MARTIN MIDSTREAM PARTNERS
Annual Report
2007 Terminalling and Storage
We own or operate 17 marine terminal facilities and six 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. We provide these terminalling and storage services on a fee basis
primarily under long-term contracts.
Natural Gas Services
We have ownership interests in over 658 miles of gathering and transmission pipelines
located in the natural gas producing regions of Central and East Texas, Northwest Louisiana,
the Texas Gulf Coast as well as a 250 million cubic feet per day natural gas processing plant
located in East Texas. In addition to our natural gas gathering and processing business, we
distribute, store and sell natural gas liquids utilizing our supply and storage facilities. These
liquids are ultimately sold to propane retailers, refineries and industrial users in Texas and
the Southeastern United States.
Marine Transportation
We own a fleet of 37 inland marine tank barges, 18 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 Services
We process and distribute sulfur produced by oil refineries primarily located in the United
States Gulf Coast region. We process molten sulfur into prilled sulfur under both fee-based
volume contracts and buy/sell contracts at our facilities in California and Texas. We own
and operate six sulfur-based fertilizer production plants and one emulsified sulfur blending
plant that primarily manufacture sulfur-based fertilizer products for wholesale distributors
and industrial users. In addition, we manufacture sulfuric acid which is used as a feedstock
for many industrial and agricultural applications, including the manufacture of fertilizers.
The petroleum products and by-products we
collect, transport, store and distribute are produced
by the independent oil and gas companies who
often turn to third parties, such as us.
Terminalling and Storage
S
S
T
S
S
S
T
G
S
G
G
G
T
Terminalling and Storage
G
Natural Gas Services
M
S
Marine Transportation
Sulfur Services
T
T
T
T
T
M
T
T
G
T
G
G
M
S
T
M
T
T
TT
G
T
T
T
T
T T
T
M
T
S
Natural Gas Services
Marine Transportation
Financial Highlights
(in thousands, except per unit amounts)
2003
2004
2005
2006
2007
Total Assets
Revenue
Operating Income
Adjusted EBITDA(1)
Net Income
Distributable Cash Flow(1)
Distributions per Unit(2)
$ 139,685
$ 188,332
$ 389,044
$ 457,461
$ 623,577
192,731
294,144
438,443
576,384
765,822
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
28,876
67,986
24,939
45,579
$
2.00
$
2.10
$
2.19
$
2.44
$
2.60
(1) See Reconciliation on page following Form 10-K.
(2) Actual distributions per unit. First quarter 2003 distribution assumes a full quarter distribution.
$
7
6
6
$
5
7
6
$
4
3
8
$
2
9
4
$
1
9
3
$
6
8
.
0
$
5
0
.
5
$
3
3
.
1
$
2
5
.
5
$
1
8
.
9
$
4
5
.
6
$
3
2
.
1
$
2
1
.
1
$
1
8
.
0
$
1
5
.
4
’03
’04
’05
’06
’07
’03
’04
’05
’06
’07
’03
’04
’05
’06
’07
800000
700000
600000
500000
400000
300000
200000
100000
0
Revenue
(in millions)
$
7
6
6
$
5
7
6
$
4
3
8
$
2
9
4
$
1
9
3
80000
70000
60000
50000
40000
30000
20000
10000
0
Adjusted EBITDA(1)
(in millions)
Distributable
Cash Flow(1)
(in millions)
$
6
7
.
9
$
5
0
.
5
$
3
3
.
1$
2
5
.
5$
1
8
.
9
$
4
5
.
6
$
3
2
.
1
$
2
1
.
1
$
1
8
.
0
$
1
5
.
4
50000
40000
30000
20000
10000
0
Revenue
(in millions)
Adjusted EBITDA(1)
(in millions)
Distributable Cash Flow(1)
(in millions)
We operate 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 energy
and petrochemical industries.
Sulfur Services
L E T T E R T O
U N I T H O L D E R S
Ruben S. Martin
President and
Chief Executive Officer
To Our Partners:
As in previous years, 2007 proved to be another successful year of growth and development for
our partnership. The year was marked with many significant milestones, including our five-year
anniversary as a publicly-traded company. Since our formation in October of 2002, we have
developed into a unique, well-diversified company focused on providing services across the
midstream energy value chain. Our market capitalization has grown from $135 million to approx-
imately $500 million, while our annualized distributions have increased from $2.00 per unit to our
most recently declared annualized distribution of $2.80 per unit. While it is true that we have
not grown as rapidly as some of our peers over the past five years, we believe that our growth
has been strategic and disciplined, with a focus on smart acquisitions and low- multiple organic
growth. We continue to focus on this plan of long-term value creation for our unitholders.
Furthermore, we continue to avoid higher multiple, non-strategic acquisitions. We believe this
type of undisciplined growth ultimately leads to erosion of unitholder value, especially in the
presence of systemic risk.
As evidence of this risk, 2007 marked a turbulent year for master limited partnerships (MLPs)
and for the financial markets in general. As an example, the Alerian MLP Index experienced a
17% increase during the first half of the year, followed up by a 9% decrease over the second
half of the year. MMLP experienced similar volatility as evidenced by a 25% increase in unit
price for the first half of 2007, followed by a 14% decline over the remainder of the year. And
while MMLP’s unit price only slightly outperformed the Alerian MLP Index in 2007, we continued
our consistent distribution growth with an 11% increase in our fourth quarter distribution when
compared to the fourth quarter of 2006.
As we continued our distribution growth throughout 2007, the oft-mentioned “credit crunch”
deteriorated into a full-blown “credit crisis.” This resulted in significant liquidations of MLP hold-
ings across the MLP universe of companies. Unfortunately, we were not immune to this trend.
Despite this frustrating pattern, we believe it is shorter term in nature and is not unique to our
Customer demand for our energy midstream
services continues to grow. This growth provides
opportunities to expand our infrastructure and
earn attractive returns on our expansion through
our organic growth projects.
G R O W T H
partnership. What is unique, however, is our proven track record of disciplined growth through
diversification, strategic acquisitions and low-multiple organic growth projects.
Diversification
We believe we are one of the more diversified MLPs operating today. With our four segments,
we operate along many links of the midstream energy value chain. Our business segments include
Terminalling and Storage, Natural Gas Services, Marine Transportation and Sulfur Services.
These segments allow us to provide energy and petrochemical companies with the transpor tation
and logistics necessary to move and store their products. While each segment is dependent on
underlying energy fundamentals, each segment has its own unique and independent factors that
drive that particular business. This results in a diversification profile that we believe supports
long-term, steady growth in our partnership.
As you may recall, for the greater part of the last two years, we have been operating as five
segments. In the fourth quarter of 2007 we combined the historical Sulfur and Fertilizer segments
into one segment, the Sulfur Services segment. The major driver of this combination is that
sulfur and its derivatives are a primary feedstock for our sulfur-based fertilizer products. With
sulfur as the common denominator between the two historical segments, we have placed
increased focus on maximizing the value of that sulfur through its highest and best use. To that
end, we felt it was necessary to combine the two segments to more accurately reflect the way
we run the two businesses. We believe this combination will have the added benefit of reduced
segment volatility when compared to historical operations for each segment individually.
Strategic Acquisitions
As I mentioned previously, we are focused on pursuing only those acquisitions that are strategic
in nature, with a primary focus on acquisitions that supplement our existing operations. Over
the past two years, this strategy has become increasingly difficult to implement as acquisition
multiples have expanded to double-digit levels. Despite this trend, however, we have stayed
true to our strategy. As an example of this commitment, we acquired Woodlawn Pipeline
Company and related assets in May 2007 for approximately $32.6 million. This gathering and
processing system was a “bolt-on” acquisition that enhanced our existing East Texas natural
gas gathering and processing footprint. This was a negotiated transaction based on existing
relationships with the sellers that allowed us to avoid a bidding war often seen in auction
We transport asphalt, fuel oil, gasoline, sulfur
and other bulk liquids. We own a fleet of
inland and offshore tows that provide marine
transportation of petroleum products and
by-products.
W E L L P O S I T I O N E D
processes. We have been extremely pleased with the performance of Woodlawn to date and
look forward to a full year of operations in 2008.
Organic Growth Projects
As a result of the increasing multiples and competition for acquisitions, we have focused primarily
on our organic growth plan over the last two years. In 2007, we spent over $100 million on various
organic growth projects including our $25 million sulfuric acid plant which was completed in
October. The sulfuric acid plant eliminates our reliance on third-party sulfuric acid to produce
some of our sulfur-based fertilizers. With the combined effect of lower cost of sales and our
ability to sell remaining product to outside parties, we expect the sulfuric acid plant to result in
accretion to our unitholders. In addition to the sulfuric acid plant, we also completed our
Waskom expansion in the second quarter, increasing our processing capacity from 150 million
cubic feet per day to 250 million cubic feet per day. This expansion allows us to continue to take
advantage of the prolific East Texas natural gas production base. As in previous years, many of
our organic growth projects were not completed until late in the year, so we expect to benefit
from a full year’s operations of these projects in 2008.
In closing, I am pleased with our partnership’s growth and performance over the past year.
Despite some challenges that have been out of our control, our diversified business model has
performed well. We expect this trend to continue. To that end, we recently announced a $100
million organic growth plan for 2008 as evidence of our confidence in our businesses and the
underlying fundamentals. Equally important, this investment represents the confidence in and
commitment to our employees. Without their hard work and dedication, it is safe to say that we
would not be discussing our outstanding growth over the first five years of our partnership.
With their continued help, we will strive to make the next five even better.
Yours truly,
Ruben S. Martin
President and Chief Executive Officer
F O R M 1 0 - K
TABLE OF CONTENTS
Page
PART I(cid:2)
Business .................................................................................................................................................. 1(cid:2)
Item 1.(cid:2)
Item 1A.(cid:2) Risk Factors ......................................................................................................................................... 25(cid:2)
Item 1B.(cid:2) Unresolved Staff Comments ................................................................................................................ 42(cid:2)
Properties .............................................................................................................................................. 42(cid:2)
Item 2.
Legal Proceedings ................................................................................................................................ 42(cid:2)
Item 3.
Submission of Matters to a Vote of Security Holders .......................................................................... 43(cid:2)
Item 4.
PART II(cid:2)
Item 5. Market for Our Common Equity, Related Unitholder Matters
and Issuer Purchases of Equity Securities ............................................................................................ 43(cid:2)
Selected Financial Data ........................................................................................................................ 45(cid:2)
Item 6.(cid:2)
Item 7.(cid:2)
Management’s Discussion and Analysis of Financial Condition and Results of Operations ............... 46(cid:2)
Item 7A.(cid:2) Quantitative and Qualitative Disclosures about Market Risk .............................................................. 67(cid:2)
Financial Statements and Supplementary Data .................................................................................... 69(cid:2)
Item 8.(cid:2)
Item 9.(cid:2)
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ............. 105(cid:2)
Item 9A.(cid:2) Controls and Procedures .....................................................................................................................105(cid:2)
Item 9B.(cid:2) Other Information ...............................................................................................................................105(cid:2)
PART III(cid:2)
Item 10.(cid:2) Directors and Executive Officers of the Registrant ............................................................................ 106(cid:2)
Executive Compensation .................................................................................................................... 110(cid:2)
Item 11.(cid:2)
Item 12.(cid:2)
Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters ........................................................................................... 116(cid:2)
Item 13. Certain Relationships and Related Transactions ................................................................................ 118(cid:2)
Item 14. Principal Accounting Fees and Services ............................................................................................. 126(cid:2)
PART IV(cid:2)
Item 15. Exhibits and Financial Statement Schedules ...................................................................................... 127(cid:2)
i
and 2005, 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 6%, 4% and 5% of our total revenues for the years ended
December 31, 2007, 2006 and 2005, respectively. In connection with the closing of the Tesoro Marine asset acquisition
in 2003, 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
- 20 -
Solid Waste
We generate both hazardous and nonhazardous solid wastes which are subject to requirements of the federal
Resource Conservation and Recovery Act, as amended (“RCRA”) and comparable state statutes. From time to time, the
U.S. Environmental Protection Agency (“EPA”) has considered making changes in nonhazardous waste standards that
would result in stricter disposal requirements for these wastes. Furthermore, it is possible some wastes generated by us that
are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes
being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an
increase in our capital expenditures or operating expenses.
We currently own or lease, and have in the past owned or leased, properties that have been used for the
manufacturing, processing, transportation and storage of petroleum products and by-products. Solid waste disposal
practices within oil and gas related industries have improved over the years with the passage and implementation of
various environmental laws and regulations. Nevertheless, a possibility exists that hydrocarbons and other solid wastes
may have been disposed of on or under various properties owned or leased by us during the operating history of those
facilities. In addition, a number of these properties have been operated by third parties over whom we had no control as to
such entities’ handling of hydrocarbons, hydrocarbon by-products or other wastes and the manner in which such
substances may have been disposed of or released. State and federal laws and regulations applicable to oil and natural gas
wastes and properties have gradually become more strict and, under such laws and regulations, we could be required to
remove or remediate previously disposed wastes or property contamination, including groundwater contamination, even
under circumstances where such contamination resulted from past operations of third parties.
Clean Air Act
Our operations are subject to the federal Clean Air Act, as amended, and comparable state statutes. Amendments
to the Clean Air Act adopted in 1990 contain provisions that may result in the imposition of increasingly stringent pollution
control requirements with respect to air emissions from the operations of our terminal facilities, processing and storage
facilities and fertilizer and related products manufacturing and processing facilities. Such air pollution control requirements
may include specific equipment or technologies to control emissions, permits with emissions and operational limitations,
pre-approval of new or modified projects or facilities producing air emissions, and similar measures. For example, the
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.
Global Warming and Climate Change. Recent scientific studies have suggested that emissions of
certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be
contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively
considering climate change-related legislation to restrict greenhouse gas emissions. At least 17 states have already
taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of
greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the
U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA must consider whether it is
required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not
adopt new legislation specifically addressing emissions of greenhouse gases. The Court's holding in Massachusetts that
greenhouse gases fall under the federal Clean Air Act's definition of "air pollutant" may also result in future regulation
of greenhouse gas emissions from stationary sources under various Clean Air Act programs. New legislation or
regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could adversely
affect our operations and demand for our services.
Clean Water Act
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state
laws impose restrictions and controls on the discharge of pollutants into federal and state waters. Regulations promulgated
- 22 -
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:
(cid:120) 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.
(cid:120) 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.
(cid:120) Martin Resource Management may engage in limited competition with us.
(cid:120) 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.
(cid:120) 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.
(cid:120) Our general partner determines which costs incurred by Martin Resource Management are reimbursable
by us.
(cid:120) 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.
(cid:120) Our general partner controls the enforcement of obligations owed to us by Martin Resource Management.
(cid:120) Our general partner decides whether to retain separate counsel, accountants or others to perform services
for us.
(cid:120)
(cid:120)
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.
(cid:120) 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.
- 40 -
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 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
- 41 -
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, Nebraska, Texas and Utah.
We may do business or own property in other states or foreign countries in the future. It is the unitholder’s responsibility to
file all federal, state, local and foreign tax returns. Our counsel has not rendered an opinion on the state, local or foreign tax
consequences of an investment in our common units.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
A description of our properties is contained in Item 1. Business.
We believe we have satisfactory title to our assets. Some of the easements, rights-of-way, permits, licenses or
similar documents relating to the use of the properties that have been transferred to us in connection with our initial public
offering and the assets we acquired in our acquisitions, required the consent of third parties, which in some cases is a
governmental entity. We believe we have obtained sufficient third-party consents, permits and authorizations for the
transfer of assets necessary for us to operate our business in all material respects. With respect to any third-party consents,
permits or authorizations that have not been obtained, we believe the failure to obtain these consents, permits or
authorizations will not have a material adverse effect on the operation of our business.
Title to our property may be subject to encumbrances, including liens in favor of our secured lender. We believe
none of these encumbrances materially detract from the value of our properties or our interest in these properties, or
materially interfere with their use in the operation of our business.
Item 3. Legal Proceedings
From time to time, we are subject to certain legal proceedings claims and disputes that arise in the ordinary course
of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in
the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity.
In addition to the foregoing, as a result of a routine inspection by the U.S. Coast Guard of our tug Martin Explorer
at the Freeport Sulfur Dock Terminal in Tampa, Florida, we have been informed that an investigation has been commenced
concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq., and the MARPOL
Protocol 73/78. In connection with this matter, two of our employees were served with grand jury subpoenas during the
fourth quarter of 2007. We are cooperating with the investigation and, as of the date of this report, no formal charges, fines
and/or penalties have been asserted against us.
- 42 -
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 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 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 2003-2004 annual periods when compared to our financial reporting for our current
2007 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 and 2003 (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.
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, 2004
(In Thousands)
Terminalling
and Storage
NGL
Marine
Sulfur
Total
$
6,775
$
197,859
$
— $
25,207 $ 229,841
6,775
6,699
8,494
2,194
399
197,859
—
25,342
229,976
928
24,796
—
32,423
1,185
1,457
1,200
24,796
—
34,475
175
175
4,599
4,424
8,385
6,198
- 50 -
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
(In Thousands)
Terminalling
and Storage
NGL
Marine
Sulfur
Total
$
107
$ 128,055 $
— $ 22,605 $ 150,767
107
128,055
—
22,730
150,892
1,413
2,141
1,180
452
1,052
18,135
1,314
18,135
—
—
1,362
1,100
305
305
3,254
3,129
20,600
21,590
6,101
4,986
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, the reimbursement amount that we are required
to pay to Martin Resource Management with respect to indirect general and administrative and corporate overhead
expenses was capped at $2.0 million. This cap expired on November 1, 2007. Effective January 1, 2008, the Conflicts
Committee of our general partner approved a reimbursement amount for indirect expenses of $2.7 million for the year
ending December 31, 2008 which is not expected to cover all of the indirect general and administrative and corporate
overhead expenses attributable to the services provided to us. We are required to reimburse Martin Resource Management
for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business.
Martin Resource Management also licenses certain of its trademarks and trade names to us under this omnibus agreement.
We are both an important supplier to and customer of Martin Resource Management. Among other things, we
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 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 services 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.
- 51 -
Results of Operations
The results of operations for the twelve months ended December 31, 2007, 2006 and 2005 have been derived
from our consolidated and condensed financial statements.
We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of
products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization
expense from revenues. The following table sets forth our operating revenues and operating income by segment for the
twelve months ended December 31, 2007, 2006 and 2005.
Operating
Revenues
Revenues
Intersegment
Eliminations
Operating
Revenues
after
Eliminations
Operating
Income
(loss)
(In thousands)
Operating
Income
Intersegment
Eliminations
Operating
Income (loss)
after
Eliminations
Year ended December 31, 2007:
Terminalling and storage .................
Natural gas services .........................
Marine transportation ......................
Sulfur services .................................
Indirect selling, general and administrative
$ 59,790
515,992
63,533
131,602
—
$ (865)
—
(3,954)
(276)
—
$ 58,925
515,992
59,579
131,326
—
$ 10,745
4,159
7,949
9,222
(3,199)
$ (472)
333
(3,679)
3,818
—
$ 10,273
4,492
4,270
13,040
(3,199)
Total ............................................
$ 770,917
$ (5,095)
$ 765,822
$ 28,876
$ —
$ 28,876
Year ended December 31, 2006:
Terminalling and storage .................
Natural gas services .........................
Marine transportation ......................
Sulfur services .................................
Indirect selling, general and administrative
$ 36,606
389,735
50,174
102,646
—
$ (389)
—
(2,339)
(49)
—
$ 36,217
389,735
47,835
102,597
—
$ 12,646
4,239
8,258
4,719
(3,253)
$ (142)
—
(1,847)
1,989
—
$ 12,504
4,239
6,411
6,708
(3,253)
Total ............................................
$ 579,161
$ (2,777)
$ 576,384
$ 26,609
$ —
$ 26,609
Year ended December 31, 2005
Terminalling and storage .................
Natural gas services .........................
Marine transportation ......................
Sulfur services .................................
Indirect selling, general and administrative
$ 32,962
301,676
37,724
68,418
—
$ (64)
—
(2,273)
—
—
$ 32,898
301,676
35,451
68,418
—
$ 9,127
6,003
4,657
2,636
(3,463)
$ 187
—
(2,273)
2,086
—
$ 9,314
6,003
2,384
4,722
(3,463)
Total ............................................
$ 440,780
$ (2,337)
$ 438,443
$ 18,960
$ —
$ 18,960
Our results of operations are discussed on a comparative basis below. There are certain items of income and
expense which we do not allocate on a segment basis. These items, including equity in earnings (loss) of
unconsolidated entities, interest expense, and indirect selling, general and administrative expenses, are discussed after
the comparative discussion of our results within each segment.
Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006
Our total revenues before eliminations were $770.9 million for the year ended December 31, 2007 compared to
$579.2 million for the year ended December 31, 2006, an increase of $191.7 million, or 33%. Our operating income before
eliminations was $28.9 million for the year ended December 31, 2007 compared to $26.6 million for the year ended
December 31, 2006, an increase of $2.3 million, or 9%.
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.
- 52 -
Revenues:
Services ...............................................................................................
Products ..............................................................................................
Total Revenues ................................................................................
Cost of products sold ..............................................................................
Operating expenses .................................................................................
Selling, general and administrative expenses ..........................................
Depreciation and amortization ................................................................
Other operating income (loss) .................................................................
Operating income ................................................................................
Years Ended December 31,
2007
2006
(In thousands)
$ 29,400
30,390
59,790
26,298
16,238
139
6,358
10,757
(12)
$ 10,745
$ 24,182
12,424
36,606
9,999
12,276
112
4,700
9,519
3,127
$ 12,646
Revenues. Our terminalling and storage revenues increased $23.2 million, or 63%, for the year ended December
31, 2007 compared to the year ended December 31, 2006. Service revenue accounted for $5.2 million of this increase.
The service revenue increase was primarily a result of recent acquisitions and capital projects being placed into service
during the end of 2006 and throughout 2007. Product revenue increased $18.0 million primarily due to the Mega Lube
acquisition, and, exclusive of Mega Lube, a 29% increase in product cost that was passed through to our customers. There
was also a 22% increase in sales volumes.
Cost of products sold. Our cost of products sold increased $16.3 million, or 163% for the year ended December
31, 2007 compared to the year ended December 31, 2006. This increase was primarily a result of the Mega Lube
acquisition, an increase in product cost and an increase in sales volumes.
Operating expenses. Operating expenses increased $4.0 million, or 32%, for the year ended December 31,
2007 compared to the year ended December 31, 2006. The increase was result of our recent acquisitions and capital
projects placed into service during the end of 2006 and throughout 2007. The increase was also a result of increased
operating activities and an increase in costs of those activities at our terminals.
Selling, general and administrative expenses. Selling, general & administrative expenses were approximately
the same for the year ended December 31, 2007 compared to the year ended December 31, 2006.
Depreciation and amortization. Depreciation and amortization increased $1.7 million, or 35%, for the year
ended December 31, 2007 compared to the year ended December 31, 2006. This increase was primarily a result of our
recent acquisitions and capital expenditures.
Other operating income (loss). Other operating income for the year ended December 31, 2007 consisted solely
of a loss related to the sale of equipment. 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 decreased $1.9 million, or 15%, for the year ended
December 31, 2007 compared to the year ended December 31, 2006.
Natural Gas Services Segment
The following table summarizes our results of operations in our natural gas services segment.
Years Ended December 31,
2007
2006
(In thousands)
Revenues:
NGLs ..................................................................................................
Natural gas .........................................................................................
Non-cash mark to market adjustment of commodity derivatives .......
Gain (loss) on cash settlements of commodity derivatives ................
Other operating fees ..........................................................................
Total revenues ..............................................................................
$481,018
35,983
(3,104)
(611)
2,706
515,992
$372,997
13,773
221
894
1,850
389,735
- 53 -
Depreciation and amortization. Depreciation and amortization increased $1.6 million, or 95%, for the year
ended December 31, 2007 compared to the same period of 2006. This increase was primarily a result of the Woodlawn
acquisition
In summary, our natural gas services operating income decreased $0.1 million, or 2%, for the year ended
December 31, 2007 compared to the year ended December 31, 2006.
Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $10.9 million
and $8.5 million for the year ended December 31, 2007 and 2006, respectively, an increase of 28%. This increase is
primarily a result of completing the expansions to the Waskom plant and the Waskom fractionator in the first half of
2007, resulting in our inlet volumes and fractionation volumes increasing 25% and 14%, respectively.
Marine Transportation Segment
The following table summarizes our results of operations in our marine transportation segment.
Years Ended December 31,
2007
2006
(In thousands)
Revenues ............................................................................................ $ 63,533
46,946
Operating expenses ............................................................................
Selling, general and administrative expenses .....................................
535
8,819
Depreciation and amortization ...........................................................
7,233
Other operating income ......................................................................
716
Operating income ........................................................................... $ 7,949
$ 50,174
34,946
587
6,609
8,032
226
$ 8,258
Revenues. Our marine transportation revenues increased $13.4 million, or 27%, for the year ended December 31,
2007 compared to the year ended December 31, 2006. Our inland marine assets generated an additional $12.4 million in
revenue 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. Our offshore revenues increased
$1.0 million primarily from the acquisition of an integrated tug barge unit in the fourth quarter of 2006.
Operating expenses. Operating expenses increased $12.0 million, or 34%, for the year ended December 31, 2007
compared to the year ended December 31, 2006. We experienced increases in salaries and wages, repair and maintenance
expenses, increased shipyard costs and outside towing expenses.
Selling, general and administrative expenses. Selling, general & administrative expenses were approximately the
same for the year ended December 31, 2007 compared to the year ended December 31, 2006.
Depreciation and amortization. Depreciation and amortization increased $2.2 million, or 33%, for the year ended
December 31, 2007 compared to the year ended December 31, 2006. This increase was the result of capital expenditures
made in the last 12 months.
Other operating income. Other operating income increased $0.5 million, or 217%, for the year ended December
31, 2007 compared to the year ended December 31, 2006. This increase consisted of gains on the sale of property and
equipment.
In summary, our marine transportation operating income decreased $0.3 million, or 4%, for the year ended
December 31, 2007 compared to the year ended December 31, 2006.
Sulfur Services Segment
The following table summarizes our results of operations in our sulfur services segment.
- 55 -
Years Ended December 31,
2007
2006
(In thousands)
Revenues ................................................................................................
Cost of products sold..............................................................................
Operating expenses ................................................................................
Selling, general and administrative expenses .........................................
Depreciation and amortization ...............................................................
Operating income ............................................................................
$131,602
97,747
17,033
2,587
5,013
$ 9,222
$102,646
76,372
14,283
2,651
4,621
$ 4,719
Sulfur Services Volumes (long tons) ....................................................
1,420.9
1,025.2
Revenues. Our sulfur services revenues increased $29.0 million, or 28%, for the year ended December 31,
2007 compared to the year ended December 31, 2006. This increase was primarily a result of a 39% increase in sales
volume. The sales volume increase was due to a new molten sulfur sales contract negotiated in 2007 and increased
demand for our sulfur-based products, driven by higher agricultural commodity prices.
Cost of products sold. Our cost of products sold increased $21.4 million, or 28%, for the year ended December
31, 2007 compared to the year ended December 31, 2006. This percentage increase was the same as our percentage
increase in sales, as our margin per ton was approximately the same for both years.
Operating expenses. Our operating expenses increased $2.8 million, or 19%, for the year ended December 31,
2007 compared to the year ended December 31, 2006. This increase was a result of increased marine transportation
costs relating to increased crew wages, outside towing expense incurred for leased vessels due to down time of vessels
owned by the sulfur services segment and repairs and maintenance on vessels owned by the sulfur services segment to
bring them up to higher quality standards adopted by our marine transportation group.
Selling, general, and administrative expenses. Our selling, general, and administrative expenses decreased
$0.1 million, or 2%, for the year ended December 31, 2007 compared to the year ended December 31, 2006.
Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 8%, for the year
ended December 31, 2007 compared to the year ended December 31, 2006. This is attributable to our sulfuric acid
facility coming online in the fourth quarter of 2007.
In summary, our sulfur services operating income increased $4.5 million, or 95%, for the year ended December
31, 2007 compared to the year ended December 31, 2006
Statement of Operations Items as a Percentage of Revenues
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, 2007 and December 31, 2006. 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,
2007
2006
(In thousands)
Revenues .................................................................................................
Cost of products sold ..............................................................................
Operating expenses .................................................................................
Selling, general and administrative expenses ..........................................
Depreciation and amortization ................................................................
100%
81%
11%
2%
3%
100%
80%
11%
2%
3%
Equity in Earnings of Unconsolidated Entities
For the years ended December 31, 2007 and 2006, equity in earnings of unconsolidated entities relates to our
unconsolidated interest in BCP subsequent to its acquisition on June 30, 2006 and the unconsolidated interests in Waskom,
Matagorda and PIPE.
- 56 -
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. Effective
December 28, 2007, we increased our revolving credit facility $75.0 million resulting in a committed $195.0 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, 2007, we had $95.0 million outstanding under the revolving credit facility and $130.0
million outstanding under the term loan 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 $170.6 million to a
high of $239.4 million. As of December 31, 2007, we had $99.9 million available for working capital, internal expansion
and acquisition activities under the Partnership’s credit facility.
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 1.75%.
Effective January 1, 2008, the applicable margin for existing borrowings will increase to 2.00%. As a result of our
leverage ratio test as of December 31, 2007, effective April 1, 2008, the applicable margin for existing borrowings will
remain at 2.00%. We incur a commitment fee on the unused portions of the credit facility.
Effective September 2007, we entered into an interest rate swap that swaps $25.0 million of floating rate to fixed
rate. The fixed rate cost is 4.605% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in
September, 2010 is accounted for using hedge accounting.
Effective November 2006, we entered into an interest rate swap that swaps $40.0 million of floating rate to fixed
rate. The fixed rate cost is 4.82% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in
December, 2009 is accounted for using hedge accounting.
Effective November 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 using hedge accounting.
Effective March 2006, we entered into an interest rate swap that swaps $75.0 million of floating rate to fixed rate.
The fixed rate cost is 5.25% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in
November, 2010 is accounted for using hedge accounting.
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.
- 65 -
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 year ended December 31, 2007, 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, 2007.
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.
We use derivatives to manage the risk of commodity price fluctuations. Our counterparties to the commodity
derivative contracts include Shell Energy North America (US), L.P., 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 2010 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, ethane, iso butane,
normal butane and natural gasoline.
Based on estimated volumes, as of December 31, 2007, Prism Gas had hedged approximately 77%, 24%, and
17% of its commodity risk by volume for 2008, 2009, and 2010, respectively. As of December 31, 2007, commodity
derivative assets of $235 were included in other current assets on the balance sheet. Commodity derivative liabilities of
$3,261 were included in current liabilities and $2,140 were included in long-term liabilities on the balance sheet. We
anticipate 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 our existing hedging arrangements. In addition, we will enter into derivative arrangements that include the specific
NGL products as well as natural gas and crude oil.
Hedging Arrangements in Place
As of December 31, 2007
Commodity Hedged
Condensate & Natural Gasoline
Year
2008
2008 Natural Gas
2008 Ethane
2008 Natural Gasoline
2008 Iso Butane
2008 Normal Butane
2008 Natural Gasoline
2008 Natural Gasoline
2009 Condensate & Natural Gasoline
2009 Natural Gasoline
2009
Condensate
Type of Derivative
Crude Oil Swap ($66.20)
Volume
5,000 BBL/Month
30,000 MMBTU/Month Natural Gas Swap ($8.12)
5,000 BBL/Month
3,000 BBL/Month
1,000 BBL/Month
2,000 BBL/Month
3,000 BBL/Month
3,000 BBL/Month
3,000 BBL/Month
3,000 BBL/Month
1,000 BBL/Month
Basis Reference
NYMEX
Houston Ship Channel
Mt. Belvieu
Ethane Swap ($27.30)
NYMEX
Crude Oil Swap ($70.75)
Mt. Belvieu (Non-TET)
Iso Butane Swap ($75.90)
Mt. Belvieu (Non-TET)
Normal Butane Swap ($75.06)
Natural Gasoline Swap ($87.31)
Mt. Belvieu (Non-TET)
Natural Gasoline Swap ($85.10) Mt. Belvieu (Non-TET)
Crude Oil Swap ($69.08)
Crude Oil Swap ($70.90)
Crude Oil Swap ($70.45)
NYMEX
NYMEX
NYMEX
- 67 -
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 ........................................................................................ 70
Report of Independent Registered Public Accounting Firm ........................................................................................ 71
Consolidated Balance Sheets as of December 31, 2007 and 2006 .............................................................................. 72
Consolidated Statements of Operations for the years ended December 31, 2007, 2006 and 2005 .............................. 73
Consolidated Statements of Changes in Capital for the years ended December 31, 2007, 2006 and 2005 ................. 74
Consolidated Statements of Comprehensive Income for the years ended December 31, 2007 and 2006 ................... 75
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005 ............................ 76
Notes to the Consolidated Financial Statements ......................................................................................................... 77
- 69 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Marine transportation ................................................................
23,729
15,319
11,606
Product sales:
Natural gas services ............................................................
Sulfur services ....................................................................
Terminalling and storage ...................................................
Costs and expenses:
Cost of products sold:
Natural gas services ............................................................
Sulfur services ....................................................................
Terminalling and storage ....................................................
Expenses:
Operating expenses
Marine transportation .........................................................
Natural gas services ............................................................
Sulfur services ....................................................................
Terminalling and storage ....................................................
Selling, general and administrative:
Natural gas services ............................................................
Sulfur services ....................................................................
Terminalling and storage ....................................................
Indirect overhead allocation, net of reimbursement ...........
3,206
4,326
45
7,577
$ 43,122
$ 62,686
13,992
—
$ 76,678
$ 20,891
1,538
1,234
5,328
$ 28,991
927
1,770
41
1,351
$ 4,089
(14)
FINANCIAL INSTRUMENTS
1,303
24
59
1,386
$ 25,631
$ 52,030
11,913
1
$ 63,944
$ 20,051
1,560
928
3,931
$ 26,470
773
1,714
74
1,305
$ 3,866
44
229
5
278
$ 20,822
$ 15,827
9,843
31
$ 25,701
$ 15,746
1,236
295
3,485
$ 20,762
833
1,444
76
1,120
$ 3,473
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:
(cid:120) 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.
(cid:120)
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.
(15) COMMODITY CASH FLOW HEDGES
The Partnership is exposed to market risks associated with commodity prices, counterparty credit and
interest rates. In connection with the acquisition of Prism Gas, the Partnership 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
- 95 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
Based on estimated volumes, as of December 31, 2007, Prism Gas had hedged approximately 77%, 24%,
and 17% of its commodity risk by volume for 2008, 2009, and 2010, respectively. The Partnership anticipates
entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market
fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars,
futures and options, although there is no assurance that the Partnership will be able to do so or that the terms thereof
will be similar to the Partnership’s existing hedging arrangements. 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
As of December 31, 2007
Commodity Hedged
Condensate & Natural Gasoline
Year
2008
2008 Natural Gas
2008 Ethane
2008 Natural Gasoline
2008 Iso Butane
2008 Normal Butane
2008 Natural Gasoline
2008 Natural Gasoline
2009 Condensate & Natural Gasoline
2009 Natural Gasoline
2009
Condensate
2010 Condensate
2010 Natural Gasoline
Type of Derivative
Crude Oil Swap ($66.20)
Volume
5,000 BBL/Month
30,000 MMBTU/Month Natural Gas Swap ($8.12)
5,000 BBL/Month
3,000 BBL/Month
1,000 BBL/Month
2,000 BBL/Month
3,000 BBL/Month
3,000 BBL/Month
3,000 BBL/Month
3,000 BBL/Month
1,000 BBL/Month
2,000 BBL/Month
3,000 BBL/Month
Basis Reference
NYMEX
Houston Ship Channel
Mt. Belvieu
Ethane Swap ($27.30)
NYMEX
Crude Oil Swap ($70.75)
Mt. Belvieu (Non-TET)
Iso Butane Swap ($75.90)
Mt. Belvieu (Non-TET)
Normal Butane Swap ($75.06)
Natural Gasoline Swap ($87.31)
Mt. Belvieu (Non-TET)
Natural Gasoline Swap ($85.10) Mt. Belvieu (Non-TET)
Crude Oil Swap ($69.08)
Crude Oil Swap ($70.90)
Crude Oil Swap ($70.45)
Crude Oil Swap ($69.15)
Crude Oil Swap ($72.25)
NYMEX
NYMEX
NYMEX
NYMEX
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 discontinuance 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, 2007 and 2006, net gains and losses on swap hedge contracts decreased
crude revenue by $3,374 and increased crude revenue by $76, respectively. As of December 31, 2007 an unrealized
derivative fair value loss of $1,880, related to cash flow hedges of crude oil price risk, was recorded in other
comprehensive income (loss). Fair value losses of $949, $190 and $741 are expected to be reclassified into earnings
in 2008, 2009 and 2010, respectively. The actual reclassification to earnings will be based on mark-to-market prices
at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is
not reflected above.
Natural Gas
For the years ended December 31, 2007 and 2006, net gains on swap hedge contracts increased gas revenue
by $180 and $1,097, respectively.
Natural Gas Liquids
For the years ended December 31, 2007 and 2006, net losses on swap hedge contracts decreased liquids
revenue by $521 and $58, respectively. As of December 31, 2007, an unrealized derivative fair value loss of $839
- 98 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(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.
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)
INCOME TAXES
The operations of a partnership are generally not subject to income taxes, except as discussed below, because
its income is taxed directly to its partners. The net tax basis in the Partnership’s assets and liabilities is less than the
reported amounts on the financial statements by approximately $35.4 million as of December 31, 2007. Effective
January 1, 2007, the Partnership is subject to the Texas margin tax as described below. Our subsidiary, Woodlawn, is
subject to income taxes due to its corporate structure. Current income taxes related to the operations of this subsidiary
were $118 for the year ended December 31, 2007. In connection with the Woodlawn acquisition, the Partnership also
established deferred income taxes of $8,964 associated with book and tax basis differences of the acquired assets and
liabilities. The basis differences are primarily related to property, plant and equipment. A deferred tax benefit related
to these basis differences of $149 was recorded for the year ended December 31, 2007, and a deferred tax liability of
$8,815 related to the basis differences existing at December 31, 2007.
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. The final
liquidation of this corporate entity was completed on November 15, 2006. Additional federal and state income taxes of
$173 resulting from the liquidation were recorded in current year income tax expense for the year ended December 31,
2007.
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. State income taxes attributable to the Texas margin
- 100 -
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
tax of $538 were recorded in current year income tax expense for the year ended December 31, 2007. There was no
state income tax expense recorded for the year ended December 31, 2006.
In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48
(FIN 48), “Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109,
“Accounting for Income Taxes”. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting
and disclosing in the financial statements uncertain tax positions taken or expected to be taken. The Partnership
adopted FIN 48 effective January 1, 2007. There was no impact to the Partnership’s financial statements as a result
of adopting FIN 48.
The components of income tax expense (benefit) from operations recorded for the year ended December
31, 2007 are as follows:
Current:
Federal ........................................................................
State ............................................................................
Deferred:
Federal .......................................................................
Year Ended
December 31,
2007
$ 274
519
$ 793
$ (149)
$ 644
(19) 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.
In addition to the foregoing, as a result of a routine inspection by the U.S. Coast Guard of the Partnership’s
tug Martin Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, the Partnership has been informed that
an investigation has been commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33
USC 1901, et. seq., and the MARPOL Protocol 73/78. In connection with this matter, two of the Partnership’s
employees were served with grand jury subpoenas during the fourth quarter of 2007. The Partnership is cooperating
with the investigation and, as of the date of this report, no formal charges, fines and/or penalties have been asserted
against the Partnership.
(20)
BUSINESS SEGMENTS
The Partnership has four reportable segments: terminalling and storage, natural gas services, marine
transportation, and sulfur services. The Partnership’s reportable segments are strategic business units that offer
different products and services. The operating income of these segments is reviewed by the chief operating decision
maker to assess performance and make business decisions.
The accounting policies of the operating segments are the same as those described in Note 2 of the notes to
consolidated financial statements. The Partnership evaluates the performance of its reportable segments based on
operating income. There is no allocation of administrative expenses or interest expense.
Operating
Revenues
Intersegment
Eliminations
Operating
Revenues
After
Eliminations
Depreciation
and
Amortization
Operating
Income
(Loss) after
Eliminations
Capital
Expenditures
Year ended December 31, 2007:
Terminalling and storage ...............
Natural gas services .......................
$ 59,790
515,992
$ (865)
—
$ 58,925
515,992
$ 6,358
3,252
$ 10,273
4,492
$ 26,023
4,090
- 101 -
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, 2008
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, 2008.
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
- 128 -
Financial Statement Schedule
Pursuant to Item 15(a)(2
Waskom Gas
Processing Company
Financial Statements as of and for the Years Ended
December 31, 2007 and 2006, (with Independent
Auditors’ Report Thereon)
(cid:817)(cid:3)(cid:883)(cid:885)(cid:884)(cid:3)(cid:817)(cid:3)
INDEPENDENT AUDITORS’ REPORT
To the Partners of
Waskom Gas Processing Company:
We have audited the accompanying balance sheets of Waskom Gas Processing Company (the “Partnership”) as of
December 31, 2007 and 2006 and the related statements of income, partners’ capital, and cash flows for the years then
ended. 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, the financial statements referred to above present fairly, in all material respects, the financial position of
the Partnership as of December 31, 2007 and 2006, and the results of its operations and its cash flows for the years then
ended, in conformity with U.S. generally accepted accounting principles.
March 5, 2008
(cid:817)(cid:3)(cid:883)(cid:885)(cid:885)(cid:3)(cid:817)(cid:3)
WASKOM GAS PROCESSING COMPANY
BALANCE SHEETS
AS OF DECEMBER 31, 2007 and 2006
2007
2006
Current Assets:
Assets
Cash .............................................................................................................
Accounts receivable.....................................................................................
Accounts receivable - partners ....................................................................
Inventories ...................................................................................................
$ 265,786
613,648
9,775,681
433,273
$ 324,979
326,753
11,227,687
436,419
Total current assets ...................................................................................
11,088,388
12,315,838
Property and Equipment:
Gas plant asset and gas gathering equipment ..............................................
Other fixed assets ........................................................................................
Accumulated depreciation and amortization ...............................................
Property and equipment, net .....................................................................
67,931,309
584,747
(12,832,563)
55,683,493
51,331,046
564,736
(10,952,030)
40,943,752
$ 66,771,881
$ 53,259,590
Liabilities and Partners’ Capital
Current Liabilities:
Accounts payable and accrued liabilities .....................................................
Accounts payable–partners ..........................................................................
Total current liabilities .............................................................................
$ 6,939,543
2,485,286
9,424,829
$ 5,916,140
1,706,545
7,622,685
Long-Term Liabilities-Asset retirement obligation ............................................
197,740
186,989
Partners’ capital ..................................................................................................
Commitments and contingencies
57,149,312
45,449,916
$ 66,771,881
$ 53,259,590
See accompanying notes to financial statements.
(cid:817)(cid:3)(cid:883)(cid:885)(cid:886)(cid:3)(cid:817)(cid:3)
WASKOM GAS PROCESSING COMPANY
STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006
2007
2006
Operating Revenues:
Natural gas processing and other revenues ................................
Natural gas liquid sales ..............................................................
Gain/(loss) on sale of assets ......................................................
Total operating revenues .....................................................
$ 25,462,143
56,494,167
(159,724)
81,796,586
$ 19,715,849
45,884,172
500
65,600,521
Operating Costs and Expenses:
Cost of sales – natural gas liquids .............................................
Operating costs ..........................................................................
Depreciation and amortization ...................................................
Total operating costs and expenses ....................................
53,014,173
4,595,878
1,925,840
59,535,891
42,505,653
4,355,646
1,493,499
48,354,798
Operating income before taxes ...........................................
22,260,695
17,245,723
Income tax expense ..........................................................................
241,864
—
Net income ........................................................................................
$ 22,018,831
$ 17,245,723
See accompanying notes to financial statements.
(cid:817)(cid:3)(cid:883)(cid:885)(cid:887)(cid:3)(cid:817)(cid:3)
WASKOM GAS PROCESSING COMPANY
STATEMENTS OF PARTNERS’ CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 2007 and 2006
Total
Partners’
Capital
Balance – December 31, 2005 ...................................................................................
$ 22,649,871
Cash contributions for capital expenditures ....................................................
19,980,733
Cash contributions for working capital ...........................................................
Cash distributions ..........................................................................................
2,494,939
(300,000)
Distributions in-kind .......................................................................................
(16,621,349)
Net income ......................................................................................................
17,245,723
Balance – December 31, 2006 ...................................................................................
Cash contributions for capital expenditures ....................................................
Cash distributions in excess of working capital ..............................................
Cash distributions ...........................................................................................
45,449,916
17,733,619
(4,128,057)
(5,250,000)
Distributions in-kind .......................................................................................
(18,674,997)
Net income ......................................................................................................
22,018,831
Balance – December 31, 2007 ...................................................................................
$ 57,149,312
See accompanying notes to financial statements.
(cid:817)(cid:3)(cid:883)(cid:885)(cid:888)(cid:3)(cid:817)(cid:3)
WASKOM GAS PROCESSING COMPANY
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006
Cash flows from operating activities:
Net income
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
2007
2006
$ 22,018,831
$ 17,245,723
Depreciation and amortization ..........................................................................
Distributions in-kind to partners ........................................................................
Loss/(Gain) on sale of assets .............................................................................
Changes in operating assets and liabilities:
1,925,840
(18,674,997)
159,724
1,493,499
(16,621,349)
(500)
Accounts receivable ...................................................................................
Accounts receivable – partners ..................................................................
Inventory ....................................................................................................
Accounts payable and accrued liabilities ...................................................
Accounts payable – partners ......................................................................
(286,895)
1,452,006
3,146
1,023,403
778,741
(391,548)
(5,560,870)
(412,779)
805,279
1,275,364
Net cash provided by (used in) operating activities .............................
8,399,799
(2,167,181)
Cash flows from investing activities:
Additions to gas plant and gathering system assets .................................................
Additions to other fixed assets .................................................................................
Proceeds from sale of assets ....................................................................................
(16,809,743)
(20,011)
15,200
(20,834,411)
—
500
Net cash used in investing activities ....................................................
(16,814,554)
(20,833,911)
Cash flows from financing activities:
Contributions from partners .....................................................................................
Distributions to partners ...........................................................................................
17,733,619
(9,378,057)
22,475,672
(300,000)
Net cash provided by financing activities ............................................
8,355,562
22,175,672
Net decrease in cash
....................................................................................................
(59,193)
(825,420)
Cash at beginning of period ............................................................................................
324,979
1,150,399
Cash at end of period ...................................................................................................... $ 265,786
$ 324,979
Supplement Cash Flow Disclosures:
Interest Paid .................................................................................................................... $ —
$ —
Taxes Paid ....................................................................................................................... $ —
$ —
See accompanying notes to financial statements.
(cid:817)(cid:3)(cid:883)(cid:885)(cid:889)(cid:3)(cid:817)(cid:3)
Waskom Gas Processing Company
NOTES TO FINANCIAL STATEMENTS
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006
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, 2007 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 Plant is a 250 MMcfd cryogenic turboexpander gas plant located in Harrison County, Texas. The Plant has full
NGL fractionation, treating and stabilization capabilities. Fractionation is a process used to separate the mixture of
NGL’s into individual products for sale. Expansions to the processing plant were completed in March and June of
2007 increasing the capacity from 150 MMcfd to 250 MMcfd. In January 2007 the Waskom fractionator was
expanded to a capacity of 12,500 barrels per day from 9,500 barrels per day. In addition, an increase in the
processing capacity of the plant to 265 MMcfd is expected to be completed by the end of the second quarter 2008.
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 represent approximately 72% of the
229 MMcfd of natural gas supplied for the year ended December 31, 2007 and 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 NGLs as payment
for services. There is currently one contract 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 NGLs 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 was $1,915,089 in 2007 and $1,483,332 in 2006.
Repairs and maintenance are charged to operations as incurred. Renewals and betterments are capitalized.
Inventories—Substantially all inventory at December 31, 2007 and 2006 represents pipe used for future projects.
Such pipe was valued at acquisition cost.
(cid:817)(cid:3)(cid:883)(cid:885)(cid:890)(cid:3)(cid:817)(cid:3)
Waskom Gas Processing Company
NOTES TO FINANCIAL STATEMENTS
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006
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 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 asset retirement obligations include
purging, plugging and remediation costs. Accretion expense for 2007 and 2006 was $10,751 and $10,167,
respectively. Financial Accounting Standards Board issued Interpretation No. 47, “Accounting for Conditional
Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143 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, 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.
Federal Income Taxes—The Partnership is a Texas General Partnership and as such has no liability for Federal
Income Taxes. Each partner is responsible for its share of federal income tax.
On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state
business tax by replacing the taxable capital and earned surplus components of the 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. Texas margin tax expense for 2007 was $241,864. There
was no income tax expense recorded for the year ended December 31, 2006.
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.
(cid:817)(cid:3)(cid:883)(cid:885)(cid:891)(cid:3)(cid:817)(cid:3)
Waskom Gas Processing Company
NOTES TO FINANCIAL STATEMENTS
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006
Recently Issued Accounting Pronouncements— In September 2006, the FASB issued SFAS No. 157 (“SFAS
157”), “Fair Value Measurements,” which defines fair value, establishes guidelines for measuring fair value and
expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value
measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements.
SFAS 157 is effective for fiscal years beginning after November 15, 2007. However, on December 14, 2007, the
FASB issued proposed FSP FAS 157-b which would delay the effective date of SFAS 157 for all nonfinancial assets
and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a
recurring basis (at least annually). This proposed FSP partially defers the effective date of Statement 157 to fiscal
years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of
this FSP. Effective for fiscal 2008, we will adopt SFAS 157 except as it applies to those nonfinancial assets and
nonfinancial liabilities as noted in proposed FSP FAS 157-b. The partial adoption of SFAS 157 will not have a
material impact on our consolidated financial position, results of operations or cash flows.
In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48)
“Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No.109 “Accounting
for Income Taxes”. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and
disclosing in the financial statements uncertain tax positions taken or expected to be taken. The Partnership adopted
FIN 48 effective January 1, 2007. There was no impact to the Partnership’s financial statements as a result of
adopting FIN 48.
3. RELATED-PARTY TRANSACTIONS
During 2007 and 2006, the Partnership engaged in certain material transactions with the partners. The Partnership
believes that the terms of these transactions were comparable to those that could have been negotiated with unrelated
third parties. As of December 31, 2007 and 2006, the Partnership had receivables of approximately $9.8 million and
$11.2 million, respectively, and payables of approximately $2.5 million and $1.7 million, respectively, due from and
due to the partners.
Per the Partnership agreement, cash contributions are made by the partners for capital expenditures and working
capital. Contributions for capital expenditures totaled $17,733,619 and $19,980,733 for 2007 and 2006,
respectively. Cash contributions for working capital totaled $2,494,939 in 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 cash distributions totaled $4,128,057 in 2007. Other cash distributions totaled $5,250,000 and $300,000 for
2007 and 2006, respectively.
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 $18,674,997 and $16,621,349 in 2007 and 2006, respectively, were made to the partners.
Distributions of products in-kind are valued at prevailing market prices at the time of distribution.
In some instances, the fractionated NGL’s (less any retained portions) are returned to the third party producers, but
in most cases, the third party producers enter into agreements with the partners to market their product. In such
instances, the Partnership will sell the product to the partners. Such sales amounted to $53,365,845 and $43,678,571
in 2007 and 2006, respectively, and are included as natural gas liquid 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
(cid:2)(cid:3)(cid:4)(cid:5)(cid:6)(cid:3)(cid:2)(cid:3)
Waskom Gas Processing Company
NOTES TO FINANCIAL STATEMENTS
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006
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 benefits. 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.
* * * * * *
(cid:2)(cid:3)(cid:4)(cid:5)(cid:4)(cid:3)(cid:2)(cid:3)
SUBSIDIARIES OF
MARTIN MIDSTREAM PARTNERS L.P.
Exhibit 21.1
Subsidiary
Martin Operating GP LLC
Martin Operating Partnership L.P.
Prism Gas Systems GP, L.L.C.
Prism Gas Systems I, L.P.
Jurisdiction of Organization
Delaware
Delaware
Texas
Texas
McLeod Gas Gathering and Processing Company, L.L.C.
Louisiana
Prism Gulf Coast Systems, L.L.C.
Woodlawn Pipeline Co., Inc.
Prism Liquids Pipeline LLC
Texas
Texas
Texas
(cid:2)(cid:3)(cid:4)(cid:5)(cid:7)(cid:3)(cid:2)(cid:3)
Consent of Independent Registered Public Accounting Firm
Exhibit 23.1
The Board of Directors
Martin Midstream GP LLC:
We consent to the incorporation by reference in the registration statements (No. 333-148146) on Form S-3, (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, 2008, with respect to the consolidated balance sheets of Martin Midstream Partners L.P. and
subsidiaries as of December 31, 2007 and 2006, 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,
2007, and the effectiveness of internal control over financial reporting as of December 31, 2007, which reports
appear in the December 31, 2007 annual report on Form 10-K of Martin Midstream Partners L.P.
/s/ KPMG LLP
Shreveport, Louisiana
March 5, 2008
(cid:2)(cid:3)(cid:4)(cid:5)(cid:8)(cid:3)(cid:2)(cid:3)
Independent Auditors’ Consent
Exhibit 23.2
The Board of Directors
Martin Midstream GP LLC:
We consent to the incorporation by reference in the registration statements (No. 333-148146) on Form S-3, (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, 2008, with respect to the balance sheets of Waskom Gas Processing Company as of
December 31, 2007 and 2006, and the related statements of income, partners’ capital, and cash flows for the years
then ended which report appears in the December 31, 2007 annual report on Form 10-K of Martin Midstream
Partners L.P.
/s/ KPMG LLP
Shreveport, Louisiana
March 5, 2007
(cid:817)(cid:3)(cid:883)(cid:886)(cid:886)(cid:3)(cid:817)(cid:3)
Independent Auditors’ Consent
Exhibit 23.3
The Board of Directors
Martin Midstream GP LLC:
We consent to the incorporation by reference in the registration statements (No. 333-148146) on Form S-3, (No.
333-117023) on Form S-3 and (No. 333-140152) on Form S-8 of Martin Midstream Partners L.P. of our report dated
March 5, 2008, with respect to the balance sheets of Martin Midstream GP LLC as of December 31, 2007 and 2006
which report appears as Exhibit 99.1 to the December 31, 2007 annual report on Form 10-K of Martin Midstream
Partners L.P.
/s/ KPMG LLP
Shreveport, Louisiana
March 5, 2008
(cid:817)(cid:3)(cid:883)(cid:886)(cid:887)(cid:3)(cid:817)(cid:3)
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.
I have reviewed this annual report on Form 10-K of Martin Midstream Partners L.P.;
2.
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, 2008
/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.
(cid:817)(cid:3)(cid:883)(cid:886)(cid:888)(cid:3)(cid:817)(cid:3)
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.
I have reviewed this annual report on Form 10-K of Martin Midstream Partners L.P.;
2.
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, 2008
/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.
(cid:817)(cid:3)(cid:883)(cid:886)(cid:889)(cid:3)(cid:817)(cid:3)
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, 2007 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, 2008
*A signed original of this written statement required by Section 906 has been provided to Martin
Midstream Partners L.P. (the “Partnership”) and will be retained by the Partnership and furnished to the
Securities and Exchange Commission or its staff upon request. The foregoing certification is being
furnished to the Securities and Exchange Commission and shall not be deemed to be “filed.”
(cid:817)(cid:3)(cid:883)(cid:886)(cid:890)(cid:3)(cid:817)(cid:3)
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, 2007 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, 2008
*A signed original of this written statement required by Section 906 has been provided to Martin
Midstream Partners L.P. (the “Partnership”) and will be retained by the Partnership and furnished to the
Securities and Exchange Commission or its staff upon request. The foregoing certification is being
furnished to the Securities and Exchange Commission and shall not be deemed to be “filed.”
(cid:817)(cid:3)(cid:883)(cid:886)(cid:891)(cid:3)(cid:817)(cid:3)
Independent Auditors’ Report
Exhibit 99.1
The Board of Directors
Martin Midstream GP LLC:
We have audited the accompanying consolidated balance sheets of Martin Midstream GP LLC as
of December 31, 2007 and 2006. These balance sheets are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these balance sheets 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 balance sheet is free of material misstatement. An audit of a balance sheet
includes examining, on a test basis, evidence supporting the amounts and disclosures in that balance sheet.
An audit of a balance sheet also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall balance sheet presentation. We believe that our
audit provides a reasonable basis for our opinion.
In our opinion, the consolidated balance sheets referred to above present fairly, in all material
respects, the financial position of Martin Midstream GP LLC at December 31, 2007 and 2006, in
conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Shreveport, Louisiana
March 5, 2008
(cid:817)(cid:3)(cid:883)(cid:887)(cid:882)(cid:3)(cid:817)(cid:3)
MARTIN MIDSTREAM GP LLC
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
December 31,
2007
December 31,
2006
Assets
Cash ...................................................................................................................
Accounts and other receivables, less allowance for doubtful accounts of
$207 and $394 ............................................................................................
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 Members’ Equity
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 ..................................................................................................
Deferred income taxes .......................................................................................
Other long-term obligations ...............................................................................
Total liabilities ............................................................................................
Minority interests ...............................................................................................
Members’ equity ................................................................................................
Commitments and contingencies .......................................................................
$ 4,113
$ 3,303
88,039
10,912
51,798
2,325
819
158,006
441,117
(98,080)
343,037
56,712
7,076
33,019
1,330
2,049
103,489
323,967
(76,122)
247,845
37,405
75,690
9,439
$ 623,577
27,600
70,651
7,884
$ 457,469
$ 21
104,598
24,554
9,323
974
13,941
153,441
225,000
9,244
2,666
390,321
231,737
1,519
233,256
$ 74
53,450
14,737
12,612
—
3,876
84,749
174,021
—
2,626
261,396
195,354
719
196,073
$ 623,577 $ 457,469
See accompanying notes to the consolidated balance sheets.
1
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
(1) ORGANIZATION AND DESCRIPTION OF BUSINESS
Martin Midstream GP LLC (the “General Partner”) is a single member Delaware limited liability company
formed on September 21, 2002 to become the general partner of Martin Midstream Partners L.P. (the “Company”).
The General Partner owns a 2% general partner interest and incentive distribution rights in the Company. The
General Partner is a wholly owned subsidiary of Martin Resource Management Corporation (“MRMC”).
In September 2005 the FASB ratified EITF Issue 04-5, a framework for addressing when a limited
company should be consolidated by its general partner. The framework presumes that a sole general partner in a
limited company controls the limited company, and therefore should consolidate the limited company. The
presumption of control can be overcome if the limited partners have (a) the substantive ability to remove the sole
general partner or otherwise dissolve the limited company or (b) substantive participating rights. The EITF reached a
conclusion on the circumstances in which either kick-out rights or participating rights would be considered
substantive and preclude consolidation by the general partner. Based on the guidance in the EITF, the General
Partner concluded that the Company should be consolidated. As such, the accompanying balance sheets have been
consolidated to include the General Partner and the Company.
The Company is a publicly traded limited Company which provides terminalling and storage services for
petroleum products and by-products, natural gas services, marine transportation services for petroleum products and
by-products, sulfur and sulfur-based product processing, manufacturing and distribution.
The petroleum products and by-products the Company 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
Company, for the transportation and disposition of these products. In addition to these major and independent oil
and gas companies, the Company’s primary customers include independent refiners, large chemical companies,
fertilizer manufacturers and other wholesale purchasers of these products. The Company 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.
On November 10, 2005, the Company 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 Company also acquired 50% ownership interest in
Waskom Gas Processing Company (“Waskom”), the Matagorda Offshore Gathering System (“Matagorda”), and the
Panther Interstate Pipeline Energy LLC (“Panther”) each accounted for under the equity method of accounting.
(2)
SIGNIFICANT ACCOUNTING POLICIES
(a)
Principles of Presentation and Consolidation
The consolidated balance sheets include the financial position of the General Partner and the Company and
its wholly-owned subsidiaries and its equity method investees. All significant intercompany balances and
transactions have been eliminated in consolidation. As the General Partner only has a 2% interest in the Company,
the remaining 98% not owned is shown as minority interests in the consolidated balance sheets. In addition, the
Company 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 they are the primary beneficiary of such entities. If the determination is made that the Company is the
primary beneficiary, then that entity is included in the consolidated balance sheet in accordance with FIN 46(R). No
such variable interest entities exist as of December 31, 2007 and December 31, 2006.
(b)
Product Exchanges
Product exchange balances due to other companies under negotiated agreements are recorded at quoted
market product prices while balances due from other companies are recorded at the lower of cost (determined using
the first-in, first-out method) or market.
2
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
(c)
Inventories
Inventories are stated at the lower of cost or market. Cost is determined by using the first-in, first-out
method for all inventories.
(d)
Revenue Recognition
Revenue for the Company’s four operating segments is recognized as follows:
Terminalling and storage – Revenue is recognized for storage contracts based on the contracted monthly
tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through the Company’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 our NGL
customers, which occurs when the customer physically receives the product. When product is sold in storage, or by
pipeline, the Company 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 Services – Revenues are recognized when the products are delivered, which occurs when the
customer has taken title and has assumed the risks and rewards of ownership based on specific contract terms at
either the shipping or delivery point.
(e)
Equity Method Investments
The Company 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 Company’s share of accumulated earnings less capital withdrawals and
dividends. Any excess of cost over the underlying equity in net assets is recognized as goodwill. 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.
(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 net 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, Accounting for Impairment or Disposal of Long-Lived Assets. Other intangible assets primarily
3
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
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 Company’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. In connection with the amendment and expansion of the
Company’s multi-bank credit facility on December 28, 2007, it incurred debt issuance costs of $252. 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 remainder of the 60 month term of the original debt
arrangement.
Accumulated amortization of debt issuance cost amounted to $4,324 and $3,091 at December 31, 2007 and
2006, respectively. The unamortized balance of debt issuance costs, classified as other assets amounted to $3,188 and
$4,169 at December 31, 2007 and 2006, 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 Company 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. The
Company performed its annual test in the third quarters of 2007 and 2006 with no indication of impairment.
(j)
Asset Retirement Obligation
Under SFAS No. 143, Accounting for Asset Retirement Obligations (“Statement No. 143”), an Asset Retirement
Obligation (“ARO”) which consists of costs associated with legal obligations to retire tangible, long-lived assets is
recorded 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. Financial Accounting Standards Board
Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of
SFAS 143, 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 Company’s fixed assets include land, buildings, transportation equipment, storage equipment,
marine vessels and operating equipment.
The transportation equipment includes pipeline systems. The Company transports NGLs through the
pipeline system and gathering system. The Company also gathers natural gas from wells owned by producers and
delivers natural gas and NGLs on our pipeline systems, primarily in Texas and Louisiana to the fractionation facility
of our 50% owned joint venture. The Company is obligated by contractual or regulatory requirements to remove
certain facilities or perform other remediation upon retirement of our assets. However, the Company is not able to
4
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
reasonably determine the fair value of the asset retirement obligations for our trunk and gathering pipelines and our
surface facilities, since future dismantlement and removal dates are indeterminate. In order to determine a removal
date of our 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 Company is not a producer of the field
reserves, and therefore does not have access to adequate forecasts that predict the timing of expected production for
existing reserves on those fields in which the Company gathers natural gas. In the absence of such information, the
Company is not able to make a reasonable estimate of when future dismantlement and removal dates of our
gathering assets will occur. With regard to our trunk pipelines and their related surface assets, it is impossible to
predict when demand for transportation of the related products will cease. Our right-of-way agreements allow us to
maintain the right-of-way rather than remove the pipe. In addition, the Company can evaluate its trunk pipelines for
alternative uses, which can be and have been found. The Company will record such asset retirement obligations in
the period in which more information becomes available for the Company to reasonably estimate the settlement
dates of the retirement obligations.
(k)
Derivative Instruments and Hedging Activities
Derivative Instruments and Hedging Activities—SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities, established accounting and reporting standards for derivative instruments and hedging activities. It
requires that all derivatives be included on the balance sheet as an asset or liability measured at fair value and that
changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If such
hedge accounting criteria are met, the change is deferred in shareholders’ equity as a component of accumulated other
comprehensive income. The deferred items are recognized in the period the derivative contract is settled.
As of December 31, 2007 and December 31, 2006, the Company has designated a portion of its derivative
instruments as qualifying cash flow hedges.
(l)
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 Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts
receivable.
(m)
Unit Grants
The Company issued 1,000 restricted common units to each of its three independent, non-employee
directors under its long-term incentive plan in May 2007. These units vest in 25% increments beginning in January
2008 and will be fully vested in January 2011.
The Company issued 1,000 restricted common units to each of its three independent, non-employee
directors under its long-term incentive plan in January 2006. These units vest in 25% increments on the anniversary
of the grant date each year and will be fully vested in January 2010.
The Company accounts for these transactions under EITF Issue 96-18 “Accounting for Equity Instruments
That are Issued to other than Employees For Acquiring, or in Conjunction with Selling, Goods or Services.”
(n)
Incentive Distribution Rights
The General Partner holds a 2% general partner interest and certain incentive distribution rights in the
Company. 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 Company is required to distribute all of its available cash from operating surplus, as defined
in the Company 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, 2007 and 2006, the General Partner
5
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
received incentive distributions. Such distributions have been eliminated in the accompanying consolidated balance
sheet.
(o)
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 their consolidated balance sheets in conformity with
accounting principles generally accepted in the United States of America. Actual results could differ from those
estimates.
(p)
Environmental Liabilities
The Company’s policy is to accrue for losses associated with environmental remediation obligations when
such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation
obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are
adjusted as further information develops or circumstances change. Costs of future expenditures for environmental
remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from
other parties are recorded as assets when their receipt is deemed probable.
(q)
Income Taxes
The General Partner is a disregarded entity for federal income tax purposes. Its activity is included in the
consolidated federal income tax return of MRMC; however, for financial reporting purposes, current federal income
taxes are computed and recorded as if the General Partner filed a separate federal income tax return. The Company’s
subsidiary, Woodlawn Pipeline Co., Inc. (“Woodlawn”), is subject to income taxes. In connection with the Woodlawn
acquisition, a deferred tax liability of $8,964 was established associated with book and tax basis differences of the
acquired assets and liabilities. The basis differences are primarily related to property, plant and equipment.
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are
recognized for the future tax consequences attributable to differences between the financial statement carrying amounts
of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to
be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income
in the period that includes the enactment date. Deferred tax liabilities relating primarily to book and tax basis
differences of the acquired assets of Woodlawn, and the timing of recognizing Company earnings and insurance
expense totaled $9,254 ($10 of which is included in accrued liabilities) and $419 ($12 of which is included in other
accrued liabilities) at December 31, 2007 and December 31, 2006, respectively.
The operations of the Company are generally not subject to income taxes and as a result, the Company’s
income is taxed directly to its owners, except for the Texas Margin Tax as described below and the taxes associated
with Woodlawn as previously discussed.
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 Company has calculated its deferred tax assets and liabilities for Texas
based on the new margin tax. The cumulative effect of the change and subsequent changes in deferred tax assets and
liabilities are immaterial. At December 31, 2007, the Company has recorded a liability attributable to the Texas
Margin tax of $538.
In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48
(FIN 48), Accounting for Uncertainty in Income Taxes. FIN 48 is an interpretation of FASB Statement No. 109,
6
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
Accounting for Income Taxes. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and
disclosing in the financial statements uncertain tax positions taken or expected to be taken. The Company adopted
FIN 48 effective January 1, 2007. There was no impact to the Company’s financial statements as a result of adopting
FIN 48.
(2) ACQUISITIONS
(a) Asphalt Terminal.
In October 2007, the Partnership acquired the asphalt assets of Monarch Oil, Inc (“Monarch Oil”) for
$3,927 which was allocated to property, plant and equipment. The results of Monarch Oil’s operations have been
included in the consolidated financial statements beginning October 2, 2007. The assets are located in Omaha,
Nebraska. The Partnership entered into an agreement with Martin Resource Management, whereby Martin
Resource Management will operate the facilities through a terminalling service agreement based upon throughput
rates and will bear all additional expenses to operate the facility.
(b) Lubricants Terminal
In June 2007, the Partnership acquired all of the operating assets of Mega Lubricants Inc. (“Mega
Lubricants”) located in Channelview, Texas. The results of Mega Lubricant’s operations have been included in the
consolidated financial statements beginning June 13, 2007. The fair market value of the assets acquired was
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 $1,020 was recorded as
goodwill. The goodwill was a result of Mega Lubricant’s strategically located assets combined with the
Partnership’s access to capital and existing infrastructure. This will enhance the Partnership’s ability to offer
additional lubricant blending and truck loading and unloading services to customers. In accordance with FAS 142,
the goodwill will not be amortized but tested for impairment. The terminal is located on 5.6 acres of land, and
consists of 38 tanks with a storage capacity of approximately 15,000 Bbls, pump and piping infrastructure for
lubricant blending and truck loading and unloading operations, 34,000 square feet of warehouse space and an
administrative office.
The purchase price of $4,738, including two three-year non-competition agreements totaling $530 and
goodwill of $1,020, was allocated as follows:
Current assets
Property, plant and equipment, net
Goodwill
Other assets
Other liabilities
Total
$
446
3,042
1,020
530
(300)
4,738
$
In connection with the acquisition, the Partnership borrowed approximately $4,600 under its credit facility.
(c) Woodlawn Pipeline Co., Inc.
On May 2, 2007, the Partnership, through its subsidiary Prism Gas Systems I, L.P. (“Prism Gas”), acquired
100% of the outstanding stock of Woodlawn Pipeline Co., Inc. (“Woodlawn”). The results of Woodlawn’s
operations have been included in the consolidated financial statements beginning May 2, 2007. 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 $8,785 was recorded as goodwill. The goodwill was a result of
Woodlawn’s 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 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.
7
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
Woodlawn is a natural gas gathering and processing company which owns integrated gathering and
processing assets in East Texas. Woodlawn’s system consists of approximately 135 miles of natural gas gathering
pipe, approximately 36 miles of condensate transport pipe and a 30 Mcf/day processing plant. Prism Gas also
acquired a nine-mile pipeline, from a Woodlawn related party, that delivers residue gas from Woodlawn to the
Texas Eastern Transmission pipeline system.
The selling parties in this transaction were Lantern Resources, L.P., David P. Deison, and Peak Gas
Gathering L.P. The final purchase price, after final adjustments for working capital, was $32,606 and was funded by
borrowings under the Partnership’s credit facility.
The purchase price of $32,606, including four two-year non-competition agreements and other intangibles
reflected as other assets, was allocated as follows:
Current assets
Property, plant and equipment, net
Goodwill
Other assets
Current liabilities
Deferred income taxes
Other long-term obligations
Total
$
$
4,297
29,101
8,785
3,339
(3,889)
(8,964)
(63)
32,606
The identifiable intangible assets of $3,339 are subject to amortization over a weighted-average useful life
of approximately ten years. The intangible assets include four non-competition agreements totaling $40, customer
contracts associated with the gathering and processing assets of $3,002, and a transportation contract associated with
the residue gas pipeline of $297.
In connection with the acquisition, the Partnership borrowed approximately $33,000 under its credit
facility.
(d)
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 $4,679
which was allocated to property, plant and equipment. 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.
(e)
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.
(f)
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.
8
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
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).
(4)
INVENTORIES
Components of inventories at December 31, 2007 and 2006 were as follows:
Natural gas liquids ........................................................................................
Sulfur ............................................................................................................
Sulfur-based fertilizer products .....................................................................
Lubricants .....................................................................................................
Other .............................................................................................................
2007
$31,283
7,490
6,626
5,345
1,054
$51,798
2006
$17,061
4,425
7,191
2,592
1,750
$33,019
(5)
PROPERTY, PLANT AND EQUIPMENT
At December 31, 2007 and 2006, property, plant, and equipment consisted of the following:
Depreciable Lives
2007
2006
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
$ 14,515
34,585
616
38,652
147,627
172,282
1,542
31,298
$441,117
$ 12,559
26,868
531
22,343
124,323
103,929
1,450
31,964
$323,967
(6)
GOODWILL AND OTHER INTANGIBLE ASSETS
The following information relates to goodwill balances as of the periods presented:
Carrying amount of goodwill:
Terminalling and storage .................................................................
Natural gas services .........................................................................
Marine transportation .......................................................................
Sulfur services .................................................................................
December 31, December 31,
2007
2006
$ 1,020
29,010
2,026
5,349
$37,405
$ ---
20,225
2,026
5,349
$27,600
The following information relates to covenants not-to-compete as of the periods presented:
9
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
Covenants not-to-compete:
Terminalling and storage .....................................................................
Natural gas services .............................................................................
Sulfur services .....................................................................................
Less accumulated amortization ............................................................
December 31, December 31,
2007
2006
$ 1,928
640
790
3,358
1,610
$ 1,748
$ 1,561
600
790
2,951
877
$ 2,074
Intangible assets consists of the covenants not-to-compete listed above, customer contracts associated with gathering
and processing assets and a transportation contract associated with the residue gas pipeline. The covenants not-to-
compete and contracts are presented in the consolidated balance sheets as other assets, net.
(7)
RELATED PARTY TRANSACTIONS
Amounts due to and due from affiliates in the consolidated balance sheets as of December 31, 2007
(unaudited) and December 31, 2006, are primarily with MRMC and its affiliates and Waskom Gas Processing
Company (“Waskom”).
The General Partner’s balances are primarily related to (1) Company cash distributions that were paid to a
related party on behalf of the General Partner and (2) director fees that were paid by a related party on behalf of the
General Partner. The Company contributions and distributions have been eliminated in the accompanying consolidated
balance sheet.
The Company’s balances are related to transactions involving the purchase and sale of NGL products, lube oil
products, sulfur and sulfuric acid products, sulfur-based fertilizer products; land and marine transportation services;
terminalling and storage services, and other purchases of products and services representing operating expenses.
(8)
INVESTMENT IN UNCONSOLIDATED COMPANIES AND JOINT VENTURES
The Company, through its Prism Gas subsidiary, owns 50% of the ownership interests in Waskom, Matagorda
Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). Each of these
interests is accounted for under the equity method of accounting.
On June 30, 2006, the Company, through its Prism Gas subsidiary, acquired a 20% ownership interest in a
Company 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. The remaining unamortized excess investment relating to property and equipment was
$10,685 and $11,279 at December 31, 2007 and 2006, respectively. The equity-method goodwill is not amortized in
accordance with SFAS 142; however, it is analyzed for impairment annually. No impairment was recognized in
2007 or 2006.
As a partner in Waskom, the Company 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.
10
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
Activity related to these investment accounts is as follows:
Waskom
PIPE
Matagorda
BCP
Total
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
Distributions in kind .............................................................
Cash contributions ................................................................
Cash distributions .................................................................
Equity in earnings:
Equity in earnings from operations .................................
Amortization of excess investment .................................
(9,337)
6,803
(2,625)
—
—
(635)
—
—
(215)
—
107
—
(9,337)
6,910
(3,475)
11,009
(550)
514
(15)
151
(29)
(139)
—
11,535
(594)
Investment in unconsolidated entities, December 31, 2007
$ 70,237
$ 1,582
$ 3,693
$ 178
$ 75,690
Select financial information for significant unconsolidated equity method investees is as follows:
2007
Waskom ...................................................................................
$ 66,772
$ —
$ 57,149
$ 81,797
$ 22,019
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) .............................................
$ 28,369
—
$ 28,369
$ —
$ 22,650
$ 9,165
$ 2,559
—
—
33,900
(120)
$ —
$ 22,650
$ 43,065
$ 2,439
As of December 31, 2007 and 2006, the Company’s interest in cash of the unconsolidated equity method
investees is $1,018 and $767, respectively.
(9)
LONG-TERM DEBT
At December 31, 2007 and December 31, 2006, long-term debt consisted of the following:
**$195,000 Revolving loan facility at variable interest rate (6.57%* weighted
average at December 31, 2007), due November 2010 secured by
substantially all of our assets, including, without limitation, inventory,
accounts receivable, vessels, equipment, fixed assets and the interests in
our operating subsidiaries and equity method investees .................................. $ 95,000
$ 44,000
December 31,
2007
December 31,
2006
11
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
***$130,000 Term loan facility at variable interest rate (6.99%* at December
31, 2007), due November 2010, secured by substantially all of our assets,
including, without limitation, inventory, accounts receivable, vessels,
equipment, fixed assets and the interests in our operating subsidiaries and
equity method investees ..................................................................................
Other secured debt maturing in 2008, 7.25%
Total long-term debt
Less current installments
Long-term debt, net of current installments
130,000
130,000
21
225,021
21
$225,000
95
174,095
74
$174,021
*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 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 1.75%. Effective January 1, 2008, the applicable margin
for existing borrowings will increase to 2.00%. As a result of our leverage ratio test as of December 31, 2007,
effective April 1, 2008, the applicable margin for existing borrowings will remain at 2.00%. The Company incurs a
commitment fee on the unused portions of the credit facility.
** Effective September, 2007, the Company entered into a cash flow hedge that swaps $25,000 of floating rate to
fixed rate. The fixed rate cost is 4.605% plus the Company’s applicable LIBOR borrowing spread. The cash flow
hedge matures in September, 2010.
**Effective November, 2006, the Company 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 Company’s applicable LIBOR borrowing spread. The cash flow
hedge matures in December, 2009.
***The $130,000 term loan has $105,000 hedged. Effective March, 2006, the Company 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 Company’s applicable
LIBOR borrowing spread. The cash flow hedge matures in November, 2010. Effective November 2006, the
Company entered into an additional interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed
rate cost is 4.765% plus the Company’s applicable LIBOR borrowing spread. This cash flow hedge matures in
March, 2010.
On August 18, 2006, the Company purchased certain terminalling assets and assumed associated long term
debt of $113 with a fixed rate cost of 7.25%.
On November 10, 2005, the Company 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
Company increased its revolving credit facility $25,000 resulting in a committed $120,000 revolving credit facility.
Effective December 28, 2007, the Company increased its revolving credit facility $75,000 resulting in a committed
$195,000 revolving credit facility. The revolving credit facility is used for ongoing working capital needs and
general Company purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the
amended and restated credit facility, as of December 31, 2007, the Company had $95,000 outstanding under the
revolving credit facility and $130,000 outstanding under the term loan facility. As of December 31, 2007, the
Company had $99,880 available under its revolving credit facility.
On July 14, 2005, the Company issued a $120 irrevocable letter of credit to the Texas Commission on
Environmental Quality to provide financial assurance for its used oil handling program.
12
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
The Company’s obligations under the credit facility are secured by substantially all of the Company’s
assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the
interests in its operating subsidiaries and equity method investees. The Company 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 Company’s
ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless it is the survivor; (iv) sell
all or substantially all of its assets; (v) make certain acquisitions; (vi) make certain investments; (vii) make certain
capital expenditures; (viii) make distributions other than from available cash; (ix) create obligations for some lease
payments; (x) engage in transactions with affiliates; (xi) engage in other types of business; and (xii) its joint ventures
to incur indebtedness or grant certain liens.
The credit facility also contains covenants, which, among other things, require the Company 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 Company was in compliance with the debt covenants contained in credit facility for the
years ended December 31, 2007 and 2006.
On November 10 of each year, commencing with November 10, 2006, the Company 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. There were no prepayments made or required under the term
loan through December 31, 2007. If the Company 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 Company must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of
its equity. The Company 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 Company’s credit facility are normally made to fund acquisitions and for working
capital requirements. During the current fiscal year, draws on the Company’s credit facility have ranged from a low
of $170,600 to a high of $239,400. As of December 31, 2007, the Company had $99,880 available for working
capital, internal expansion and acquisition activities under the Company’s credit facility.
On July 15, 2005, the Company assumed $9,400 of U.S. Government Guaranteed Ship Financing Bonds,
maturing in 2021, relating to the acquisition of CF Martin Sulphur L.P. (“CF Martin Sulphur”). The outstanding
balance as of December 31, 2005 was $9,104. These bonds were payable in equal semi-annual installments of $291,
and were secured by certain marine vessels owned by CF Martin Sulphur. Pursuant to the terms of an amendment to
the Company’s credit facility that it entered into in connection with the acquisition of CF Martin Sulphur, the
Company was obligated to repay these bonds by March 31, 2006. The Company redeemed these bonds on March 6,
2006 with available cash and borrowings from its credit facility. Also, at redemption, a pre-payment premium was
paid in the amount of $1,160.
In connection with the Company’s Monarch acquisition on October 2, 2007, the Company borrowed
approximately $3,900 under its revolving credit facility.
In connection with the Company’s Mega Lubricants acquisition on June 13, 2007, the Company borrowed
approximately $4,600 under its revolving credit facility.
13
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
In connection with the Company’s Woodlawn acquisition on May 2, 2007, the Company borrowed
approximately $33,000 under its revolving credit facility.
(10)
INTEREST RATE CASH FLOW HEDGES
In September 2007, the Company entered into a cash flow hedge agreement with a notional amount of
$25,000 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 September 2010. The Company designated this swap agreement as a cash
flow hedge. Under the swap agreement, the Company pays a fixed rate of interest of 4.605% 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 April, 2006, the Company 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 Company designated this swap agreement as a cash flow
hedge. Under the swap agreement, the Company pays a fixed rate of interest of 5.25% 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 Company 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 Company designated this swap agreement as a cash
flow hedge. Under the swap agreement, the Company 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 Company 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 Company’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, hedge accounting was not utilized. The swap has been recorded at fair value at December 31, 2006 with
an offset to current operations.
The total fair value of the interest rate swaps agreement was a liability of approximately $4,677 at
December 31, 2007.
The fair value of derivative liabilities is as follows:
Fair value of derivative liabilities — current ........................................
Fair value of derivative liabilities — long term ...................................
Net fair value of derivatives .................................................................
December 31,
2007
$ (1,241)
(3,436)
$ (4,677)
14
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
(11) COMMODITY CASH FLOW HEDGES
The Company is exposed to market risks associated with commodity prices, counterparty credit and interest
rates. However, in connection with the acquisition of Prism Gas, the Company 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 Company is focusing on utilizing counterparties for these transactions whose financial
condition is appropriate for the credit risk involved in each specific transaction.
The Company uses derivatives to manage the risk of commodity price fluctuations. Additionally, the
Company 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 Company
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, 2007, the Company 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 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,
2007
2006
$ 235
—
(3,261)
(2,140)
$ (5,166)
$ 882
221
—
(74)
$1,029
Set forth below is the summarized notional amount and terms of all instruments held for price risk
management purposes at December 31, 2007 (all gas quantities are expressed in British Thermal Units, crude oil and
natural gas liquids are expressed in barrels). As of December 31, 2007, the remaining term of the contracts extend
no later than December 2010, with no single contract longer than one year. The Company’s counterparties to the
derivative contracts include Shell Energy North America (US) L.P., Morgan Stanley Capital Group Inc. and
Wachovia Bank. For the period ended December 31, 2007, changes in the fair value of the Company’s derivative
contracts were recorded in both earnings and in other comprehensive income as a component of equity since the
Company has designated a portion of its derivative instruments as hedges as of December 31, 2007.
Transaction Type
Total
Volume
Per Month
Mark to Market Derivatives::
December 31, 2007
Pricing Terms
Remaining Terms
of Contracts
Fair Value
Natural Gas swap
Fixed price of $8.12 settled against
30,000
MMBTU
Houston Ship Channel first of the month
15
January 2008 to
December 2008
235
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
Crude Oil Swap
3,000 BBL Fixed price of $70.75 settled against WTI
NYMEX average monthly closings
Crude Oil Swap
3,000 BBL Fixed price of $69.08 settled against WTI
NYMEX average monthly closings
Crude Oil Swap
3,000 BBL Fixed price of $70.90 settled against WTI
NYMEX average monthly closings
Total swaps not designated as cash flow hedges
Cash Flow
Hedges:
Crude Oil Swap
5,000 BBL
Fixed price of $66.20 settled against WTI
NYMEX average monthly closings
Ethane Swap
5,000 BBL
Fixed price of $27.30 settled against Mt.
Belvieu Purity Ethane average monthly
postings
January 2008 to
December 2008
January 2009 to
December 2009
January 2009 to
December 2009
January 2008 to
December 2008
January 2008 to
December 2008
Iso butane Swap
1,000 BBL
Fixed price of $75.90 settled against Mt.
Belvieu Non-TET Iso butane average
monthly postings
January 2008 to March
2008
Normal Butane
Swap
2,000 BBL
Fixed price of $75.06 settled against Mt.
Belvieu Non-TET normal butane average
monthly postings
January 2008 to March
2008
Natural Gasoline
Swap
3,000 BBL
Fixed price of $87.31 (Jan-Mar) and
$85.10 (Apr-June) settled against Mt.
Belvieu Non-TET natural gasoline
average monthly postings.
January 2008 to June
2008
Crude Oil Swap
1,000 BBL
Fixed price of $70.45 settled against WTI
NYMEX average monthly closings
Crude Oil Swap
2,000 BBL
Fixed price of $69.15 settled against WTI
NYMEX average monthly closings
Crude Oil Swap
3,000 BBL
Fixed price of $72.25 settled against WTI
NYMEX average monthly closings
January 2009 to
December 2009
January 2010 to
December 2010
January 2010 to
December 2010
Total swaps designated as cash flow hedges
Total net fair value of derivatives
(810)
(628)
(569)
$ (1,772)
(1,612)
(773)
(9)
(19)
(38)
(194)
(337)
(412)
$ (3,394)
$ (5,166)
On all transactions where the Company is exposed to counterparty risk, the Company 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
Company has incurred no losses associated with the counterparty non-performance on derivative contracts.
As a result of the Prism Gas acquisition, the Company 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 2010 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, ethane, iso butane, normal butane and natural gasoline.
16
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
Based on estimated volumes, as of December 31, 2007, Prism Gas had hedged approximately 77%, 24%,
and 17% of its commodity risk by volume for 2008, 2009, and 2010, respectively. The Company 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 Company will be able to do so or that the terms thereof
will be similar to the Company’s existing hedging arrangements. In addition, the Company will consider derivative
arrangements that include the specific NGL products as well as natural gas and crude oil.
Hedging Arrangements in Place
As of December 31, 2007
Commodity Hedged
Condensate & Natural Gasoline
Year
2008
2008 Natural Gas
2008 Ethane
2008 Natural Gasoline
2008 Iso Butane
2008 Normal Butane
2008 Natural Gasoline
2008 Natural Gasoline
2009 Condensate & Natural Gasoline
2009 Natural Gasoline
2009
Condensate
2010 Condensate
2010 Natural Gasoline
Type of Derivative
Crude Oil Swap ($66.20)
Volume
5,000 BBL/Month
30,000 MMBTU/Month Natural Gas Swap ($8.12)
5,000 BBL/Month
3,000 BBL/Month
1,000 BBL/Month
2,000 BBL/Month
3,000 BBL/Month
3,000 BBL/Month
3,000 BBL/Month
3,000 BBL/Month
1,000 BBL/Month
2,000 BBL/Month
3,000 BBL/Month
Basis Reference
NYMEX
Houston Ship Channel
Mt. Belvieu
Ethane Swap ($27.30)
NYMEX
Crude Oil Swap ($70.75)
Mt. Belvieu (Non-TET)
Iso Butane Swap ($75.90)
Mt. Belvieu (Non-TET)
Normal Butane Swap ($75.06)
Natural Gasoline Swap ($87.31)
Mt. Belvieu (Non-TET)
Natural Gasoline Swap ($85.10) Mt. Belvieu (Non-TET)
Crude Oil Swap ($69.08)
Crude Oil Swap ($70.90)
Crude Oil Swap ($70.45)
Crude Oil Swap ($69.15)
Crude Oil Swap ($72.25)
NYMEX
NYMEX
NYMEX
NYMEX
NYMEX
The Company’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 Company’s natural gas and NGL sales are made at market-based prices. The Company’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 Company.
(12)
Public Equity Offering
In May 2007, the Company completed a public offering of 1,380,000 common units at a price of $42.25 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 64.3% limited partnership
interest in the Company. Total proceeds from the sale of the 1,380,000 common units, net of underwriters’
discounts, commissions and offering expenses were $55,933. The General Partner contributed $1,190 in cash to the
Company in conjunction with the issuance in order to maintain its 2% general partner interest in the Company. The
net proceeds were used to pay down revolving debt under the Company’s credit facility and to 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 .................................................................................
Total proceeds received .................................................................................
$ 58,305
1,190
$ 59,495
17
MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED BALANCE SHEETS
Use of Proceeds:
Underwriter’s fees ................................................................................................
Professional fees and other costs ..........................................................................
Repayment of debt under revolving credit facility ...............................................
Working capital ....................................................................................................
Total use of proceeds .....................................................................................
$ 2,107
265
55,850
1,273
$ 59,495
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 to 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 .................................................................................
Total proceeds received .................................................................................
$100,464
2,050
$102,514
Use of Proceeds:
Underwriter’s fees ................................................................................................
Professional fees and other costs ..........................................................................
Repayment of debt under revolving credit facility ...............................................
Working capital ....................................................................................................
Total use of proceeds .....................................................................................
$ 4,521
671
62,000
35,322
$102,514
(13) COMMITMENTS AND CONTINGENCIES
From time to time, the Company 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 Company.
In addition to the foregoing, as a result of a routine inspection by the U.S. Coast Guard of our tug Martin
Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, we have been informed that an investigation has
been commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq.,
and the MARPOL Protocol 73/78. In connection with this matter, two of our employees were served with grand jury
subpoenas during the fourth quarter of 2007. We are cooperating with the investigation and, as of the date of this
report, no formal charges, fines and/or penalties have been asserted against us.
18
Adjusted EBITDA Reconciliation (in thousands)
2003
2004
2005
2006
2007
Net income
$ 11,981
$ 12,326
$ 13,880
$ 22,243
$ 24,939
Adjustments to reconcile net income to adjusted EBITDA:
Interest expense
Debt prepayment premium
Equity in earnings of unconsolidated entities
Depreciation and amortization
EBITDA
Distributions in-kind from equity investments
Distributions from unconsolidated entities
Return of investments from unconsolidated entities
Non-cash derivatives (gain) loss
(Gain) Loss on disposition or sale of property, plant and equipment
2,001
3,326
6,909
12,466
14,533
—
(2,801)
4,765
—
—
1,160
—
(912)
(1,591)
(8,547)
(10,941)
8,766
12,642
17,597
23,442
$ 15,946
$ 23,506
$ 31,840
$ 44,919
$ 51,973
—
3,564
—
—
(3)
—
—
1,980
—
48
—
1,115
8,311
231
466
(555)
(37)
—
541
433
(389)
(231)
(3,125)
9,337
1,523
1,952
3,904
(703)
—
(Gain) Loss on involuntary conversion of property, plant and equipment
(589)
Adjusted EBITDA
$ 18,918
$ 25,534
$ 33,060
$ 50,459
$ 67,986
Distributable Cash Flow Reconciliation (in thousands)
Net income
$ 11,981
$ 12,326
$ 13,880
$ 22,243
$ 24,939
Adjustments to reconcile net income to distributable cash flow:
Depreciation and amortization
Amortization of deferred debt issue costs
Deferred income taxes
Distribution equivalents from unconsolidated entities
Invested cash in unconsolidated entities
4,765
8,766
12,642
17,597
23,442
486
—
886
—
3,564
1,980
—
—
600
—
1,812
(322)
1,040
—
9,285
767
1,233
(149)
12,812
1,338
Equity in earnings of unconsolidated entities
(2,801)
(912)
(1,591)
(8,547)
(10,941)
Non-cash derivatives (gain) loss
—
—
(555)
(389)
3,904
Maintenance capital expenditures, excluding hurricane-related items
(2,773)
(5,182)
(5,100)
(7,732)
(10,342)
(Gain) Loss on disposition or sale of property, plant and equipment
—
(Gain) Loss on involuntary conversion of property, plant and equipment
(589)
—
—
—
—
—
162
—
—
(291)
—
—
58
—
(703)
(3,125)
—
1,160
—
(159)
—
—
—
—
46
—
—
744
—
$ 15,377
$ 18,026
$ 21,133
$ 32,140
$ 45,579
Repayment of debt
Debt prepayment premium
Insurance proceeds
Other
Distributable Cash Flow
Principal Officers
Martin Midstream GP LLC
Board of Directors
Martin Midstream GP LLC
Corporate Offices
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
Wesley M. Skelton
Executive Vice President
Chief Administrative Officer
Scott D. Martin
Executive Vice President
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Ruben S. Martin
President
Chief Executive Officer
Martin Midstream GP LLC
Scott D. Martin
Executive Vice President
Martin Midstream GP LLC
John R. Gaylord
President
Jacintoport Terminal Company
Howard R. Hackney
Director
Texas Bank & Trust
Federal Home Loan Bank of Dallas
C. Scott Massey
CPA
C. Scott Massey, CPA LLC
Manager
Sandstone Ventures LLC
4200 Stone Road
Kilgore, Texas 75662
(903) 983-6200
Transfer Agent
BNY Mellon Shareowner Services
480 Washington Boulevard
Jersey City, New Jersey 07310
(800) 301-0911
www.bnymellon.com/shareowner/isd
Auditors
KPMG LLP
333 Texas Street
Suite 1900
Shreveport, Louisiana 71101
Units Traded
NASDAQ Global Select Market
Symbol: MMLP
Investor Information
Updated investor information on the
Company is available on our website
www.martinmidstream.com. Inquiries can
also be sent to info@martinmidstream.com.
4200 Stone Road
Kilgore, Texas 75662
903-983-6200
www.martinmidstream.com