Revenues
After
Eliminations
Depreciation
and
Amortization
Operating
Income
(Loss)
Capital
Expenditures
Year ended December 31, 2006:
Terminalling and storage ...............
Natural gas services .......................
Marine transportation ....................
Sulfur..............................................
Fertilizer .........................................
Indirect selling, general, and
$ 36,606
389,735
50,174
62,467
41,842
$ (389)
—
(2,339)
(1,196)
(516)
$ 36,217
389,735
47,835
61,271
41,326
$ 4,700
1,667
6,609
2,997
1,624
$ 12,504
4,239
6,411
4,864
1,844
$ 13,371
5,552
18,840
12,582
16,007
administrative ............................
—
—
—
—
(3,253)
—
Total ...........................................
$580,824
$ (4,440)
$ 576,384
$ 17,597
$ 26,609
$ 66,352
Year ended December 31, 2005
Terminalling and storage ...............
Natural gas services .......................
Marine transportation ....................
Sulfur..............................................
Fertilizer .........................................
Indirect selling, general, and
$ 32,962
301,676
37,724
37,472
31,838
$ (64)
—
(2,273)
(688)
(204)
$ 32,898
301,676
35,451
36,784
31,634
$ 4,376
356
4,942
1,790
1,178
$ 9,314
6,003
2,384
2,937
1,785
$ 4,708
1,669
6,020
9,514
2,903
administrative ............................
—
—
—
—
(3,463)
—
Total ...........................................
$441,672
$ (3,229)
$ 438,443
$ 12,642
$ 18,960
$ 24,814
DAL02:480617.6
- 102 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Operating
Revenues
Intersegment
Eliminations
Operating
Revenues
After
Eliminations
Depreciation
and
Amortization
Operating
Income
(Loss)
Capital
Expenditures
Year ended December 31, 2004:
Terminalling and storage ...............
Natural gas services .......................
Marine transportation ....................
Fertilizer .........................................
Indirect selling, general, and
$ 26,283
203,427
35,261
29,780
$ (126)
—
(481)
—
$ 26,157
203,427
34,780
29,780
$ 3,740
103
3,982
941
$ 6,749
3,080
5,827
1,839
administrative ............................
—
—
—
—
(2,766)
Total ...........................................
$294,751
$ (607)
$ 294,144
$ 8,766
$ 14,729
The following table reconciles operating income to net income:
$ 204
11
4,584
383
—
$ 5,182
Operating income ....................................................
Equity in earnings of unconsolidated entities ..........
Interest expense .......................................................
Debt prepayment premium ......................................
Other, net .................................................................
Income before income taxes .............................
2006
$ 26,609
8,547
(12,466)
(1,160)
713
$ 22,243
2005
$ 18,960
1,591
(6,909)
—
238
$ 13,880
2004
$ 14,729
912
(3,326)
—
11
$ 12,326
Revenues from one customer in the Natural gas services segment were $60,870, $45,396 and $34,594 for
the years ended December 31, 2006, 2005 and 2004, respectively.
Total assets by segment are as follows:
Total assets:
Terminalling and storage ..........................................
Natural gas services ..................................................
Marine transportation ................................................
Sulfur ........................................................................
Fertilizer ....................................................................
Total assets .............................................................
2006
2005
$ 89,354
184,464
77,668
62,210
43,765
$457,461
$ 68,429
180,464
54,772
55,367
30,012
$389,044
Investments in unconsolidated entities totaled $70,651 and $59,879 at December 31, 2006 and 2005,
respectively, and are included in the natural gas services segment.
(20)
QUARTERLY FINANCIAL INFORMATION
CONSOLIDATED QUARTERLY INCOME -STATEMENT INFORMATION
First
Quarter
Fourth
Quarter
(Dollar in thousands, except per unit amounts)
Second
Quarter
(Unaudited)
Third
Quarter
2006
Revenues..............................................................
Operating Income ................................................
Equity in earnings of unconsolidated entities ......
Net income ...........................................................
Net income per limited partner unit .....................
$146,822 $133,052
5,874
5,884
2,310
2,412
4,287
5,248
$ 0.33 $ 0.40
$147,505
4,720
2,720
4,329
$ 0.32
$149,005
10,131(1)
1,105(2)
8,378(1)
$ 0.63
DAL02:480617.6
- 103 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
First
Quarter
Fourth
Quarter
(Dollar in thousands, except per unit amounts)
Second
Quarter
Third
Quarter
2005
Revenues.................................................................................
Operating Income ...................................................................
Equity in earnings of unconsolidated entities .........................
Net income ..............................................................................
Net income per limited partner unit ........................................
$96,140
4,495
75
3,531
$ 0.41
$84,896
3,877
120
2,943
$ 0.34
$112,780
6,433
27
4,846
$ 0.56
$144,627(3)
4,155
1,369(4)
2,560
$ 0.28
First
Quarter
Fourth
Quarter
(Dollar in thousands, except per unit amounts)
Third
Quarter
Second
Quarter
2004
Revenues.................................................................................
Operating Income ...................................................................
Equity in earnings(loss) of unconsolidated entities ................
Net income ..............................................................................
Net income per limited partner unit ........................................
$69,068
3,804
529
3,638
$ 0.45
$61,253
2,799
362
2,422
$ 0.28
$72,190
3,073
(359)
1,862
$ 0.22
$91,633
5,053
380
4,404
$ 0.51
(1) Includes recognition of gain on involuntary conversion of assets of $2,272.
(2) Decrease in equity in earnings of unconsolidated entities due a shut down of the Waskom plant in the fourth
quarter..
(3) Includes Prism Gas revenues of $17,459 since acquisition date on November 10, 2005.
(4) Represents $1,369 in equity in earnings of unconsolidated entities and joint ventures of Prism Gas since its
acquisition on November 10, 2005.
DAL02:480617.6
- 104 -
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
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, 2006. 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, 2006, to
provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the
Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and
Exchange Commission’s rules and forms.
Changes in internal controls. 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 control over financial reporting.
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, 2006. Our management’s
assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been
audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included
herein.
Item 9B. Other Information
None.
Item 10. Directors and Executive Officers of the Registrant
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 and applicable securities laws. 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. In addition, the
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members of the conflicts committee also serve on an audit committee that 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 members of the conflicts committee also serve on the compensation committee,
which oversees compensation decisions for the officers of our general partner as well as the compensation plans
described below. The current members of our conflicts committee, audit committee, nominating committee and
compensation committee are our outside directors, John P. Gaylord, C. Scott Massey and Howard Hackney, all of
whom meet the independence standards established by NASDAQ.
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.
Name
Age
Position with the General Partner
Ruben S. Martin
Robert D. Bondurant
Donald R. Neumeyer
Wesley M. Skelton
Scott D. Martin
Chris Booth
John P. Gaylord
C. Scott Massey
Howard Hackney
55
48
59
59
41
37
46
54
67
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 and Director
Vice President, General Counsel and Secretary
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 and
Scott D. Martin, see below, are brothers. Mr. Martin holds a bachelor of science degree in industrial management from
the University of Arkansas.
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
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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.
Scott D. Martin serves as Executive Vice President and as a member of the Board of Directors of our general
partner. Mr. Martin has served as a director of our general partner since June 2002. He was appointed as Executive
Vice President of our general partner in February 2006. Mr. Martin has served as a Director of Martin Resource
Management since 1990. He has held a variety of positions in marketing, transportation, terminalling, finance,
operations and business development with Martin Resource Management since 1980. Mr. Martin and Ruben S. Martin,
see above, are brothers. Mr. Martin holds a bachelor of science degree in business administration from University of
Arkansas, where he is a member of the Walton Business School advisory board.
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.
John P. Gaylord serves as a member of the Board of Directors of our general partner. Mr. Gaylord has served
as a Director since June 2002. Mr. Gaylord has served as the President of Jacintoport Terminal Company since 1992.
He originally joined Jacintoport Terminal Company when it was founded in 1989 as Vice President of Finance.
Jacintoport Terminal Company is the general partner of Chartco Terminal L.P. which has terminalling and storage
operations in Houston, Texas. Mr. Gaylord holds a bachelor of arts degree from Texas Christian University and a
master of business administration degree from Southern Methodist University.
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.
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 Risk Management Committees. Mr. Hackney is also currently an adjunct faculty member at
LeTourneau University Business School in finance and management. 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.
Independence of Directors
Messrs. Gaylord, Massey and Hackney 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.
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Board Meetings and Committees
From January 1, 2006 to December 31, 2006, the Board of Directors of our general partner held 17 meetings.
All five directors then in office attended each of these meetings, either in person or by teleconference, with the
exception of two meetings whereby one director was absent. Additionally, the Board of Directors undertook action
five times during 2006 without a meeting by acting through written unanimous consent. We have standing conflicts,
audit, compensation and nominating committees of the Board of Directors of our general partner. The Board of
Directors of our general partner appoints the members of the Audit, Compensation, Nominating and Conflicts
Committees. Each member of the Audit, Compensation, Nominating and Conflicts Committees 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, 2006 to December 31, 2006, and a brief description of the functions performed by each committee are
set forth below:
Conflicts Committee (5 meetings). The members of the conflicts committee are Messrs. Gaylord (chairman),
Massey and Hackney. 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. 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 (7 meetings). The members of the audit committee are Messrs. Gaylord, Massey (chairman)
and Hackney. All of the members, attended all meetings of the audit committee for the period noted above, with the
exception of two meetings whereby one member was absent. 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 (2 meetings). The members of the compensation committee are Messrs. Gaylord,
Massey and Hackney (chairman). The primary responsibility of the compensation committee is to oversee
compensation decisions for the outside directors of our general partner and executive officers of our general partner (in
the event they are to be paid by our general partner) as well as our long-term incentive plan.
Nominating Committee (1 meeting). The members of the nominating committee are Messrs. Gaylord, Massey
and Hackney (chairman). 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 an annual retainer fee 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
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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. 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.
Compensation Committee Interlocks and Insider Participation
The current members of the compensation committee of our general partner that are identified above were the
only persons who served on such committee during 2006. 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, officers and beneficial owners of more than 10 percent 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 on our review of copies of such forms and amendments,
we believe directors, executive officers and greater than 10% beneficial owners complied with all filing requirements
during the year ended December 31, 2006 except as follows: two reports on Form 4 following allocations pursuant to a
benefit plan of Martin Resource Management were filed late by each of Messrs. Ruben Martin, Scott Martin, Skelton,
Neumeyer and Bondurant. In addition, a report on Form 3 and two subsequent reports on Form 4 following allocations
pursuant to a benefit plan of Martin Resource Management were filed late by Messr. Booth.
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. 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.
Under the omnibus agreement, the reimbursement amount with respect to indirect general and administrative
and corporate overhead expenses is capped. In January, 2004, the cap was increased from $1.0 million to $2.0 million
for the year period ending October 31, 2004 to account for the additional operations acquired in subsequent
acquisitions, including the Tesoro Marine asset acquisition. Subsequently, this amount may be increased by no more
than the percentage increase in the consumer price index and is also subject to adjustment for expansions of our
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operations. In addition, Martin Resource Management and us can agree, subject to the approval of the conflicts
committee of our general partner, to adjust the amount for expansions in our operations and acquisitions. To date, we
have not increased this amount.
General and administrative expenses directly associated with providing services to us (such as legal and
accounting services) are not included in the overhead allocation pool and are therefore not subject to the $2.0 million
cap. 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 — Agreements — Omnibus Agreement.”
Item 11. Executive Compensation
Compensation Discussion and Analysis
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. We reimburse Martin
Resource Management for certain 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, the reimbursement amount with respect to indirect general and administrative and corporate
overhead expenses was capped at $2.0 million for the period ending October 31, 2006. Subsequently, this amount may
be increased by no more than the percentage increase in the consumer price index. In addition, Martin Resource
Management and us can agree, subject to the approval of the Conflicts Committee of our general partner, to adjust the
amount for expansions of our operations and acquisitions. As of March 5, 2007, we have not increased this cap. Please
see “Item 13. Certain Relationships and Related Transactions — Agreements — Omnibus Agreement” for a discussion
of the omnibus agreement.
The compensation policies and philosophy of Martin Resource Management govern the types and amount
of compensation granted each of the named executive officers of our general partner listed in the summary
compensation table set forth below (the “Named Executive Officers”). The board of directors and the compensation
committee of our general partner do not have responsibility for approving the elements of compensation presented in
the tables which follow this discussion. 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 for
managerial, administrative and operational support, including compensation of the Named Executive Officers,
provided by Martin Resource Management under the omnibus agreement.
Our allocation for the costs incurred by Martin Resource Management in providing compensation and benefits
to its employees who serve as the Named Executive Officers is governed by the omnibus agreement. In general, this
allocation is based upon estimates of the relative amounts of time that these employees devote to the business and
affairs of our general partner and to the business and affairs of Martin Resource Management. We bear substantially
less than a majority of Martin Resource Management’s costs of providing compensation and benefits to the Named
Executive Officers.
Although we bear an allocated portion of Martin Resource Management’s costs of providing compensation
and benefits to the Named Executive Officers, we do not have control over such costs and do not establish or direct the
compensation policies or practices of Martin Resource Management. Ruben S. Martin, the Chief Executive Officer of
our general partner, controls Martin Resource Management and has ultimate decision-making authority with respect to
compensation of the Named Executive Officers. The following elements of compensation, and Martin Resource
Management’s decisions with respect to determinations on payments, will not be subject to approvals by our general
partner’s board of directors or its Compensation Committee. Awards 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. Martin Resource Management does not have a separate compensation
committee.
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 drive performance
and reward contributions in support of the business strategies of Martin Resource Management and its affiliates,
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including us. During 2006, Martin Resource Management did not use any elements of compensation based on specific
performance-based criteria and did not have any other specific performance-based objectives.
During 2006, elements of compensation paid to the Named Executive Officers by Martin Resource
Management consisted of the following:
• Annual base salary;
• Discretionary annual cash awards;
• Awards pursuant to Martin Resource Management employee benefit plans; and
• Other compensation, including limited perquisites.
With respect to compensation objectives and decisions regarding the Named Executive Officers during 2006,
Martin Resource Management takes 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 did not consult with any compensation consultants with respect
to determining 2006 compensation for any of our named executive officers.
The compensation paid by Martin Resource Management to the Named Executive Officers is intended to
yield competitive total cash compensation and drive performance in support of our business strategies, as well as the
performance of Martin Resource Management and other Martin Resource Management affiliates for which the Named
Executive Officers perform services.
The 2006 equity-based awards under our long-term incentive plan that were given to our independent
directors were determined by the Compensation Committee. Any equity-based awards under Martin Resource
Management employee benefit plans given to the Named Executive Officers are determined by Mr. Martin.
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. 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. There have been no other awards granted pursuant to the long-term incentive plan.
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
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compensation committee, cash equivalent to the value of a common unit. The compensation committee may
determine to make grants under the plan to employees and directors containing such terms as the compensation
committee shall determine under the plan. The compensation committee will determine the period over which
restricted units or phantom units granted to employees and directors will vest. The committee may base its
determination upon the achievement of specified financial objectives. In addition, the restricted units or phantom
units will vest upon a change of control of us, our general partner or Martin Resource Management or if our general
partner ceases to be an affiliate of Martin Resource Management.
If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s
restricted units or phantom units will be automatically forfeited unless, and to the extent, the compensation
committee provides otherwise. Common units to be delivered upon the vesting of restricted units or phantom units
may be common units acquired by our general partner in the open market, common units already owned by our
general partner, common units acquired by our general partner directly from us or any affiliate of our general partner
or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost
incurred in acquiring common units. If we issue new common units upon vesting of the restricted units or phantom
units, the total number of common units outstanding will increase.
We intend the issuance of the common units upon vesting of the restricted units or phantom units under the
plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to
participate in the equity appreciation of the common units. Therefore, plan participants will not pay any
consideration for the common units they receive, and we will receive no remuneration for the units. On 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.
Unit Options. The long-term incentive plan currently permits the grant of options covering common units.
As of March 5, 2007, we have not granted any common unit options to directors or employees of our general
partner, or its affiliates. In the future, the compensation committee may determine to make grants under the plan to
employees and directors containing such terms as the committee shall determine. Unit options will have an exercise
price that, in the discretion of the committee, may not be less than the fair market value of the units on the date of
grant. In general, unit options granted will become exercisable over a period determined by the compensation
committee. In addition, the unit options will become exercisable upon a change in control of us, our general partner,
Martin Resource Management or if our general partner ceases to be an affiliate of Martin Resource Management or
upon the achievement of specified financial objectives.
Upon exercise of a unit option, our general partner will acquire common units in the open market or
directly from us or any affiliate of our general partner or use common units already owned by our general partner, or
any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference
between the cost incurred by our general partner in acquiring these common units and the proceeds received by our
general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we
issue new common units upon exercise of the unit options, the total number of common units outstanding will
increase, and our general partner will pay us the proceeds it received from the optionee.
Martin Resource Management Employee Benefit Plans
Martin Resource Management has employee benefit plans for its employees who perform services for us.
The following summary of these plans is not complete but outlines the material provisions of these plans.
Martin Resource Management Purchase Plan for Units of Martin Midstream Partners L.P. Martin
Resource Management maintains a purchase plan for our Units to provide employees of Martin Resource
Management and its affiliates who perform services for us the opportunity to acquire an equity interest in the 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.
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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
ten 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 five 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 cannot be pledged or encumbered. The
recipient must sign an agreement waiving any voting rights with respect to shares received. Cash elections are paid
in five equal annual installments. 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.
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.
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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 period from January 1, 2006 to December 31, 2006.
Name and
Principal Position
Year
Salary ($)
Total Compensation
Ruben S. Martin
President and Chief Executive Officer
2006
$137,718
$137,718
Robert D. Bondurant
Executive Vice President
and Chief Financial Officer
2006
$105.565
$105,565
Donarld R. Neumeyer
Executive Vice President and Chief Operating Officer
2006
$108,065
$108,065
Wesley M. Skelton
Executive Vice President, Controller and Chief Administrative Officer
2006
$117,780
$117,780
Scott D. Martin
Executive Vice President
Director Compensation
2006
$98,585
$98,585
As a partnership, we are managed by our general partner. The board of directors of our general partner
perform for us the functions of a board of directors of a business corporation. We are allocated 100 percent of the
director compensation of these board members. Martin Resource Management employees who are a member of the
board of directors of our general partner do not receive any additional compensation for serving in such capacity.
Name
Fees Earned Paid in
Cash ($)
Stock
Awards ($)(1)
Total ($)
Ruben S. Martin
Scott D. Martin
John P. Gaylord
C. Scott Massey
Howard Hackney
____________
N/A
N/A
$35,000
$35,000
$35,000
N/A
N/A
N/A
N/A
$30,100
$65,100
$30,100
$65,100
$30,100
$65,100
(1)
On January 24, 2006, 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. In calculating the fair value of the award, we
DAL02:480617.6
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multiplied the closing price of our common units on the NASDAQ on the date of grant, January 24, 2006,
by the number of restricted common units granted to each director.
COMPENSATION REPORT OF THE COMPENSATION COMMITTEE
The Compensation Committee of the general partner of Martin Midstream Partners L.P. has reviewed and
discussed the Compensation Discussion and Analysis section of this report with management of the general partner
of Martin Midstream Partners L.P. and, based on that review and discussions, has recommended that the
Compensation Discussion and Analysis be included in this report.
/s/ Howard Hackney
Howard Hackney, Committee Chair
/s/ John P. Gaylord
John P. Gaylord
/s/ C. Scott Massey
C. Scott Massey
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 5, 2007 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 to be
Beneficially
Owned
Percentage
of Common
Units to be
Beneficially
Owned(2)
Subordinated
Units to be
Beneficially
Owned
Percentage of
Subordinated
Units to be
Beneficially
Owned
Percentage
of Total
Units to be
Beneficially
Owned(2)
2,632,799
1,548,973
248,258
835,568
2,659,378
2,644,899
3,556
1,774
3,678
188
11,000
3,750
1,000
688,357
24.8%
14.6%
2.3%
7.9%
25.1%
24.9%
—
—
—
—
—
—
—
6.49%
2,552,018
926,279
372,386
1,253,353
2,552,018
2,552,018
—
—
—
—
—
—
—
—
2,696,424
25.4%
2,552,018
100%
36.3%
14.6%
49.1%
100%
100%
—
—
—
—
—
—
—
—
100%
39.4%
18.8%
4.7%
15.9%
39.6%
39.5%
—
—
—
—
—
—
—
5.23%
39.9%
Name of Beneficial Owner(1)
Martin Resource Management
Corporation(3) ................................
Martin Product Sales LLC ......................
Midstream Fuel Service LLC .................
Martin Resource LLC .............................
Ruben S. Martin(4) .................................
Scott D. Martin(5) .................................
Donald R. Neumeyer ..............................
Wesley M. Skelton .................................
Robert D. Bondurant ..............................
Chris Booth ............................................
John P. Gaylord(6) .................................
C. Scott Massey(6)(7) .............................
Howard Hackney(6) ...............................
Kayne Anderson Capital Advisors, L.P.(8)
All directors and executive officers as a
group (9 persons)(9) .......................
____________
(1)
(2)
(3)
The address Martin Resource Management Corporation and all of the individuals listed in this table 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 Product Sales LLC, Marine Fuel Service
LLC and Martin Resource LLC, and as such may be deemed to beneficially own the common and
subordinated units held by such entities.
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(4)
(5)
(6)
(7)
(8)
(9)
Includes 2,632,799 common units and 2,552,018 subordinated units beneficially owned by Martin
Resource Management through its ownership Martin Product Sales LLC, Marine Fuel Service LLC and
Martin Resource LLC. Ruben S. Martin beneficially owns securities in Martin Resource Management
Corporation representing approximately 61.7% of the voting power 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 2,632,799 common units and 2,552,018 subordinated units beneficially owned by Martin
Resource Management through its ownership Martin Product Sales LLC, Marine Fuel Service LLC and
Martin Resource LLC. Scott D. Martin beneficially owns securities in Martin Resource Management
representing approximately 61.7% of the voting power thereof and serves on its Board of Directors. 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.
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.
Mr. Massey may be deemed to be the beneficial owner of 250 common units held by his wife.
Based on a Schedule 13G (Amendment No. 2), dated February 2, 2007 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 688,357
common units.
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 as both Ruben S. Martin and Scott D. Martin may be deemed to
be the beneficial owners thereof.
Martin Resource Management owns our general partner and, together with our general partner, owns
approximately 39.4% of our outstanding limited partner units. The table below sets forth information as March 5, 2007
concerning (i) the beneficial ownership of the redeemable preferred stock of Martin Resource Management, (ii) each
person owning in excess of 5% of common stock of Martin Resource Management, and (iii) the common stock
ownership of (a) each director of Martin Resource Management, (b) each executive officer of Martin Resource
Management, and (c) all such executive officers and directors of Martin Resource Management as a group. Except as
indicated, each individual has sole voting and investment power over all shares listed opposite his or her name.
Name of Beneficial Owner(1)
R.S. Martin Jr. Children’s Trust No. One f/b/o Angela Santi Jones (2) .......................
Martin Resource Management Corporation Employee Stock Ownership Trust (3) .....
RSM, III Investments, Ltd.(4) ......................................................................................
Ruben S. Martin III Dynasty Trust (5) .........................................................................
SKM Partnership, Ltd .(6) ...........................................................................................
Ruben S. Martin (2) (3) (4) (5) (7) ...............................................................................
Scott D. Martin (2) (3) (6) (7) ......................................................................................
Donald R. Neumeyer (8) ..............................................................................................
Wesley M. Skelton (3) (8) ...........................................................................................
Robert D. Bondurant(8) ...............................................................................................
Executive officers and directors as a group (5 individuals)
_____________
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Beneficial Ownership of
Common Stock
Number of
Shares
Percent of
Outstanding
1,278
638
2,267
635
2,560
5,152
5,150
56
696
130
8,600
15.3%
7.6%
27.2%
7.6%
30.7%
61.7%
61.7%
*
8.3%
1.6%
100.0%
* 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
is c/o Martin Resource Management Corporation, 4200 Stone Road, Kilgore, Texas 75662.
Ruben S. Martin and Scott D. Martin are the co-trustees of the R.S. Martin Jr. Children’s Trust No. One
f/b/o Angela Santi Jones and exercise shared control over the voting and disposition of the securities owned
by this trust. As a result, these persons may be deemed to be the beneficial owners of the securities held by
such trust; thus, the number of shares of common stock reported herein as beneficially owned by such
individuals includes the 1,278 shares owned by such trust.
Ruben S. Martin, Scott D. Martin and Wesley M. Skelton are the co-trustees of the Martin Resource
Management Corporation Employee Stock Ownership Trust and exercise shared control over the voting
and disposition of the securities owned by this trust. As a result, these persons may be deemed to be the
beneficial owners of the securities held by such trust; thus, the number of shares of common stock reported
herein as beneficially owned by such individuals includes the 638 shares owned by such trust. Mr. Skelton
disclaims beneficial ownership of these 638 shares.
Ruben S. Martin is the beneficial owner of the general partner of RSM, III Investments, 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
preferred stock reported herein as beneficially owned by such individual includes the 2,267 shares owned
by such entity.
Ruben S. Martin 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; thus, the number of shares of common stock reported
herein as beneficially owned by Ruben S. Martin includes the 635 shares owned by such trust. These 635
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
preferred 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 representing approximately
61.7% of the voting power thereof and serves as its Chairman of the Board and President. Scott D. Martin
beneficially owns securities in Martin Resource Management representing approximately 61.7% of the
voting power thereof and serves on its Board of Directors. Martin Transport, Inc. is a wholly owned
subsidiary of Martin Resource Management. As a result, each of Ruben S. Martin and Scott D. 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 such individual includes the 40 shares
owned by Martin Transport, Inc.
(8)
Messrs. Neumeyer, Skelton and Bondurant have the right to acquire 66, 58 and 130 shares, respectively, by
virtue of options issued under Martin Resource Management’s nonqualified stock option plan.
Item 13. Certain Relationships and Related Transactions
Martin Resource Management owns 2,552,018 subordinated units representing approximately 19.4% of our
outstanding limited partnership units. 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 the incentive distribution rights. Our
general partner’s ability, as general partner, to manage and operate us, and Martin Resource Management’s ownership
DAL02:480617.6
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of approximately 39.4% 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 ........................................
Withdrawal or removal of our general
partner ................................................
•
•
•
4,253,362 subordinated units; (A total 1.701,344 of the original
subordinated units issued to Martin Resource Management have
been converted into common units on a one-for-one basis since the
formation of the Partnership. (850,672 subordinated units were
converted on November 14, 2005 and, 850,672 subordinated units
were converted on November 14, 2006).
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 distributions of approximately $1.2 million
on its 2.0% general partner interest and Martin Resource Management
would receive an aggregate annual distribution of approximately $6.3
million on its subordinated units.
Martin Resource Management is entitled to reimbursement for all direct and
indirect expenses it or our general partner incurs on our behalf, including
general and administrative expenses. 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. Under the omnibus agreement,
the reimbursement amount with respect to indirect general and
administrative and corporate overhead expenses was capped at $2.0 million
for the period ending October 31, 2006. Subsequently, this amount may be
increased by no more than the percentage increase in the consumer price
index. In addition, Martin Resource Management and us can agree, subject
to approval of the Conflicts Committee of our general partner, to adjust this
amount for expansions of our operations and acquisitions. 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.
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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 tradenames 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 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 a small lube oil processing business in Smackover, Arkansas,
operating an underground NGL storage facility in Arcadia, Louisiana, and
operating, solely for our account, a NGL truck loading and unloading and pipeline distribution terminal in
Mont Belvieu, Texas.
any business that Martin Resource Management acquires or constructs that has a fair market value of less
than $5.0 million;
DAL02:480617.6
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•
•
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.
Indemnification Provisions. Under the omnibus agreement, Martin Resource Management is obligated to
indemnify us for five years after the closing of our initial public offering:
•
•
certain potential environmental liabilities associated with the operation of the assets contributed to us, and
assets retained, by Martin Resource Management that relate to events or conditions occurring or existing
before November 1, 2002, and
any payments we are required to make, as a successor in interest to affiliates of Martin Resource
Management, under environmental indemnity provisions contained in the contribution agreement
associated with the contribution of assets by Martin Resource Management to CF Martin Sulphur in
November 2000.
However, Martin Resource Management’s maximum liability for this indemnification obligation will not exceed
$7.5 million. Martin Resource Management will also indemnify us for liabilities relating to:
•
•
•
•
•
legal actions currently against Martin Resource Management at the time of our formation;
events and conditions associated with any assets retained by Martin Resource Management;
certain defects in the title to the assets contributed to us by Martin Resource Management that arise within
a four year period beginning on November 1, 2002 to the extent such defects materially and adversely
affect our ownership and operation of such assets;
our failure to obtain certain consents and permits necessary to conduct our business to the extent such
liabilities arise within a three year period beginning on November 1, 2002; and
certain income tax liabilities attributable to the operation of the assets contributed to us prior to the time
that they were contributed.
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 and indirect 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. Under the omnibus agreement, the reimbursement amount with respect to indirect
general and administrative and corporate overhead expenses was capped at $2.0 million for the period ending
October 31, 2006. Subsequently, this amount may be increased by no more than the percentage increase in the
consumer price index. In addition, Martin Resource Management and us can agree, subject to approval of the
Conflicts Committee of our general partner, to adjust this amount for expansions of our operations and acquisitions.
As of March 5, 2007, we have not increased this cap. 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
DAL02:480617.6
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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 tradenames and marks, as well as
the tradenames 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, other than the
indemnification provisions and the provisions limiting the amount for which we will reimburse Martin Resource
Management for general and administrative services performed on our behalf, will terminate if we are no longer an
affiliate of Martin Resource Management.
Motor Carrier Agreement
We are a party to a motor carrier agreement effective January 1, 2006 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 between us and Martin Transport, Inc. for land
transportation services. Under the agreement, Martin Transport agreed to ship our NGL shipments as well as other
liquid products.
Term and Pricing. This agreement was amended in November 2006 and January 2007 to add additional
point-to-point rates and to lower certain fuel and insurance surcharges being charged to us. The agreement has an
initial term that expired in December 2006 but which automatically renewed through December 2007. This
agreement will continue to automatically renew 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 transports our NGL shipments as well as other liquid products. Our shipping rates were
fixed for the first year of the agreement, subject to certain cost adjustments. These rates are subject to any
adjustment to which we mutually agree 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 Agreement. We are a party to a terminal services agreement with Martin Resource
Management under which we provide the following services for Martin Resource Management at our terminals:
• we unload, transfer and store products received from vessels or trucks at the terminal; and
• we transfer products stored at the terminal to vessels or trucks.
DAL02:480617.6
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Effective each December 1, this agreement will automatically renew on a month-to- month basis until 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.
Marine Transportation Agreement. We are a party to a marine transportation agreement effective January
1, 2006 under which we provide marine transportation services to Martin Resource Management on a spot-contract
basis at applicable market rates. This agreement replaced a prior agreement between us and Martin Resource
Management covering marine transportation services which expired 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.
Product Storage Agreement. We are a party to a product storage agreement with Martin Resource
Management under which we lease storage space at Martin Resource Management’s underground storage facility
located in Arcadia, Louisiana. Effective each November 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. Our per-unit cost under this agreement is adjusted annually based
on a price index. We indemnified Martin Resource Management from any damages resulting from our delivery of
products that are contaminated or otherwise fail to conform to the product specifications established in the
agreement, as well as any damages resulting from our transportation, storage, use or handling of products.
Marine Fuel. We are a party to an agreement with Martin Resource Management under which Martin
Resource Management provides us with marine fuel at its docks located in Mobile, Alabama, Theodore, Alabama,
Pascagoula, Mississippi and Tampa, Florida. We agreed to purchase all of our marine fuel requirements that occur
in the areas serviced by these docks under this agreement. Martin Resource Management provides fuel at a set
margin of $.035 above its cost on a spot-contract basis. This agreement had an initial term that expired in
October 2005 and 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. Effective January 1, 2006 a new agreement was entered into under which Martin Resource Management
provides us with marine fuel from its locations in the Gulf of Mexico at a fixed rate over the Platt’s U.S. Gulf Coast
Index for #2 Fuel Oil.
Sulfuric Acid. We are a party to an agreement with Martin Resource Management under which Martin
Resource Management provides sulfuric acid for our Plainview facility. We agreed to purchase all of our sulfuric
acid requirements for our Plainview facility under this agreement. Martin Resource Management provides sulfuric
acid at a set margin of $4.00 per short ton above its cost on a spot-contract basis. This agreement has an initial term
that expired in October 2005 and 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.
Throughput Agreement. We are a party to an agreement under which Martin Resource Management agreed
to provide us with sole access to and use of a NGL truck loading and unloading and pipeline distribution terminal
located at Mont Belvieu, Texas. Effective each November 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. Our throughput fee is adjusted annually based on a price
index.
Purchaser Use Easement, Ingress-Egress Easement, and Utility Facilities Easement. We entered into a
Purchaser Use Easement, Ingress-Egress Easement and Utility Facilities Easement with Martin Resource
Management under which we have complete, non-exclusive access to, and use of, all marine terminal facilities, all
loading and unloading facilities for vessels, barges and trucks and other common use facilities located at the
Stanolind terminal. This easement has a perpetual duration. We did not incur any expenses, costs or other financial
obligations under the easement. Martin Resource Management is obligated to maintain, and repair all common use
areas and facilities located at this terminal. We share the use of these common use areas and facilities only with
DAL02:480617.6
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Martin Resource Management and CF Martin Sulphur who also have tanks located at the Stanolind facility. See
“Item 1. Business — Terminalling and Storage Business — Marine Terminals — Specialty Petroleum Terminals.”
Terminal Services Agreement. We entered into a terminal services agreement under which we provide
terminalling services to Martin Resource Management. Effective each December 1, this agreement will
automatically renew on a month-to- month basis until 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 per gallon throughput fee
we charge under this agreement is adjusted annually based on a price index.
Transportation Services Agreement. We entered into a transportation services agreement under which we
provide marine transportation services to Martin Resource Management. This agreement has a three-year term,
which began in December 2003, and will automatically renew for successive one-year terms 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. In addition, within 30 days of the expiration of the then-applicable term, both parties have the
right to renegotiate the rate for the use of our vessels. If no agreement is reached as to a new rate by the end of the
then-applicable term, the agreement will terminate. The hourly rate we charge under this agreement is adjusted
annually based upon mutual agreement of the parties or in accordance with a price index. This agreement was not
renewed and the marine transportation services previously provided under this agreement are now being provided to
Martin Resource Management under the terms of the Marine Transportation Agreement executed with us effective
January 1, 2006.
Specialty Terminal Services Agreement. We entered into an agreement under which Martin Resource
Management provides terminal services to us. Effective each November 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. The fees we charge under this agreement are
adjusted annually based on a price index.
Terminal Services Agreement — under which we provide terminalling services to Martin Resource
Management. This agreement 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 is adjusted annually based on a price
index.
Product Supply Agreements — under which Martin Resource Management provides us with marine fuel
and sulfuric acid. Effective each November 1, these agreements automatically renew 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 purchase products at a set margin above Martin Resource
Management’s cost for such products during the term of the agreements.
Lubricants and Drilling Fluids Terminal Services Agreement — under which Martin Resource
Management provides terminal services to us. Effective each January 1, this agreement automatically renews for
successive one-year terms until either party terminates the agreement by giving written notice to the other party at
least 60 days prior to the end of the then-applicable term. The per gallon handling fee and the percentage of our
commissions we are charged under this agreement is adjusted annually based on a price index.
Cross Terminalling Agreement — under which we provide terminalling services to Cross Oil Refining &
Marketing, Inc., an affiliate of Martin Resource Management, through October 27, 2008. The per gallon throughput
fee we charge under this agreement is adjusted during each year of the agreement.
Miscellaneous Agreements — From time to time we enter into agreements with Martin Resource
Management for the provision of other services or the purchase of other goods. In 2006, we entered into two leases
whereby we lease existing underground storage wells from Martin Underground Storage, Inc., a subsidiary of
Martin Resource Management. In addition to these two leases, in 2006, we also entered in three additional
terminalling agreements with Martin Resource Management relating to our recently acquired asphalt terminals and
the Corpus Christi barge terminal for the use of specific tankage or facilities owned by us. Each of these
terminalling agreements are based on a through-put arrangement with a minimum monthly or annual amount.
DAL02:480617.6
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Other Related Party Transactions
Issuance of Common Units. In December 2006, we issued 470,484 common units to Martin Product Sales
LLC, an affiliate of Martin Resource Management, for approximately $15.3 million, including a capital contribution of
approximately $0.3 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.
Public Offering. In January 2006, we completed a follow-on public offering of 3,450,000 common units,
resulting in proceeds of $95.4 million, after payment of underwriters’ discounts, commissions and offering expenses.
Our general partner contributed $2.1 million in cash to us in conjunction with the offering in order to maintain its 2%
general partner interest in us. Of the net proceeds, $62.0 million was used to pay then current balances under our
revolving credit facility and $7.5 million was used to fund a portion of the redemption price for our U.S. Government
Guaranteed Ship Financing Bonds. The remainder of the net proceeds has been or will be used to fund future organic
growth projects.
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.
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 $43.8 million for the year ended December 31, 2006. 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.
DAL02:480617.6
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Item 14. Principal Accounting Fees and Services
KPMG LLP served as our independent auditors for the fiscal year ended December 31, 2006 and 2005. 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
2006
2005
$ 728,200(1)
16,500(3)
744,700
$747,500(2)
37,000(3)
784,500
189,000(4)
—
138,000(4)
—
Total fees
_________________
(1)
the audit of Martin Midstream GP LLC and the review of registration statements and issuing related consents.
2006 audit fees include fees for the annual integrated audit, the audit of Waskom Gas Processing Company,
$ 922,500
$ 933,700
(2)
2005 audit fees includes fees for the annual integrated audit, issuance of the comfort letter related to the
January 2006 equity offering and reviews of acquiree financial statements as of September 30, 2005 related to the
issuance of the comfort letter.
(3)
2005.
Audit related fees include fees for accounting consultations on various transactions occurring in 2006 and
(4)
on other tax related matters.
Tax fees are for services related to review of our partnership K-1’s returns, and research and consultations
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, 2006 and December 31, 2005 were approved
in advance by the Audit Committee.
DAL02:480617.6
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Item 15. Exhibits, Financial Statements Schedules
PART IV
(a)
(1)
Financial Statements and Financial Schedules
The following financial statements of Martin Midstream Partners L.P. and are included in Part II,
Item 8:
Report of Independent Accountants
Consolidated Balance Sheets as of December 31, 2006 and 2005
Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004
Consolidated Statements of Changes in Capital/Equity for the years ended December 31, 2006,
2005 and 2004
Consolidated Statements of Comprehensive Income for the years ended December 31, 2006 and
2005.
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004
Notes to the Consolidated Financial Statements
(2)
Financial Statements of Waskom Gas Processing Company for the year ended December 31,
2006, 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 129 for a list of all exhibits filed as
part of this report.
DAL02:480617.6
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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 5, 2007
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 5th day of March, 2007.
Signature
Title
/s/ Ruben S. Martin
Ruben S. Martin
/s/ Robert D. Bondurant
Robert D. Bondurant
/s/ Wesley M. Skelton
Wesley M. Skelton
/s/ Scott D. Martin
Scott D. Martin
/s/ John P. Gaylord
John P. Gaylord
/s/ C. Scott Massey
C. Scott Massey
/s/ Howard Hackney
Howard Hackney
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
DAL02:480617.6
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Exhibit
Number
INDEX TO EXHIBITS
Exhibit Name
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
4.1
4.2
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
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 (Reg. No. 333-91706),
filed July 1, 2002, and incorporated herein by reference).
First Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 6, 2002
(filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, 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 (Reg. 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, 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 (Reg. 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 (Red. 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 (Reg. 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 (Reg. 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 (Reg. No. 333-91706), filed October 25, 2002, and
incorporated herein by reference).
Amended and Restated Credit Agreement, dated October 29, 2004, 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 11, 2004, and incorporated herein by reference).
First Amendment to Credit Agreement, dated May 3, 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 May 4, 2005, 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).
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, filed November 19, 2002, and incorporated herein by reference).
Motor Carrier Agreement dated November 1, 2002, by and between the Operating Partnership and Transport
(filed as Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and
incorporated herein by reference).
Terminal Services Agreement dated November 1, 2002, by and between the Operating Partnership and
MGSLLC (filed as Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002,
and incorporated herein by reference).
Throughput Agreement dated November 1, 2002, by and between MGSLLC and the Operating Partnership
(filed as Exhibit 10.6 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and
incorporated herein by reference).
Contract for Marine Transportation dated November 1, 2002, by and between the Operating Partnership and
DAL02:480617.6
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Exhibit
Number
10.9
Exhibit Name
Martin Resource Management (filed as Exhibit 10.7 to the Partnership’s Current Report on Form 8-K, filed
November 19, 2002, and incorporated herein by reference).
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, filed
November 19, 2002, and incorporated herein by reference).
10.10 Marine Fuel Agreement dated November 1, 2002, by and between MFSLLC and the Operating Partnership
10.11
(filed as Exhibit 10.9 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and
incorporated herein by reference).
Product Supply Agreement dated November 1, 2002, by and between MGSLLC and the Operating
Partnership (filed as Exhibit 10.10 to the Partnership’s Current Report on Form 8-K, filed November 19,
2002, and incorporated herein by reference).
10.12† Martin Midstream Partners L.P. Long-Term Incentive Plan (filed as Exhibit 10.11 to the Partnership’s
Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference).
10.13† Martin Midstream Partners L.P. Amended and Restated Long-Term Incentive Plan (filed as Exhibit 10.1 to
10.14†
10.15
10.16
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, 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, filed November 19, 2002, and incorporated herein by reference).
10.17 Marine Transportation Agreement, by and between the Operating Partnership and Cross Oil Refining &
10.18
10.19
10.20
10.21
10.22
10.23
Marketing, Inc., dated October 27, 2003 (filed as Exhibit 10.14 to the Partnership’s Quarterly Report of Form
10-Q, filed November 10, 2003, and incorporated herein by reference).
Terminalling Agreement, by and between the Operating Partnership and Cross Oil Refining & Marketing,
Inc., dated October 27, 2003 (filed as Exhibit 10.15 to the Partnership’s Quarterly Report of Form 10-Q, filed
November 10, 2003, 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, filed January 23, 2004, and incorporated herein by reference).
Purchase Agreement by and among the Operating Partnership, Prism Gas Systems I, L.P., Natural Gas
Partners V, L.P., Robert E. Dunn, William J. Diehnelt, Gene A. Adams, Philip D. Gettig, Sharon C. Taylor
and Scott A. Southard, dated September 6, 2005 (filed as Exhibit 10.1 to the Partnership’s Current Report on
Form 8-K, 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,
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, 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, filed January 23, 2004, and incorporated herein by reference).
10.24† Martin Resource Management Corporation Purchase Plan for Units of Martin Midstream Partners L.P. (filed
as Exhibit 10.1 to the Partnership’s registration statement on Form S-8 (Reg. No. 333-140152), filed
January 23, 2007, 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.
21.1*
23.1*
23.2*
31.1*
31.2*
DAL02:480617.6
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Exhibit
Number
32.1*
32.2*
Exhibit Name
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 herewith.
† As required by Item 15(a)(3) of Form 10-K, this exhibit is identified as a compensatory plan or arrangement.
DAL02:480617.6
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Financial Statement Schedule
Pursuant to Item 15(a)(2)
Waskom Gas Processing Company
Financial Statements
December 31, 2006
(With Independent Auditors’ Report Thereon)
DAL02:480617.6
Report of Independent Registered Public Accounting Firm
To the Partners of
Waskom Gas Processing Company:
We have audited the accompanying balance sheet of Waskom Gas Processing Company (the “Partnership”) as of
December 31, 2006 and the related statement of income, partners’ capital, and cash flows for the year ended
December 31, 2006. These financial statements are the responsibility of the Partnership’s management. Our
responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America.
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit also includes consideration of internal control over financial
reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly,
we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Partnership
as of December 31, 2006, and the results of its operations and its cash flows for the year ended December 31, 2006, in
conformity with U.S. generally accepted accounting principles.
KPMG LLP
/s/ KPMG LLP
Shreveport, Louisiana
March 5, 2007
DAL02:480617.6
WASKOM GAS PROCESSING COMPANY
BALANCE SHEET
AS OF DECEMBER 31, 2006
ASSETS
CURRENT ASSETS:
Cash
Accounts receivable
Accounts receivable—partners
Inventories
Total current assets
PROPERTY AND EQUIPMENT:
Gas plant asset and gas gathering equipment
Other fixed assets
Accumulated depreciation and amortization
Net property and equipment
TOTAL
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities
Accounts payable—partners
Total current liabilities
LONG-TERM LIABILITIES—Asset retirement obligation
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL
TOTAL
See accompanying notes to financial statements.
2006
$
324,979
326,753
11,227,687
436,419
12,315,838
51,331,046
564,736
(10,952,030)
40,943,753
$
53,259,590
$
5,916,140
1,706,545
7,622,686
186,988
45,449,916
$
53,259,590
DAL02:480617.6
-1-
WASKOM GAS PROCESSING COMPANY
STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 2006
OPERATING REVENUES:
Natural gas processing fees
Natural gas liquid sales
Gain on sale of assets
Total operating revenues
OPERATING COSTS AND EXPENSES:
Cost of sales - natural gas liquids
Operating costs
Depreciation and amortization
Total operating costs and expenses
OPERATING INCOME
2006
$
18,506,096
47,093,925
500
65,600,521
42,505,653
4,355,646
1,493,499
48,354,798
17,245,723
NET INCOME
$
17,245,723
See accompanying notes to financial statements.
DAL02:480617.6
-2-
WASKOM GAS PROCESSING COMPANY
STATEMENT OF PARTNERS’ CAPITAL
FOR THE YEAR ENDED DECEMBER 31, 2006
Total
Partners'
Capital
BALANCE—December 31, 2005
$
22,649,871
Cash contributions for capital expenditures
Cash contributions for working capital
Cash distributions
Distributions in-kind
Net income
19,980,733
2,494,939
(300,000)
(16,621,349)
17,245,723
BALANCE—December 31, 2006
$
45,449,916
See accompanying notes to financial statements.
DAL02:480617.6
-3-
WASKOM GAS PROCESSING COMPANY
STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2006
2006
$
17,245,723
1,493,499
(16,621,349)
(500)
(391,548)
(5,560,870)
(412,779)
805,280
1,275,364
(2,167,181)
(20,834,411)
500
(20,833,911)
22,475,672
(300,000)
22,175,672
(825,420)
1,150,399
$
324,979
$
-
$
-
OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to cash
used in operating activities:
Depreciation and amortization
Distributions in-kind to partners
Gain on sale of asset
Changes in operating assets and liabilities:
Accounts receivable
Accounts receivable - partners
Inventory
Accounts payable and accrued liabilites
Accounts payable - partners
Net cash provided by operating activities
INVESTING ACTIVITIES:
Additions to gas plant and gathering system assets
Proceeds from sale of an asset
Net cash used in investing activities
FINANCING ACTIVITIES:
Contributions from partners
Distrubutions to partners
Net cash provided by financing activities
NET DECREASE IN CASH
CASH—Beginning of year
CASH—End of year
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Interest paid
Taxes paid
See accompanying notes to financial statements.
DAL02:480617.6
-4-
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,
2006, 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 and
marketing of natural gas and natural gas liquids (“NGL’s”), predominantly in Texas and northwest Louisiana.
The Partnership owns a 150 MMcf/d 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. In October 2006, construction began to expand
the fractionator to 12,500 bpd, to provide additional capacity for increased trucked-in NGL volumes. This
expansion was completed in late January 2007.
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 and Devon Energy Corporation, which collectively represented
approximately 61% of the 183 MMcfd of natural gas supplied for the year ended December 31, 2006.
The Partnership’s processing contracts are predominately percent-of-liquids (POL) contracts, in which the
Partnership retains a portion of the NGL’s recovered as a processing fee. The Partnership also operates under
percent-of-proceeds (POP) contracts in which it retains a portion of both the residue gas and the NGL’ s as
payment for services. There are currently two minor contracts for processing on a keep-whole basis. The
Partnership is not contractually required to process these keep-whole volumes and, therefore, only processes
natural gas related to these contracts under profitable conditions.
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
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 for 2006 was $1,483,332. Of this total, $1,348,003 related to operating assets.
Repairs and maintenance are charged to operations as incurred. Renewals and betterments are capitalized.
Inventories—Substantially all inventory at December 31, 2006 represents pipe used for future projects. Such
pipe was valued at acquisition cost.
Asset Retirement Obligations—Under SFAS No. 143, “Accounting for Asset Retirement Obligations”
(“Statement No. 143) which provides accounting requirements for costs associated with legal obligations to
retire tangible, long-lived assets, the Partnership records as an offset to the Asset Retirement Obligation
(“ARO”), an asset at fair value in the period in which it is incurred by increasing the carrying amount of the
DAL02:480617.6
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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. Accretion expense
for 2006 was $10,167.
On March 31, 2005, the Financial Accounting Standards Board issued Interpretation No. 47, “Accounting for
Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143. FIN 47, which was
effective for fiscal years ending after December 15, 2005, clarifies that the recognition and measurement
provisions of SFAS 143 apply to asset retirement obligations in which the timing or method of settlement may
be conditional on a future event that may or may not be within the control of the entity. No conditional asset
retirement obligations associated with the Partnership’s long-lived assets have been identified.
Impairment of Long-Lived Assets—In accordance with SFAS No. 144, “Accounting for the Impairment or
Disposal 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
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 to the Partnership’s commercial, industrial and retail customers.
Income Taxes—The Partnership is a Texas general partnership and as such has no liability for income taxes,
except for the Texas margin tax as described in the following paragraph. 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 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 provisions of SFAS 109
regarding the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the
effect on deferred tax assets of a change in tax law should be included in tax expense attributable to continuing
operations in the period that includes the enactment date. Therefore, the Partnership has calculated its deferred
tax assets and liabilities for Texas based on the new margin tax. The cumulative effect of the change was
immaterial. The impact of the change in deferred tax assets does not have a material impact on tax expense.
There was no income tax expense recorded for the year ended December 31, 2006. Beginning 2007, the
Partnership anticipates it will incur tax expense related to this new Texas margin tax.
Environmental Liabilities—The Partnership’s policy is to accrue for losses associated with environmental
remediation obligations when such losses are probably 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.
Recently Issued Accounting Pronouncements— In September 2006, the FASB issued SFAS No. 157, “Fair
Value Measurements,” which will become effective for the Partnership on January 1, 2008. This standard
defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value
measurements. SFAS No. 157 does not require any new fair value measurements but would apply to assets and
DAL02:480617.6
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liabilities that are required to be recorded at fair value under other accounting standards. The impact, if any, to
the Partnership from the adoption of SFAS No. 157 in 2008 will depend on the Partnership’s assets and
liabilities at that time that are required to be measured at fair value.
In September 2005, the FASB’s Emerging Issues Task Force (“EITF”) issued EITF No. 04-13, “Accounting for
Purchases and Sales of Inventory with the Same Counterparty.” This pronouncement provides additional
accounting guidance for situations involving inventory exchanges between parties, to that contained in APB
Opinion No. 29, “Accounting for Nonmonetary Transactions” and SFAS 153, “Exchanges of Nonmonetary
Assets.” The standard is effective for new arrangements entered into in reporting periods beginning after March
15, 2006. The adoption did not have a material impact on the Partnership’s financial statements.
3. RELATED-PARTY TRANSACTIONS
During 2006, the Partnership engaged in certain material transactions with its 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, 2006, the Partnership had receivables of approximately $11.2 million, and
payables of approximately $1.7 million, due from and due to the partners.
Per the Partnership agreement, cash contributions are made by the partners for capital expenditures and working
capital. Such contributions totaled $19,980,733 and $2,494,939 respectively, for 2006. 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 distributions totaled
$300,000 for 2006.
The Partnership purchases gas from third party producers and processes this gas based on processing contracts,
which are primarily percent-of-liquids (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 $16,621,349 in 2006 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 $43,678,571 and
are included as NGL sales in the income statement.
4. 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.
5.
SUBSEQUENT EVENTS
On January 31, 2007, the Partnership purchased transmission lines for $800,000 located in Harrison County,
Texas and Caddo Parish, Louisiana from Centerpoint Energy Gas Transmission Company. These lines were
purchased to serve as an inlet at the Plant. The inlet conversion will be completed later in 2007. In January of
2007, construction on the Waskom fractionator was completed, resulting in an increased capacity of 12,500
barrels per day. In addition the processing capacity of the Plant is expected to be increased to 250 MMcfd by
the end of the second quarter of 2007.
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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.
McLeod Gas Gathering and Processing Company, L.L.C.
Prism Gulf Coast Systems, L.L.C.
Jurisdiction of Organization
Delaware
Delaware
Texas
Texas
Louisiana
Texas
DAL02:480617.6
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. 333-117023) on Form S-3 and
(No. 333-140152) on Form S-8 of Martin Midstream Partners L.P. of our reports dated March 5, 2007, with respect
to the consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2006 and
2005, 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, 2006, management’s assessment of the
effectiveness of internal control over financial reporting as of December 31, 2006, and the effectiveness of internal
control over financial reporting as of December 31, 2006, which reports appear in the December 31, 2006 annual
report on Form 10-K of Martin Midstream Partners L.P.
/s/ KPMG LLP
Shreveport, Louisiana
March 5, 2007
DAL02:480617.6
Consent of Independent Registered Public Accounting Firm
Exhibit 23.2
The Board of Directors
Martin Midstream GP LLC:
We consent to the incorporation by reference in the registration statements (No. 333-117023) 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 5,
2007, with respect to the balance sheet of Waskom Gas Processing Company as of December 31, 2006, and the
related statements of income, partners’ capital, and cash flows for the year ended December 31, 2006, which report
appears in the December 31, 2006 annual report on Form 10-K of Martin Midstream Partners L.P.
/s/ KPMG LLP
Shreveport, Louisiana
March 5, 2007
DAL02:480617.6
CERTIFICATION
PURSUANT TO AND IN CONNECTION WITH THE ANNUAL REPORTS ON FORM 10-K
TO BE FILED UNDER SECTIONS 13 AND 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
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 5, 2007
/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.
DAL02:480617.6
CERTIFICATION
PURSUANT TO AND IN CONNECTION WITH THE ANNUAL REPORTS ON FORM 10-K
TO BE FILED UNDER SECTIONS 13 AND 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
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 5, 2007
/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.
DAL02:480617.6
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, 2006 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 5, 2007
*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.
DAL02:480617.6
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, 2006 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 5, 2007
*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.
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mm ar 2006 cover 5/10/07 11:25 AM Page 1
4200 STONE ROAD
KILGORE, TEXAS 75662
903-983-6200
www.martinmidstream.com
on the cover:
Natural gas processing plant, Waskom, Texas